<PAGE>

    As filed with the Securities and Exchange Commission on October 18, 2006

                                                  Registration Number 333-

                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                   ----------

                                    FORM S-1
             REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

                                   ----------

                      ATLAS AMERICA PUBLIC #16-2007 PROGRAM
             (Exact name of Registrant as Specified in its Charter)

                                    DELAWARE
         (State or other jurisdiction of incorporation or organization)

                                   ----------

                                      1311
            (Primary Standard Industrial Classification Code Number)

                                   ----------

                                 NOT APPLICABLE
                      (IRS Employer Identification Number)

                                   ----------

                                 311 ROUSER ROAD
                        MOON TOWNSHIP, PENNSYLVANIA 15108
                                 (412) 262-2830
               (Address, including zip code, and telephone number,
        including area code, of registrant's principal executive offices)

                                   ----------

    JACK L. HOLLANDER, SENIOR VICE PRESIDENT - DIRECT PARTICIPATION PROGRAMS
                              ATLAS RESOURCES, LLC
               311 ROUSER ROAD, MOON TOWNSHIP, PENNSYLVANIA 15108
                                 (412) 262-2830
                (Name, address, including zip code, and telephone
               number, including area code, of agent for service)

                                   ----------

                                 With a Copy to:
                          WALLACE W. KUNZMAN, JR., ESQ.
                            KUNZMAN & BOLLINGER, INC.
                                5100 N. BROOKLINE
                                    SUITE 600
                          OKLAHOMA CITY, OKLAHOMA 73112

                                   ----------

   AS SOON AS PRACTICABLE AFTER THIS REGISTRATION STATEMENT BECOMES EFFECTIVE.
        (Approximate Date of Commencement of Proposed Sale to the Public)

     If any of the securities being registered on this form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, check the following box: [X]

     If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [_]

     If this Form is a post-effective amendment filed pursuant to rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]

     If this Form is a post-effective amendment filed pursuant to rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]

                                   ----------

<PAGE>

                         CALCULATION OF REGISTRATION FEE

<TABLE>
<CAPTION>
Title of Each                               Unit             Dollar      Proposed Maximum   Proposed Maximum
Class of Securities                        Amounts       Amounts to be       Offering           Aggregate          Amount of
to be Registered                      to be Registered     Registered     Price per Unit     Offering Price    Registration Fee
-----------------------------------   ----------------   -------------   ----------------   -----------------------------------
<S>                                        <C>           <C>                 <C>              <C>                 <C>
Investor General Partner Units (1)         19,900        $199,000,000        $10,000          $199,000,000        $21,293.00
Converted Limited Partner Units (2)        19,900                 -0-            -0-                   -0-               -0-
Limited Partner Units (2)                     100        $  1,000,000        $10,000          $  1,000,000        $   107.00
                                           ------        ------------        -------          ------------        ----------
TOTAL                                      20,000        $200,000,000                         $200,000,000        $21,400.00
                                           ======        ============                         ============        ==========
</TABLE>

(1)  "Investor General Partner Units" means the investor general partner
     interests offered to participants in the program.-

(2)  "Limited Partner Units" means up to 100 initial limited partner interests
     offered to participants in the program and up to 19,900 limited partner
     units into which the investor general partner units automatically will be
     converted by the managing general partner with no additional price paid by
     the investor.

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATES AS MAY BE
NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER
AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL
THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES
ACT OF 1933 OR UNTIL THIS REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH
DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE.

<PAGE>

                      ATLAS AMERICA PUBLIC #16-2007 PROGRAM
                              CROSS REFERENCE SHEET

<TABLE>
<CAPTION>
                  Item of Form S-1                                     Caption in Prospectus
                  ----------------                                     ---------------------
<S>      <C>                                           <C>
Item 1.  Forepart of the Registration Statement and
         Outside Front Cover Page of Prospectus.....   Front Page of Registration Statement and Outside
                                                       Front Cover Page of Prospectus

Item 2.  Inside Front and Outside Back Cover Pages
         of Prospectus..............................   Inside Front and Outside Back Cover Pages of
                                                       Prospectus

Item 3.  Summary Information, Risk Factors and Ratio
         Of Earnings to Fixed Charges...............   Summary of the Offering; Risk Factors

Item 4.  Use of Proceeds............................   Capitalization and Source of Funds and Use of
                                                       Proceeds

Item 5.  Determination of Offering Price............   Terms of the Offering

Item 6.  Dilution...................................   The managing general partner's officers, directors,
                                                       promoters and affiliated persons have not acquired
                                                       any units during the past five years. Also, no units
                                                       will be issued in this offering to the managing
                                                       general partner except units subscribed for by the
                                                       managing general partner, which it does not
                                                       anticipate. Discounted units, if any, are described
                                                       in "Plan of Distribution."

Item 7.  Selling Security Holders...................   The program does not have any selling security
                                                       holders.

Item 8.  Plan of Distribution.......................   Plan of Distribution

Item 9.  Description of Securities to be
         Registered.................................   Summary of the Offering; Terms of the Offering;
                                                       Summary of Partnership Agreement

Item 10. Interests of Named Experts and Counsel.....   Legal Opinions; Experts

Item 11. Information with respect to the Registrant

         (a) Description of Business................   Proposed Activities; Management

         (b) Description of Property................   Proposed Activities

         (c) Legal Proceedings......................   Litigation

         (d) Market Price of and Dividends on the
             Registrant's Common Equity and
             Related Stockholder Matters............   The partnerships composing the program have no
                                                       markets in which their units are being traded and
                                                       they have not yet conducted activities or paid any
                                                       dividends.

         (e) Financial Statements...................   Financial Information Concerning the Managing General
                                                       Partner and Atlas America Public #16-2007(A) L.P.

         (f) Selected Financial Data................   All of the partnerships composing the program have
                                                       been formed, but the partnerships have not conducted
                                                       any activities. Thus, the program does not have this
                                                       information for the partnerships.

         (g) Supplementary Financial Information....   All of the partnerships composing the program have
                                                       been formed, but the partnerships have not conducted
                                                       any activities. Thus, the program does not have this
                                                       information for the partnerships.

         (h) Management's Discussion and Analysis of
             Financial Condition and Results of
             Operations.............................   Management's Discussion and Analysis of Financial
                                                       Condition, Results of Operations, Liquidity and
                                                       Capital Resources
</TABLE>

<PAGE>

<TABLE>
<CAPTION>
                  Item of Form S-1                                     Caption in Prospectus
                  ----------------                                     ---------------------
<S>                                                    <C>
         (i) Changes in and Disagreements with
             Accountants on Accounting and
             Financial Disclosure...................   There have been no changes in and disagreements with
                                                       accountants on accounting and financial disclosure.

         (j) Quantitative and Qualitative
             Disclosures about Market Risk..........   The partnerships have no market for their units and
                                                       none will be created.

         (k) Directors and Executive Officers.......   Management

         (l) Executive Compensation.................   Management

         (m) Security Ownership of Certain
             Beneficial Owners and Management.......   Management

         (n) Certain Relationships and Related
             Transactions...........................   Compensation; Management; Conflicts of Interest

Item 12. Disclosure of Commission Position on
         Indemnification for Securities Act
         Liabilities................................   Fiduciary Responsibilities of the Managing General
                                                       Partner
</TABLE>

----------

<PAGE>

********************************************************************************
The information in this prospectus is not complete and may be changed. We may
not sell these securities until the registration statement filed with the
Securities and Exchange Commission is effective. This prospectus is not an offer
to sell these securities and it is not soliciting an offer to buy these
securities in any state where the offer or sale is not permitted.
********************************************************************************

                  PRELIMINARY PROSPECTUS DATED OCTOBER 18, 2006

                      ATLAS AMERICA PUBLIC #16-2007 PROGRAM

    Up to 19,900 Investor General Partner Units and 19,900 converted Limited
    Partner Units and up to 100 Limited Partner Units, which are collectively
                 referred to as the "Units," at $10,000 per Unit
             $2 Million (200 Units) Minimum Aggregate Subscriptions
           $200 Million (20,000 Units) Maximum Aggregate Subscriptions

Atlas America Public #16-2007 Program is a series of up to two limited
partnerships which will drill primarily natural gas development wells. See
"Terms of the Offering - Subscription to a Partnership," beginning on page 8,
for a detailed description of the offering of these limited partnerships. The
limited partnerships will be managed by Atlas Resources, LLC of Pittsburgh,
Pennsylvania.

If you invest in a partnership, you will not have any interest in the other
partnership unless you also make a separate investment in the other partnership.

The units will be offered on a "best efforts" "minimum-maximum" basis. This
means the broker/dealers must sell at least 200 units and receive subscription
proceeds of at least $2 million in order for a partnership to close, and they
must use only their best efforts to sell the remaining units in the partnership.

Subscription proceeds for each partnership will be held in an interest bearing
escrow account until $2 million has been received. The offering of Atlas America
Public #16-2007(A) L.P. and Atlas America Public #16-2007(B) L.P. will not
extend beyond December 31, 2007. If the minimum subscription proceeds are not
received by a partnership's offering termination date, then your subscription
will be promptly returned to you from the escrow account with interest and
without deduction for any fees.

The Offering: In addition to the information in the table below for not less
than 95% of the units (19,000 units), up to 5% of the units (1,000 units), in
the aggregate, may be sold at $8,950 per unit to the managing general partner,
its officers, directors and affiliates, and investors who buy units through the
officers and directors of the managing general partner; or at $9,300 per unit to
registered investment advisors and their clients, and selling agents and their
registered representatives and principals. These discounted prices reflect
certain fees, sales commissions and reimbursements which will not be paid for
these sales. (See "Plan of Distribution.") To the extent that units are sold at
discounted prices, a partnership's subscription proceeds will be reduced.

                                                          Total         Total
                                            Per Unit     Minimum     Maximum (2)
                                            --------   ----------   ------------
Public Price                                 $10,000   $2,000,000   $200,000,000
Dealer-manager fee, sales
   commissions and bona fide due
   diligence reimbursements (1)              $ 1,000   $  200,000   $ 20,000,000
Proceeds to partnership                      $10,000   $2,000,000   $200,000,000

----------
(1)  These fees, sales commissions and reimbursements will be paid by the
     managing general partner as a part of its capital contribution and not from
     subscription proceeds.

o    A partnership's drilling operations involve the possibility of a partial
     loss of your investment, which may be substantial, because a partnership
     may drill wells that are productive, but do not produce enough revenue to
     return the investment made, and from time to time dry holes.

o    A partnership's revenues are directly related to its ability to market the
     natural gas produced from the wells it drills and natural gas and oil
     prices, which are volatile and uncertain. If natural gas and oil prices
     decrease, then your investment return will decrease.

o    Unlimited joint and several liability for partnership obligations if you
     choose to invest as an investor general partner until you are converted to
     a limited partner.

o    Lack of liquidity or a market for the units, which makes it extremely
     difficult for you to sell your units.

o    Lack of conflict of interest resolution procedures.

o    Total reliance on the managing general partner and its affiliates.

o    Authorization of substantial fees to the managing general partner and its
     affiliates.

o    You and the managing general partner will share in costs disproportionately
     to your sharing of revenues.

o    Possible allocation of taxable income to you in excess of your cash
     distributions from your partnership.

o    No guaranty of cash distributions every month.

     THESE SECURITIES ARE SPECULATIVE AND ARE SUBJECT TO CERTAIN RISKS. YOU
     SHOULD PURCHASE THESE SECURITIES ONLY IF YOU CAN AFFORD A COMPLETE LOSS OF
     YOUR INVESTMENT. (SEE "RISK FACTORS," PAGE 8.)

     Neither the SEC nor any state securities commission has approved or
     disapproved of these securities or determined if this prospectus is
     truthful or complete. Any representation to the contrary is a criminal
     offense.

                    ANTHEM SECURITIES, INC. - DEALER-MANAGER

<PAGE>

                                TABLE OF CONTENTS

SUMMARY OF THE OFFERING...................................................     1
   Business of the Partnerships and the Managing General Partner..........     1
   Risk Factors...........................................................     1
   Terms of the Offering..................................................     3
   Description of Units...................................................     3
      Investor General Partner Units......................................     3
      Limited Partner Units...............................................     4
   Use of Proceeds........................................................     5
   Five Year-50% Subordination, Participation in Costs and Revenues, and
      Distributions.......................................................     5
   Compensation...........................................................     7

RISK FACTORS..............................................................     8
   Risks Related To The Partnerships' Oil and Gas Operations..............     8
      No Guarantee of Return of Investment or Rate of Return on Investment
         Because of Speculative Nature of Drilling Natural Gas and Oil
         Wells............................................................     8
      Because Some Wells May Not Return Their Drilling and Completion
         Costs, It May Take Many Years to Return Your Investment in Cash,
         If Ever..........................................................     8
      Nonproductive Wells May be Drilled Even Though the Partnerships'
         Operations are Primarily Limited to Development Drilling.........     8
      Partnership Distributions May be Reduced if There is a Decrease in
         the Price of Natural Gas and Oil.................................     8
      Adverse Events in Marketing a Partnership's Natural Gas Could Reduce
         Partnership Distributions........................................     9
      Possible Leasehold Defects..........................................    11
      Transfer of the Leases Will Not Be Made Until Well is Completed.....    11
      Participation with Third-Parties in Drilling Wells May Require the
         Partnerships to Pay Additional Costs.............................    11
   Risks Related to an Investment In a Partnership........................    12
      If You Choose to Invest as a General Partner, Then You Have Greater
         Risk Than a Limited Partner......................................    12
      The Managing General Partner May Not Meet Its Capital Contributions,
         Indemnification and Purchase Obligations If Its Liquid Net Worth
         Is Not Sufficient................................................    12
      An Investment in a Partnership Must be for the Long-Term Because the
         Units Are Illiquid and Not Readily Transferable..................    13
      Spreading the Risks of Drilling Among a Number of Wells Will be
         Reduced if Less than the Maximum Subscription Proceeds are
         Received and Fewer Wells are Drilled.............................    13
      Increases in the Costs of the Wells May Adversely Affect Your
         Return...........................................................    14
      The Partnerships Do Not Own Any Prospects, the Managing General
         Partner Has Complete Discretion to Select Which Prospects Are
         Acquired By a Partnership, and The Possible Lack of Information
         for a Majority of the Prospects Decreases Your Ability to
         Evaluate the Feasibility of a Partnership........................    14
      Drilling Prospects in One Area May Increase Risk....................    14
      Lack of Production Information Increases Your Risk and Decreases
         Your Ability to Evaluate the Feasibility of a Partnership's
         Drilling Program.................................................    15
      The Partnerships in This Program and Other Partnerships Sponsored by
         the Managing General Partner May Compete With Each Other for
         Prospects, Equipment, Subcontractors, and Personnel..............    15
      Managing General Partner's Subordination is Not a Guarantee of the
         Return of Any of Your Investment.................................    15
      Borrowings by the Managing General Partner Could Reduce Funds
         Available for Its Subordination Obligation.......................    15
      Compensation and Fees to the Managing General Partner Regardless of
         Success of a Partnership's Activities Will Reduce Cash
         Distributions....................................................    16
      The Intended Monthly Distributions to Investors May be Reduced or
         Delayed..........................................................    16
      There Are Conflicts of Interest Between the Managing General Partner
         and the Investors................................................    16
      The Presentment Obligation May Not Be Funded and the Presentment
         Price May Not Reflect Full Value.................................    17
      The Managing General Partner May Not Devote the Necessary Time to
         the Partnerships Because Its Management Obligations Are Not
         Exclusive........................................................    18
      Prepaying Subscription Proceeds to the Managing General Partner May
         Expose the Subscription Proceeds to Claims of the Managing
         General Partner's Creditors......................................    18
      Lack of Independent Underwriter May Reduce Due Diligence
         Investigation of the Partnerships and the Managing General
         Partner..........................................................    18
      A Lengthy Offering Period May Result in Delays in the Investment of
         Your Subscription and Any Cash Distributions From the Partnership
         to You...........................................................    18
      Your Interests May Be Diluted.......................................    18
   Tax Risks..............................................................    19
      Your Deduction for Intangible Drilling Costs May Be Limited for
         Purposes of the Alternative Minimum Tax..........................    19
      Limited Partners Need Passive Income to Use Their Deduction for
         Intangible Drilling Costs........................................    19
      You May Owe Taxes in Excess of Your Cash Distributions from Your
         Partnership......................................................    19
      Investment Interest Deductions of Investor General Partners May Be
         Limited..........................................................    20
      Your Tax Benefits from an Investment in a Partnership Are Not
         Contractually Protected..........................................    20
      An IRS Audit of Your Partnership May Result in an IRS Audit of Your
         Personal Federal Income Tax Returns..............................    20
      Each Partnership's Deductions May be Challenged by the IRS..........    20
      Changes in the Law May Reduce Your Tax Benefits From an Investment
         in a Partnership.................................................    21
      It May Be Many Years Before You Receive Any Marginal Well Production
         Credits, If Ever.................................................    21

ADDITIONAL INFORMATION....................................................    21

FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS...........................    21

INVESTMENT OBJECTIVES.....................................................    22

ACTIONS TO BE TAKEN BY MANAGING GENERAL PARTNER TO REDUCE RISKS OF
   ADDITIONAL PAYMENTS BY INVESTOR GENERAL PARTNERS.......................    24

CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS....................    26


                                        i

<PAGE>

                                TABLE OF CONTENTS

   Source of Funds........................................................    26
   Use of Proceeds........................................................    26

COMPENSATION..............................................................    29
   Natural Gas and Oil Revenues...........................................    30
   Lease Costs............................................................    30
   Drilling Contracts.....................................................    31
   Per Well Charges.......................................................    33
   Gathering Fees.........................................................    34
   Dealer-Manager Fees....................................................    35
   Interest and Other Compensation........................................    35
   Estimate of Administrative Costs and Direct Costs to be Borne by the
      Partnerships........................................................    36

TERMS OF THE OFFERING.....................................................    37
   Subscription to a Partnership..........................................    37
   Partnership Closings and Escrow........................................    38
   Acceptance of Subscriptions............................................    38
   Suitability Standards..................................................    39
      In General..........................................................    39
      General Suitability Requirements for Purchasers of Limited Partner
         Units............................................................    39
      Special Suitability Requirements for Purchasers of Limited Partner
         Units............................................................    40
      General Suitability Requirements for Purchasers of Investor General
         Partner Units....................................................    41
      Special Suitability Requirements for Purchasers of Investor General
         Partner Units....................................................    42
      Fiduciary Accounts..................................................    44

PRIOR ACTIVITIES..........................................................    44

MANAGEMENT................................................................    55
   Managing General Partner and Operator..................................    55
   Officers, Directors and Other Key Personnel of Managing General
      Partner.............................................................    56
   Atlas America, Inc., a Delaware Company................................    59
   Organizational Diagrams and Security Ownership of Beneficial Owners....    60
   Atlas Energy Resources, LLC, a Delaware Limited Liability Company......    62
   Atlas Energy Management, Inc., a Delaware Company......................    63
   Remuneration of Officers and Directors.................................    63
   Code of Business Conduct and Ethics....................................    63
   Transactions with Management and Affiliates............................    63

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, RESULTS OF
   OPERATIONS, LIQUIDITY AND CAPITAL RESOURCES............................    63

PROPOSED ACTIVITIES.......................................................    65
   Overview of Drilling Activities........................................    65
   Primary Areas of Operations............................................    66
      Mississippian/Upper Devonian Sandstone Reservoirs, Fayette County,
         Pennsylvania.....................................................    67
      Clinton/Medina Geological Formation in Western Pennsylvania.........    68
      Mississippian Carbonate and Devonian Shale Reservoirs in Anderson,
         Campbell, Morgan, Roane and Scott Counties, Tennessee............    68
   Secondary Areas of Operations..........................................    69
      Upper Devonian Sandstone Reservoirs, Armstrong County,
         Pennsylvania.....................................................    69
      Upper Devonian Sandstone Reservoirs in McKean County, Pennsylvania..    70
      Clinton/Medina Geological Formation in Western New York.............    70
      Clinton/Medina Geological Formation in Southern Ohio................    70
   Acquisition of Leases..................................................    71
      Deep Drilling Rights Retained by Managing General Partner...........    72
   Interests of Parties...................................................    72
   Primary Areas..........................................................    73
      Clinton/Medina Geological Formation in Western Pennsylvania and
         Mississippian/Upper Devonian Sandstone Reservoirs in Fayette
         County, Pennsylvania.............................................    73
      Mississippian Carbonate and Devonian Shale Reservoirs in Anderson,
         Campbell, Morgan, Roane and Scott Counties, Tennessee............    74
   Secondary Areas........................................................    74
   Title to Properties....................................................    74
   Drilling and Completion Activities; Operation of Producing Wells.......    75
   Sale of Natural Gas and Oil Production.................................    76
      Policy of Treating All Wells Equally in a Geographic Area...........    76
      Gathering of Natural Gas............................................    76
      Natural Gas Contracts...............................................    77
   Marketing of Natural Gas Production from Wells in Other Areas of the
      United States.......................................................    79
   Crude Oil..............................................................    79
   Insurance..............................................................    79
   Use of Consultants and Subcontractors..................................    80

COMPETITION, MARKETS AND REGULATION.......................................    80
   Natural Gas Regulation.................................................    80
   Crude Oil Regulation...................................................    80
   Competition and Markets................................................    80
   State Regulations......................................................    83
   Environmental Regulation...............................................    83
   Proposed Regulation....................................................    84

PARTICIPATION IN COSTS AND REVENUES.......................................    84
   In General.............................................................    84
   Costs..................................................................    85
   Revenues...............................................................    87
   Subordination of Portion of Managing General Partner's Net Revenue
      Share...............................................................    87
   Table of Participation in Costs and Revenues...........................    89
   Allocation and Adjustment Among Investors..............................    90
   Distributions..........................................................    90
   Liquidation............................................................    91

CONFLICTS OF INTEREST.....................................................    91
   In General.............................................................    91
   Conflicts Regarding Transactions with the Managing General Partner and
      its Affiliates......................................................    92
   Conflict Regarding the Drilling and Operating Agreement................    93
   Conflicts Regarding Sharing of Costs and Revenues......................    93
   Conflicts Regarding Tax Matters Partner................................    93
   Conflicts Regarding Other Activities of the Managing General Partner,
      the Operator and Their Affiliates...................................    94
   Conflicts Involving the Acquisition of Leases..........................    94
   Conflicts Regarding Order of Pipeline Construction and Gathering Fees..    98
   Conflicts Between Investors and the Managing General Partner as an
      Investor............................................................    99
   Lack of Independent Underwriter and Due Diligence Investigation........    99
   Conflicts Concerning Legal Counsel.....................................   100
   Conflicts Regarding Presentment Feature................................   100


                                       ii

<PAGE>

                                TABLE OF CONTENTS

   Conflicts Regarding Managing General Partner Withdrawing or Assigning
      an Interest.........................................................   100
   Procedures to Reduce Conflicts of Interest.............................   100
   Policy Regarding Roll-Ups..............................................   102

FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER..................   103
   In General.............................................................   103
   Limitations on Managing General Partner Liability as Fiduciary.........   104

FEDERAL INCOME TAX CONSEQUENCES...........................................   104
   Introduction...........................................................   104
   Disclosures in Tax Opinion Letter......................................   105
   Special Counsel's Assumptions..........................................   105
   Managing General Partner's Representations.............................   105
   Special Counsel's Opinions.............................................   106
   Discussion of Federal Income Tax Consequences..........................   109
   Introduction...........................................................   109
   Partnership Classification.............................................   109
   Limitations on Passive Activity Losses and Credits.....................   109
   Publicly Traded Partnership Rules......................................   112
   Conversion from Investor General Partner to Limited Partner............   112
   Taxable Year and Method of Accounting..................................   112
      Taxable Year.......................................................    112
      Method of Accounting...............................................    112
   Business Expenses......................................................   113
   Intangible Drilling Costs..............................................   113
   Drilling Contracts.....................................................   114
   Depletion Allowance....................................................   117
   Depreciation and Cost Recovery Deductions..............................   118
   Marginal Well Production Credits.......................................   119
   Lease Acquisition Costs and Abandonment................................   119
   Tax Basis of Units.....................................................   120
   "At Risk" Limitation on Losses.........................................   120
   Distributions From a Partnership.......................................   121
   Sale of the Properties.................................................   121
   Disposition of Units...................................................   123
   Alternative Minimum Tax................................................   124
   Limitations on Deduction of Investment Interest........................   126
   Allocations............................................................   126
   Partnership Borrowings.................................................   128
   Partnership Organization and Offering Costs............................   128
   Tax Elections..........................................................   128
   Tax Returns and IRS Audits.............................................   130
      Tax Returns........................................................    130
   Profit Motive, IRS Anti-Abuse Rule and Judicial Doctrines Limitations
      on Deductions.......................................................   130
   Federal Interest and Tax Penalties.....................................   131
   State and Local Taxes..................................................   133
   Severance and Ad Valorem (Real Estate) Taxes...........................   133
   Social Security Benefits and Self-Employment Tax.......................   133
   Farmouts...............................................................   134
   Foreign Partners.......................................................   134
   Estate and Gift Taxation...............................................   134
   Changes in the Law.....................................................   134

SUMMARY OF PARTNERSHIP AGREEMENT..........................................   135
   Liability of Limited Partners..........................................   135
   Amendments.............................................................   135
   Notice.................................................................   135
   Voting Rights..........................................................   135
   Access to Records......................................................   136
   Withdrawal of Managing General Partner.................................   136
   Return of Subscription Proceeds if Funds Are Not Invested in Twelve
      Months..............................................................   137

SUMMARY OF DRILLING AND OPERATING AGREEMENT...............................   137

REPORTS TO INVESTORS......................................................   138

PRESENTMENT FEATURE.......................................................   139

TRANSFERABILITY OF UNITS..................................................   141
   Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws
      and the Partnership Agreement.......................................   141
   Conditions to Becoming a Substitute Partner............................   141

PLAN OF DISTRIBUTION......................................................   142
   Commissions............................................................   142
   Indemnification........................................................   144

SALES MATERIAL............................................................   144

LEGAL OPINIONS............................................................   145

EXPERTS...................................................................   145

LITIGATION................................................................   145

FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL PARTNER AND ATLAS
   AMERICA PUBLIC #16-2007(A) L.P.........................................   146

INDEX TO FINANCIAL STATEMENTS.............................................   146

Exhibits

Appendix A      Information Regarding Currently Proposed Prospects for Atlas
                America Public #16-2007(A) L.P.

Exhibit (A)     Form of Amended and Restated Certificate and Agreement of
                Limited Partnership for Atlas America Public #16-2007(A) L.P.
                [Form of Amended and Restated Certificate and Agreement of
                Limited Partnership for Atlas America Public #16-2007(B) L.P.]

Exhibit (I-A)   Form of Managing General Partner
                Signature Page

Exhibit (I-B)   Form of Subscription Agreement

Exhibit (II)    Form of Drilling and Operating Agreement for Atlas America
                Public #16-2007(A) L.P. [Atlas America Public #16-2007(B)
                L.P.]

Exhibit (B)     Special Suitability Requirements and Disclosures to Investors


                                       iii

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                             SUMMARY OF THE OFFERING

This is a summary and does not include all of the information that may be
important to you. You should read this entire prospectus and the attached
exhibits and appendix before you decide to invest in a partnership. Throughout
this prospectus when there is a reference to you it is a reference to you as a
potential investor or participant in a partnership.

BUSINESS OF THE PARTNERSHIPS AND THE MANAGING GENERAL PARTNER

Atlas America Public #16-2007 Program, which is sometimes referred to in this
prospectus as the "program," consists of up to two Delaware limited
partnerships. These limited partnerships are sometimes referred to in this
prospectus in the singular as a "partnership" or in the plural as the
"partnerships." Units in the two partnerships will be offered and sold in a
series beginning with the offering of units in the first partnership, Atlas
America Public #16-2007(A) L.P. See "Terms of the Offering" for a discussion of
the terms and conditions involved in making an investment in a partnership.

Each partnership in the program will be a separate business entity from the
other partnership. A limited partnership agreement will govern the rights and
obligations of the partners of each partnership. A form of the limited
partnership agreement is attached to this prospectus as Exhibit (A). For a
summary of the material provisions of the limited partnership agreement which
are not covered elsewhere in this prospectus see "Summary of Partnership
Agreement." You will be a partner only in the partnership in which you invest.
You will have no interest in the business, assets or tax benefits of the other
partnership unless you also invest in the other partnership. Thus, your
investment return will depend solely on the operations and success or lack of
success of the partnership in which you invest.

The offering proceeds of each partnership will be used to drill primarily
natural gas development wells in the Appalachian Basin. The wells to be drilled
by each partnership will be located primarily in western Pennsylvania and north
central Tennessee as described in "Proposed Activities." A development well
means a well drilled within the proved area of a natural gas or oil reservoir to
the depth of a stratigraphic horizon known to be productive. Currently, the
partnerships do not hold any interests in any properties or prospects on which
the wells will be drilled by each partnership.

The managing general partner of each partnership is Atlas Resources, LLC, a
Pennsylvania limited liability company, which was originally formed as a
corporation in 1979 and then changed to a limited liability company in March,
2006. The managing general partner is sometimes referred to in this prospectus
as "Atlas Resources." As set forth in "Prior Activities," the managing general
partner has sponsored and serves as managing general partner of 38 private
drilling partnerships and 16 public drilling partnerships. Atlas Resources also
will serve as each partnership's general drilling contractor and operator and it
will supervise the drilling, completing and operating of the wells to be drilled
by each partnership.

The address and telephone number of the partnerships and the managing general
partner are 311 Rouser Road, Moon Township, Pennsylvania 15108, (412) 262-2830.

RISK FACTORS

This offering involves numerous risks, including risks related to each
partnership's oil and gas operations, risks related to an investment in a
partnership, and tax risks. You should carefully consider a number of
significant risk factors inherent in and affecting the business of a partnership
and this offering, including the following.

     o    The drilling operations of the partnership in which you invest involve
          the possibility of a partial loss of your investment, which may be
          substantial, because each partnership may drill wells that are
          productive, but do not produce enough revenue to return the investment
          made, and from time to time dry holes.

     o    Each partnership's revenues are directly related to its ability to
          market the natural gas produced from the wells it drills and natural
          gas and oil prices, which are volatile and uncertain. If natural gas
          and oil prices decrease then your investment return will decrease.


                                       1

<PAGE>

     o    Unlimited joint and several liability for partnership obligations if
          you choose to invest as an investor general partner until you are
          converted to a limited partner.

     o    Lack of liquidity or a market for the units makes it extremely
          difficult for you to sell your units and necessitates a long-term
          investment commitment from you.

     o    Total reliance on the managing general partner and its affiliates to
          manage each partnership and its business.

     o    Authorization of substantial fees to the managing general partner and
          its affiliates.

     o    Possible allocation of taxable income to you and the other investors
          in excess of your respective cash distributions from a partnership.

     o    Each partnership must receive minimum subscription proceeds of $2
          million to close this offering, and the subscription proceeds of all
          partnerships, in the aggregate, may not exceed $200 million. There are
          no other requirements regarding the size of a partnership, and the
          subscription proceeds of one partnership may be substantially more or
          less than the subscription proceeds of the other partnership. If only
          the minimum subscription proceeds are received by a partnership, its
          ability to spread the risks of drilling will be greatly reduced as
          described in "Compensation - Drilling Contracts."

     o    There are certain conflicts of interest between the managing general
          partner and you and the other investors, and a lack of procedures to
          resolve the conflicts.

     o    You and the other investors and the managing general partner will
          share in a partnership's costs disproportionately to the sharing of
          its revenues.

     o    Currently, the partnerships do not hold any interests in any
          properties or prospects on which the wells will be drilled. Although
          the managing general partner has absolute discretion in determining
          which properties or prospects will be drilled by a partnership, the
          managing general partner intends that Atlas America Public #16-2007(A)
          L.P. will drill the prospects described in "Appendix A - Information
          Regarding Currently Proposed Prospects for Atlas America Public
          #16-2007(A) L.P." These prospects represent a portion of the wells to
          be drilled if the nonbinding targeted maximum subscription proceeds
          described in "Terms of the Offering - Subscription to a Partnership"
          are received. If there are material adverse events with respect to any
          of the currently proposed prospects before drilling begins on the
          prospect, the managing general partner will substitute a new prospect.
          The managing general partner also anticipates that it will designate a
          portion of the prospects in Atlas America Public #16-2007(B) L.P. by a
          supplement or an amendment to the registration statement of which this
          prospectus is a part.

     o    In each partnership the managing general partner may subordinate a
          portion of its share of that partnership's net production revenues to
          increase that partnership's distributions to you and the other
          investors. This subordination, however, is not a guaranty by the
          managing general partner of your distributions from that partnership.
          If the wells in that partnership produce small volumes of natural gas
          and oil and/or natural gas and oil prices decrease, then even with
          subordination your cash flow from the partnership may not return the
          intended distributions during the subordination period or, over the
          term of the partnership, all of your investment.

     o    In each partnership monthly cash distributions to its investors may be
          deferred if revenues are used for partnership operations or reserves.


                                       2

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TERMS OF THE OFFERING

The time period for the offer and sale of the first partnership's units will
begin on the date of this prospectus. Each partnership will offer a minimum of
200 units, which is $2 million, and the partnerships, in the aggregate, will
offer a maximum of 20,000 units which is $200 million. The maximum subscription
proceeds for each partnership will be the lesser of:

     o    the amount of $200 million; or

     o    $200 million less the amount of subscriptions sold in the preceding
          partnership.

The targeted subscription proceeds and closing date for each partnership, which
are not binding on the managing general partner, are set forth in a table in
"Terms of the Offering - Subscription to a Partnership."

Units are offered at a subscription price of $10,000 per unit, provided that up
to 5% of the units in each partnership in this offering may be sold to certain
investors at discounted prices as described in "Plan of Distribution." All
subscriptions must be paid 100% in cash at the time of subscribing. Your minimum
subscription in a partnership is one unit ($10,000). Larger fractional
subscriptions will be accepted in $1,000 increments, beginning, for example,
with $11,000, $12,000, etc.

You may elect to purchase units as either an investor general partner or a
limited partner as described in "- Description of Units," below. Under the
partnership agreement no investor, including investor general partners, may
participate in the management of a partnership or its business. The managing
general partner will have exclusive management authority for the partnerships.

Each partnership has been formed as a limited partnership under the Delaware
Revised Uniform Limited Partnership Act. Subscription proceeds for each
partnership will be held in a separate interest bearing escrow account at
National City Bank of Pennsylvania until receipt of the minimum subscription
proceeds, excluding any subscriptions by the managing general partner or its
affiliates. On receipt of the minimum subscription proceeds, the managing
general partner on behalf of a partnership may break escrow, transfer the
escrowed subscription proceeds to a partnership account, and begin the
partnership's activities, including drilling. After breaking escrow, additional
subscription proceeds may be paid directly to a partnership account for that
partnership and will continue to earn interest until the final closing date of
the offering of units in that partnership. (See "Terms of the Offering.") If
subscription proceeds of $2 million are not received by the offering termination
date for your partnership, then your subscription amount will be promptly
returned to you from the escrow account with interest and without deduction for
any fees.

DESCRIPTION OF UNITS

On subscribing for units in the partnership being offered at the time, you may
elect to buy either:

     o    investor general partner units; or

     o    limited partner units.

The partnerships will not issue certificates for their units, but your ownership
of your unit(s) will be recorded on the partnership's books and records. Also,
the type of unit you buy will not affect the allocation of your partnership's
costs, revenues, and cash distributions among you and its other investors. There
are, however, material differences in the federal income tax effects and
liability associated with each type of unit.

INVESTOR GENERAL PARTNER UNITS.

     o    TAX EFFECT. If you invest in a partnership as an investor general
          partner, then your share of the partnership's deduction for intangible
          drilling costs will not be subject to the passive activity limitations
          on losses. For example, if you pay $10,000 for a unit, then generally
          you may deduct not less than 90% of your subscription amount, $9,000
          per unit, in the year in which you invest, which includes your
          deduction for intangible drilling costs for all of the wells to be
          drilled by the


                                       3

<PAGE>

          partnership. (See "Federal Income Tax Consequences - Limitations on
          Passive Activity Losses and Credits.")

          o    Intangible drilling costs generally means those costs of drilling
               and completing a well that are currently deductible, as compared
               to lease costs which must be recovered through the depletion
               allowance and costs for equipment in the well which must be
               recovered through depreciation deductions.

     o    LIABILITY. If you invest in a partnership as an investor general
          partner, then you will have unlimited liability regarding the
          partnership's activities. This means that if:

          o    the partnership's insurance proceeds from any source;

          o    the managing general partner's indemnification of you and the
               other investor general partners; and

          o    the partnership's assets;

          were not sufficient to satisfy a partnership liability for which you
          and the other investor general partners were also liable solely
          because of your status as general partners of the partnership, then
          the managing general partner would require you and the other investor
          general partners to make additional capital contributions to the
          partnership to satisfy the liability. In addition, you and the other
          investor general partners will have joint and several liability, which
          means generally that a person with a claim against the partnership may
          sue all or any one or more of the partnership's general partners,
          including you, for the entire amount of the liability. (See "Actions
          To Be Taken By Managing General Partner To Reduce Risks of Additional
          Payments by Investor General Partners" and "Proposed Activities -
          Insurance.")

     Although past performance is no guarantee of future results, the investor
     general partners in the managing general partner's prior partnerships have
     not had to make any additional capital contributions to their partnerships
     because of their status as investor general partners. (See "Prior
     Activities.")

     Your investor general partner units in a partnership will be automatically
     converted by the managing general partner to limited partner units after
     all of that partnership's wells have been drilled and completed. The
     conversion will not create any tax liability to you or the other investors.

     Once your units are converted, you will have the lesser liability of a
     limited partner under Delaware law for partnership obligations and
     liabilities arising after the conversion. However, you will continue to
     have the responsibilities of a general partner for partnership liabilities
     and obligations incurred before the effective date of the conversion. For
     example, you might become liable for partnership liabilities in excess of
     your subscription amount during the time the partnership is engaged in
     drilling activities and for environmental claims that arose during drilling
     activities, but were not discovered until after the conversion.

LIMITED PARTNER UNITS.

     o    TAX EFFECT. If you invest in a partnership as a limited partner, then
          your use of your share of the partnership's deduction for intangible
          drilling costs will be limited to offsetting your net passive income
          from "passive" trade or business activities. Passive trade or business
          activities generally include the partnership and other limited partner
          investments, but passive income does not include salaries, dividends
          or interest. This means that you will not be able to deduct your share
          of the partnership's intangible drilling costs in the year in which
          you invest unless you have net passive income from investments other
          than the partnership. However, any portion of your share of the
          partnership's deduction for intangible drilling costs that you cannot
          use in the year in which you invest, because you do not have
          sufficient net


                                       4

<PAGE>

          passive income in that year, may be carried forward by you and used to
          offset your net passive income from the partnership or your other
          passive activities, if any, in subsequent tax years. (See "Federal
          Income Tax Consequences - Limitations on Passive Activity Losses and
          Credits.")

     o    LIABILITY. If you invest in a partnership as a limited partner, then
          you will have limited liability for the partnership's liabilities and
          obligations. This means that you will not be liable for any
          partnership liabilities or obligations beyond the amount of your
          initial investment in the partnership and your share of the
          partnership's undistributed net profits, subject to certain exceptions
          set forth in "Summary of Partnership Agreement - Liability of Limited
          Partners."

USE OF PROCEEDS

Each partnership must receive minimum subscription proceeds of $2 million to
close, and the subscription proceeds of both partnerships, in the aggregate, may
not exceed $200 million. The subscription proceeds of one partnership may be
substantially more or less than the subscription proceeds of the other
partnerships and the managing general partner has the discretion to accept
subscriptions for up to and including the entire amount in Atlas America Public
#16-2007(A) L.P. and not offer and sell any units in Atlas America Public
#16-2007(B) L.P. In each partnership, regardless of whether the partnership
receives the minimum or the maximum subscription proceeds from you and the other
investors:

     o    90% of the subscription proceeds will be used to pay 100% of the
          intangible drilling costs, as defined above in "- Description of
          Units," of drilling and completing the partnership's wells; and

     o    10% of the subscription proceeds will be used to pay a portion of the
          equipment costs of drilling and completing the partnership's wells.

The managing general partner will contribute all of the leases to each
partnership covering the acreage on which that partnership's wells will be
drilled and pay all of the equipment costs of drilling and completing the
partnership's wells that exceed 10% of the partnership's subscription proceeds.
Thus, the managing general partner will pay the majority of each partnership's
equipment costs. The managing general partner also will be charged with 100% of
the organization and offering costs for each partnership. A portion of these
contributions to each partnership will be in the form of payments to itself, its
affiliates and third-parties and the remainder will be in the form of services
related to organizing this offering. The managing general partner will receive a
credit towards its required capital contribution to each partnership for these
payments and services as discussed in "Participation in Costs and Revenues."
(See "Capitalization and Source of Funds and Use of Proceeds" and "Federal
Income Tax Consequences - Intangible Drilling Costs.")

FIVE YEAR-50% SUBORDINATION, PARTICIPATION IN COSTS AND REVENUES, AND
DISTRIBUTIONS

Each partnership will be a separate business entity from the other partnerships,
and you will be a partner only in the partnership in which you invest. You will
have no interest in the business, assets or tax benefits of the other
partnership unless you also invest in the other partnership. Thus, your
investment return will depend solely on the operations and success or lack of
success of the particular partnership in which you invest. Each partnership is
structured to provide you and its other investors with cash distributions equal
to a minimum of 10% of capital, based on a subscription price of $10,000 per
unit, regardless of the actual subscription price you paid for your units, in
each of the first five 12-month periods beginning with the partnership's first
cash distribution from operations. To help achieve this investment feature of a
10% return of capital in each of the first five 12-month periods, the managing
general partner will subordinate up to 50% of its share of partnership net
production revenues, which will be up to between 16% and 20% of total
partnership net production revenues, depending on the amount of the managing
general partner's capital contribution to that partnership, during this
subordination period. (See "Participation in Costs and Revenues - Subordination
of Portion of Managing General Partner's Net Revenue Share.")

Each partnership's 60-month subordination period will begin with the
partnership's first cash distribution from operations to you and its other
investors. Subordination distributions will be determined by debiting or
crediting current period partnership revenues to the managing general partner as
may be necessary to provide the distributions to you and the other investors. At
any time during the subordination period, but not after, the managing general
partner is entitled to an


                                       5

<PAGE>

additional share of partnership revenues to recoup previous subordination
distributions to the extent your cash distributions from the partnership exceed
the 10% return of capital described above. The specific formula for determining
subordination distributions is set forth in Section 5.01(b)(4)(a) of the
partnership agreement.

The following table sets forth how the partnership's costs and revenues will be
charged and credited between the managing general partner and you and the other
investors for each partnership after deducting from the partnership's gross
revenues the landowner royalties and any other lease burdens.

                                                       MANAGING
                                                        GENERAL
                                                        PARTNER   INVESTORS
                                                       --------   ---------
PARTNERSHIP COSTS
Organization and offering costs.....................     100%          0%
Lease costs.........................................     100%          0%
Intangible drilling costs (1).......................       0%        100%
Equipment costs.....................................      (2)         (2)
Operating costs, administrative costs, direct costs,
   and all other costs..............................      (3)         (3)

PARTNERSHIP REVENUES
Interest income.....................................      (4)         (4)
Equipment proceeds..................................      (2)         (2)
All other revenues including production revenues....      (5)(6)      (5)(6)

----------
(1)  Ninety percent of the subscription proceeds of you and the other investors
     in the partnership in which you subscribe will be used to pay 100% of the
     intangible drilling costs incurred by that partnership in drilling and
     completing its wells.

(2)  Ten percent of the subscription proceeds of you and the other investors in
     the partnership in which you subscribe will be used to pay a portion of the
     equipment costs incurred by that partnership in drilling and completing its
     wells. All equipment costs in excess of 10% of the partnership's
     subscription proceeds will be paid by the managing general partner. Thus,
     the managing general partner will pay a majority of each partnership's
     equipment costs. Equipment proceeds, if any, will be credited in the same
     percentage in which the equipment costs were charged. Thus, the managing
     general partner will receive a majority of any equipment proceeds.

(3)  These costs will be charged to the parties in the same ratio as the related
     production revenues are being credited. These costs also include the
     plugging and abandonment costs of the wells after their economic reserves
     have been produced and depleted as described in "Participation in Costs and
     Revenues."

(4)  Interest earned on your subscription proceeds before the final closing of
     the partnership to which you subscribed will be credited to your account
     and paid to you not later than the partnership's first cash distribution
     from operations. After each closing of a partnership, and until the
     subscription proceeds from the closing are invested in the partnership's
     natural gas and oil operations, any interest income from temporary
     investments will be allocated pro rata to the investors providing the
     subscription proceeds. All other interest income, including interest earned
     on the deposit of operating revenues, will be credited as natural gas and
     oil production revenues are credited.

(5)  The managing general partner and you and the other investors in a
     partnership will share in all of that partnership's other revenues in the
     same percentage as their respective capital contributions bears to the
     partnership's total capital contributions, except that the managing general
     partner will receive an additional 7% of the partnership revenues. However,
     the managing general partner's total revenue share may not exceed 40% of
     partnership revenues.

(6)  The actual allocation of partnership revenues between the managing general
     partner and you and the other investors will vary from the allocation
     described in (5) above if a portion of the managing general partner's share
     of partnership net production revenues is subordinated as described above.

The managing general partner will review each partnership's accounts at least
monthly to determine whether cash distributions are appropriate and the amount
to be distributed, if any. The partnership in which you invest will distribute


                                       6

<PAGE>

funds to you and its other investors that the managing general partner does not
believe are necessary for the partnership to retain. (See "Participation in
Costs and Revenues.")

COMPENSATION

The items of compensation paid to the managing general partner and its
affiliates from each partnership are as follows:

     o    The managing general partner will receive a share of each
          partnership's revenues. The managing general partner's revenue share
          will be in the same percentage as its capital contribution bears to
          that partnership's total capital contributions plus an additional 7%
          of partnership revenues. However, the managing general partner's
          revenue share may not exceed a total of 40% of partnership revenues,
          regardless of the amount of the managing general partner's capital
          contribution, and a portion of the managing general partner's revenue
          share will be subject to the its subordination obligation.

     o    The managing general partner will receive a credit to its capital
          account in an amount equal to the cost of the leases contributed to a
          partnership by the managing general partner, or the fair market value
          of the leases if the managing general partner has reason to believe
          that cost is materially more than the fair market value.

     o    Each partnership will enter into the drilling and operating agreement
          with the managing general partner to drill and complete the
          partnership's wells at competitive rates as described in "Compensation
          - Drilling Contracts."

     o    When a partnership's wells begin producing natural gas or oil in
          commercial quantities, the managing general partner, as operator of
          the wells, will receive:

          o    reimbursement at actual cost for all direct expenses incurred by
               it on behalf of the partnership; and

          o    well supervision fees for operating and maintaining the wells
               during producing operations at a competitive rate.

     o    The managing general partner will receive gathering fees at
          competitive rates for its services in gathering and transporting a
          partnership's natural gas production.

     o    Subject to certain exceptions described in "Plan of Distribution,"
          Anthem Securities, Inc., the dealer-manager and an affiliate of the
          managing general partner, which is sometimes referred to in this
          prospectus as "Anthem Securities," will receive on each unit sold to
          an investor a 2.5% dealer-manager fee, a 7% sales commission and up to
          a .5% reimbursement of the selling agents' bona fide due diligence
          expenses.

     o    The managing general partner or an affiliate will have the right to
          charge a competitive rate of interest on any loan it may make to or on
          behalf of a partnership. If the managing general partner provides
          equipment, supplies, and other services to a partnership, then it may
          do so at competitive industry rates.

     o    The managing general partner and its affiliates will receive a
          nonaccountable, fixed payment reimbursement for their administrative
          costs, which has been determined by the managing general partner to be
          $75 per well per month. The managing general partner may not increase
          this fee during the term of the partnership.

(See "Compensation.")


                                       7

<PAGE>

                                  RISK FACTORS

An investment in a partnership involves a high degree of risk and is suitable
only if you have substantial financial means and no need of liquidity in your
investment.

RISKS RELATED TO THE PARTNERSHIPS' OIL AND GAS OPERATIONS

NO GUARANTEE OF RETURN OF INVESTMENT OR RATE OF RETURN ON INVESTMENT BECAUSE OF
SPECULATIVE NATURE OF DRILLING NATURAL GAS AND OIL WELLS. Natural gas and oil
exploration is an inherently speculative activity. Before the drilling of a well
the managing general partner cannot predict with absolute certainty:

     o    the volume of natural gas and oil recoverable from the well; or

     o    the time it will take to recover the natural gas and oil.

You may not recover all of your investment in a partnership, or if you do
recover your investment in a partnership you may not receive a rate of return on
your investment that is competitive with other types of investment. You will be
able to recover your investment only through distributions of the partnership's
net proceeds from the sale of its natural gas and oil from productive wells. The
quantity of natural gas and oil in a well, which is referred to as its reserves,
decreases over time as the natural gas and oil is produced until the well is no
longer economical to operate. All of these distributions to you will be
considered a return of capital until you have received 100% of your investment.
This means that you are not receiving a return on your investment in a
partnership, excluding tax benefits, until your total cash distributions from
the partnership exceed 100% of your investment. (See "Prior Activities.")

BECAUSE SOME WELLS MAY NOT RETURN THEIR DRILLING AND COMPLETION COSTS, IT MAY
TAKE MANY YEARS TO RETURN YOUR INVESTMENT IN CASH, IF EVER. Even if a well is
completed in a partnership and produces natural gas and oil in commercial
quantities, it may not produce enough natural gas and oil to pay for the costs
of drilling and completing the well, even if tax benefits are considered. For
example, the managing general partner has formed 54 partnerships since 1985,
however, 38 of the 54 partnerships have not yet returned to the investor 100% of
his capital contributions without taking tax savings into account. Thus, it may
take many years to return your investment in cash, if ever. The partnerships'
primary drilling areas are located in the most active drilling areas in the
Appalachian Basin. As a result, many of the leases which will be drilled by a
partnership are in areas that have already been partially depleted or drained by
earlier offset drilling. This may reduce a partnership's ability to find
economically recoverable quantities of natural gas in those areas. (See "Prior
Activities.")

NONPRODUCTIVE WELLS MAY BE DRILLED EVEN THOUGH THE PARTNERSHIPS' OPERATIONS ARE
PRIMARILY LIMITED TO DEVELOPMENT DRILLING. Each partnership may drill some
development wells that are nonproductive, which is referred to as a "dry hole,"
and must be plugged and abandoned. If one or more of a partnership's wells are
nonproductive, then the partnership's productive wells may not produce enough
revenues to offset the loss of investment in the nonproductive wells. (See
"Prior Activities.")

PARTNERSHIP DISTRIBUTIONS MAY BE REDUCED IF THERE IS A DECREASE IN THE PRICE OF
NATURAL GAS AND OIL. The prices at which a partnership's natural gas and oil
will be sold are uncertain and, as discussed in "- Adverse Events in Marketing a
Partnership's Natural Gas Could Reduce Partnership Distributions," the
partnerships are not guaranteed a specific natural gas price for the sale of
their natural gas production. Changes in natural gas and oil prices will have a
significant impact on a partnership's cash flow and the value of its reserves.
Lower natural gas and oil prices may not only decrease a partnership's revenues,
but also may reduce the amount of natural gas and oil that a partnership can
produce economically. Historically, natural gas and oil prices have been
volatile and it is likely that they will continue to be volatile in the future.
Prices for natural gas and oil will depend on supply and demand factors largely
beyond the control of the partnerships and prices may fluctuate widely in
response to:

     o    relatively minor changes in the supply of and demand for natural gas
          or oil;

     o    market uncertainty; and


                                       8

<PAGE>

     o    a variety of additional factors that are beyond a partnership's
          control, as described in "Competition, Markets and Regulations -
          Competition and Markets."

These factors make it extremely difficult to predict natural gas and oil price
movements with any certainty.

If natural gas and oil prices decrease in the future, then your partnership
distributions will decrease accordingly. Also, natural gas and oil prices may
decrease during the first years of production from your partnership's wells
which is when the wells typically achieve their greatest level of production.
This would have a greater adverse effect on your partnership distributions than
price decreases in later years when the wells have a lower level of production.
Also, your return level will decrease during the term of the partnership, even
if there are rising natural gas prices, because of declining production volumes
from the wells over time. See "Appendix A - Information Regarding Currently
Proposed Prospects for Atlas America Public #16-2007(A) L.P." for a discussion
of flush production and "Proposed Activities - Sale of Natural Gas and Oil
Production." Further, as discussed in "Federal Income Tax Consequences -
Depletion Allowance," the managing general partner has represented that most, if
not all, of the natural gas and oil production from your partnership's
productive wells will be marginal production under the Internal Revenue Code and
could qualify for potentially higher rates of percentage depletion. Thus, the
partnership will be more sensitive to price declines than if its wells produced
at a higher average rate of production that did not qualify for the potentially
higher rate of percentage depletion.

ADVERSE EVENTS IN MARKETING A PARTNERSHIP'S NATURAL GAS COULD REDUCE PARTNERSHIP
DISTRIBUTIONS. In addition to the risk of decreased natural gas and oil prices
described above, certain material adverse events in marketing a partnership's
natural gas could reduce a partnership's distributions to you and its other
investors. These risks are set forth below.

     o    Competition from other natural gas producers and marketers in the
          Appalachian Basin, as well as competition from alternative energy
          sources, may make it more difficult to market each partnership's
          natural gas.

     o    The majority of each partnership's natural gas production and that of
          the managing general partner will be sold to a limited number of
          different natural gas purchasers as described in "Proposed Activities
          - Sale of Natural Gas and Oil Production." As set forth in "Appendix A
          - Information Regarding Currently Proposed Prospects for Atlas America
          Public #16-2007(A) L.P.," the managing general partner has identified
          three primary areas where it intends to drill each partnership's
          wells. The managing general partner anticipates that each
          partnership's natural gas production in each of the three primary
          areas initially will be sold to a different purchaser or purchasers in
          each area. Each partnership will depend on a limited number of natural
          gas purchasers. If a partnership loses a natural gas purchaser in a
          given area, the partnership may be unable to locate a new natural gas
          purchaser in the area that will buy the partnership's natural gas on
          as favorable terms as the initial purchaser.

          Although one of the partnership's natural gas purchasers has a 10-year
          agreement, which began on April 1, 1999, to buy all of the managing
          general partner's and its affiliates' natural gas production, there
          are various exceptions to its obligation to buy the natural gas. The
          most significant exception for each partnership includes natural gas
          produced from the Fayette County, Pennsylvania area, which is where
          the managing general partner anticipates that the majority of each
          partnership's prospects will be situated. The majority of the natural
          gas produced from the Fayette County area by each partnership
          initially will be sold to four different purchasers under natural gas
          contracts described in "Proposed Activities - Sale of Natural Gas and
          Oil Production." Of the remaining two primary areas, there will be a
          different natural gas purchaser in each area and natural gas produced
          from only one of those areas will be sold under the 10-year agreement
          referred to above.

          Also, all of these natural gas purchase contracts provide that the
          price paid by the natural gas purchaser may be adjusted upward or
          downward in accordance with the spot market price and market
          conditions as described in "Proposed Activities - Sale of Natural Gas
          and Oil Production." Thus, the partnerships will not be guaranteed a
          specific natural gas price, other than through hedging or forward
          sales transactions


                                       9

<PAGE>

          through the natural gas purchasers (which is not considered hedging
          for accounting purposes), and the price a partnership receives for the
          sale of its natural gas may decrease in the future because of market
          conditions. Although hedging and forward sales transactions provide
          the partnerships some protection against falling natural gas prices,
          those arrangements also could reduce the potential benefits of price
          increases if, at the time the natural gas is to be delivered, the spot
          market natural gas price is higher than the price paid under the
          hedging arrangements or forward sales transactions. Also, the
          partnership could incur liability on the financial hedges.

     o    There is a credit risk associated with a natural gas purchaser's
          ability to pay. Each partnership may not be paid, or may experience
          delays in receiving payment, for its natural gas that has already been
          delivered to the purchaser. In accordance with industry practice, a
          partnership typically will deliver natural gas to a purchaser for a
          period of up to 60 to 90 days before it receives payment. Thus, it is
          possible that the partnership may not be paid for natural gas that
          already has been delivered if the natural gas purchaser fails to pay
          for any reason, including bankruptcy. This ongoing credit risk also
          may delay or interrupt the sale of the partnership's natural gas or
          the partnership's negotiation of different terms and arrangements for
          selling its natural gas to other purchasers. Finally, this credit risk
          may reduce the price benefit derived by the partnerships from the
          managing general partner's natural gas hedging arrangements as
          described in "Proposed Activities - Sale of Natural Gas and Oil
          Production - Natural Gas Contracts," since from time to time the
          managing general partner has implemented a portion of its natural gas
          hedges through the natural gas purchasers.

     o    A partnership's net revenues will decrease the farther its natural gas
          is transported for sale because of increased transportation costs.

     o    Production from wells drilled in certain areas, such as wells drilled
          in the Crawford County, Pennsylvania area and, to a lesser extent, the
          Fayette County, Pennsylvania and Anderson, Campbell, Morgan, Scott and
          Roane Counties, Tennessee area, may be delayed until construction of
          the necessary gathering lines and production facilities is completed.
          (See "Proposed Activities - Sale of Natural Gas and Oil Production -
          Gathering of Natural Gas.")

     o    The managing general partner anticipates that it will use the
          gathering system owned by Atlas Pipeline Partners for the majority of
          a partnership's natural gas as described in "Proposed Activities -
          Sale of Natural Gas and Oil Production - Gathering of Natural Gas."
          Atlas Pipeline Partners GP, LLC, a wholly-owned subsidiary of Atlas
          Pipeline Holdings, L.P., an affiliate of Atlas America, Inc., which is
          sometimes referred to in this prospectus as "Atlas America" and is the
          indirect parent company of the managing general partner, controls and
          manages the gathering system for Atlas Pipeline Partners. (See
          "Management - Organizational Diagram and Security Ownership of
          Beneficial Owners.") However, Atlas Pipeline Holdings, L.P., as a
          public company, may be more susceptible to a change of control from
          Atlas America's affiliates to independent third-parties.

          Also, certain of the managing general partner's affiliates, including
          Atlas America, are obligated through their agreement with Atlas
          Pipeline Partners to pay the difference between the amount a
          partnership pays for gathering fees to the managing general partner as
          set forth in "Compensation - Gathering Fees," and the greater of $.35
          per mcf or 16% of the gross sales price for the natural gas. This
          creates a conflict of interest between the managing general partner
          and a partnership because the managing general partner has an economic
          incentive to increase the amount of gathering fees paid by a
          partnership so as to reduce the amount of gathering fees paid by Atlas
          America to Atlas Pipeline Partners, but any increase cannot exceed a
          competitive rate. Further, if Atlas Pipeline Partners GP, LLC were
          removed as general partner of Atlas Pipeline Partners without cause
          and without its consent, this could create further pressure to
          increase the amount of gathering fees required to be paid by the
          partnerships for natural gas transported through Atlas Pipeline
          Partners' gathering system since Atlas Pipeline Partners GP, LLC would
          no longer receive revenues from Atlas Pipeline Partners, but Atlas
          America and its affiliates would be obligated to pay the


                                       10

<PAGE>

          difference between the amount in the master natural gas gathering
          agreement and the amount paid by a partnership other than with respect
          to new wells drilled, if any, by the partnership after the removal of
          Atlas Pipeline Partners GP, LLC as general partner of Atlas Pipeline
          Partners. Thus, the managing general partner and its affiliates would
          have an incentive to increase the gathering fees charged to a
          partnership. Any increase in the gathering fees that your partnership
          pays, which cannot exceed competitive rates, would reduce your cash
          distributions from the partnership.

POSSIBLE LEASEHOLD DEFECTS. There may be defects in a partnership's title to its
leases. Although the managing general partner will obtain a favorable formal
title opinion for the leases before each well is drilled, it will not obtain a
division order title opinion after the well is completed. Thus, a partnership
may experience losses from title defects which arose during drilling that would
have been disclosed by a division order title opinion, such as liens arising
during drilling operations or transfers of interests in the leases after
drilling begins. Also, the managing general partner may use its own judgment in
waiving title requirements for a partnership's leases and it will not be liable
for any failure of title of leases transferred to a partnership. (See "Proposed
Activities - Title to Properties.")

TRANSFER OF THE LEASES WILL NOT BE MADE UNTIL WELL IS COMPLETED. Because the
leases will not be transferred from the managing general partner to a
partnership until after the wells are drilled and completed, the transfer could
be set aside by a creditor of the managing general partner, or the trustee in
the event of the voluntary or involuntary bankruptcy of the managing general
partner, if it were determined that the managing general partner received less
than a reasonably equivalent value for the leases. In this event, the leases and
the wells would revert to the creditors or trustee, and the partnership would
either recover nothing or only the amount it paid for the leases and the cost of
drilling the wells. Assigning the leases to a partnership after the wells are
drilled and completed, however, will not affect the availability of the tax
deductions for intangible drilling costs since the partnership will have an
economic interest in the wells under the drilling and operating agreement before
the wells are drilled. (See "Proposed Activities - Title to Properties.")

PARTICIPATION WITH THIRD-PARTIES IN DRILLING WELLS MAY REQUIRE THE PARTNERSHIPS
TO PAY ADDITIONAL COSTS. Third-parties will participate with each partnership in
drilling some of the well and additional financial risks exist when the costs of
drilling, equipping, completing, and operating wells is shared by more than one
person. If a partnership pays its share of the costs, but another interest owner
does not pay its share of the costs, then the partnership would have to pay the
costs of the defaulting party. In this event, the partnership would receive the
defaulting party's revenues from the well, if any, under penalty arrangements
set forth in the operating agreement, which may, or may not, cover all of the
additional costs paid by the partnership.

If the managing general partner is not the actual operator of the well for all
of the working interest owners of the well, then there is a risk that the
managing general partner cannot supervise the third-party operator closely
enough. For example, decisions related to the following would be made by the
third-party operator and may not be in the best interests of the partnerships
and you and the other investors:

     o    how the well is operated;

     o    expenditures related to the well; and

     o    possibly the marketing of the natural gas and oil production from the
          well.

Further, the third-party operator may have financial difficulties and fail to
pay for materials or services on the wells it drills or operates, which would
cause the partnership to incur extra costs in discharging materialmen's and
workmen's liens. The managing general partner may not be the operator of the
well for all of the working interest owners of the well if the partnership owns
less than a 50% working interest in the well, or if the managing general partner
acquired the working interest in the well from a third-party under arrangements
that required the third-party to be named operator as one of the terms of the
acquisition.


                                       11

<PAGE>

RISKS RELATED TO AN INVESTMENT IN A PARTNERSHIP

IF YOU CHOOSE TO INVEST AS A GENERAL PARTNER, THEN YOU HAVE GREATER RISK THAN A
LIMITED PARTNER. If you elect to invest in a partnership as an investor general
partner for the tax benefits instead of as a limited partner, then under
Delaware law you will have unlimited liability for your partnership's activities
until you are converted to limited partner status, subject to certain exceptions
described in "Actions To Be Taken by Managing General Partner To Reduce Risks of
Additional Payments By Investor General Partners - Conversion of Investor
General Partner Units to Limited Partner Units." This could result in you being
required to make payments, in addition to your original investment, in amounts
that are impossible to predict because of their uncertain nature. Under the
terms of the partnership agreement, if you are an investor general partner you
agree to pay only your proportionate share, as among all of your partnership's
investor general partners, of your partnership's obligations and liabilities.
This agreement, however, does not eliminate your liability to third-parties if
another investor general partner does not pay his proportionate share of your
partnership's obligations and liabilities.

Also, each partnership will own less than 100% of the working interest in some
of its wells. If a court holds you and the other third-party working interest
owners of the well liable for the development and operation of a well and the
third-party working interest owners do not pay their proportionate share of the
costs and liabilities associated with the well, then the partnership and you and
the other investor general partners also would be liable for those costs and
liabilities.

As an investor general partner you may become subject to the following:

     o    contract liability, which is not covered by insurance;

     o    liability for pollution, abuses of the environment, and other
          environmental damages as discussed in "Competition, Markets and
          Regulation - Environmental Regulation, including but not limited to
          the release of toxic gas, spills or uncontrollable flows of natural
          gas, oil or well fluids, including underground or surface
          contamination, against which the managing general partner cannot
          insure because coverage is not available or against which it may elect
          not to insure because of high premium costs or other reasons; and

     o    liability for drilling hazards that result in property damage,
          personal injury, or death to third-parties in amounts greater than the
          insurance coverage. The drilling hazards include, but are not limited
          to, well blowouts, fires, craterings and explosions.

If your partnership's insurance proceeds and assets, the managing general
partner's indemnification of you and the other investor general partners, and
the liability coverage provided by major subcontractors were not sufficient to
satisfy the liability, then the managing general partner would call for
additional funds from you and the other investor general partners to satisfy the
liability. (See "Actions To Be Taken By Managing General Partner To Reduce Risks
of Additional Payments by Investor General Partners.") Additionally, any of the
drilling hazards may result in the loss of the well and the associated revenues.

THE MANAGING GENERAL PARTNER MAY NOT MEET ITS CAPITAL CONTRIBUTIONS,
INDEMNIFICATION AND PURCHASE OBLIGATIONS IF ITS LIQUID NET WORTH IS NOT
SUFFICIENT. The managing general partner has made commitments to you and the
other investors in each partnership regarding the following:

     o    the payment of organization and offering costs and the majority of
          equipment costs;

     o    indemnification of the investor general partners for liabilities in
          excess of their pro rata share of partnership assets and insurance
          proceeds; and

     o    purchasing units presented by an investor, although this feature may
          be suspended by the managing general partner if it determines, in its
          sole discretion, that it does not have the necessary cash flow or
          cannot borrow funds for this purpose on reasonable terms.

A significant financial reversal for the managing general partner could
adversely affect its ability to honor these obligations.


                                       12

<PAGE>

The managing general partner's net worth is based primarily on the estimated
value of its producing natural gas properties and is not available in cash
without borrowings or a sale of the properties. Also, if natural gas prices
decrease, then the estimated value of the properties and the managing general
partner's net worth will be reduced. Further, price decreases will reduce the
managing general partner's revenues, and may make some reserves uneconomic to
produce. This would reduce the managing general partner's reserves and cash
flow, and could cause the lenders of the managing general partner and its
affiliates to reduce the borrowing base for the managing general partner and its
affiliates. Also, because the majority of the managing general partner's proved
reserves are currently natural gas reserves, the managing general partner's net
worth is more susceptible to movements in natural gas prices than in oil prices.

The managing general partner's net worth may not be sufficient, either currently
or in the future, to meet its financial commitments under the partnership
agreement. These risks are increased because the managing general partner has
made similar financial commitments in most of its other partnerships and will
make this same commitment in future partnerships. See "Financial Information
Concerning the Managing General Partner and Atlas America Public #16-2007(A)
L.P."

AN INVESTMENT IN A PARTNERSHIP MUST BE FOR THE LONG-TERM BECAUSE THE UNITS ARE
ILLIQUID AND NOT READILY TRANSFERABLE. If you invest in a partnership, then you
must assume the risks of an illiquid investment. The transferability of the
units is limited by the securities laws, the tax laws, and the partnership
agreement. The units generally cannot be liquidated since there is not a readily
available market for the sale of the units. Further, the partnerships do not
intend to list the units on any exchange. (See "Transferability of Units -
Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the
Partnership Agreement.")

Also, a sale of your units could create adverse tax and economic consequences
for you. The sale or exchange of all or part of your units held for more than 12
months generally will result in a recognition of long-term capital gain or loss.
However, previous deductions for depreciation, depletion and intangible drilling
costs may be recaptured as ordinary income rather than capital gain regardless
of how long you have owned your units. If you have held your units for 12 months
or less, then the gain or loss generally will be short-term gain or loss. Also,
your pro rata share of a partnership's liabilities, if any, as of the date of
the sale or exchange of your units must be included in the amount realized by
you. Thus, the gain recognized by you may result in a tax liability greater than
the cash proceeds, if any, received by you from the sale or other disposition of
your units, if permitted under the partnership agreement. (See "Federal Income
Tax Consequences - Disposition of Units" and "Presentment Feature.")

SPREADING THE RISKS OF DRILLING AMONG A NUMBER OF WELLS WILL BE REDUCED IF LESS
THAN THE MAXIMUM SUBSCRIPTION PROCEEDS ARE RECEIVED AND FEWER WELLS ARE DRILLED.
Each partnership must receive minimum subscription proceeds of $2 million to
close the offering, and the subscription proceeds of the partnerships, in the
aggregate, may not exceed $200 million. There are no other requirements
regarding the size of a partnership other than the nonbinding targeted maximum
amounts described in "Terms of the Offering - Subscription to a Partnership."
Thus, the subscription proceeds of one partnership may be substantially more or
less than the subscription proceeds of another partnership. A partnership with a
smaller amount of subscription proceeds will drill fewer wells which decreases
the partnership's ability to spread the risks of drilling. For example, the
managing general partner anticipates that a partnership will drill approximately
seven net wells if the minimum subscriptions of $2 million are received, which
is compared with approximately 710 net wells if subscription proceeds of $200
million are received by a partnership. A gross well is a well in which a
partnership owns a working interest. This is compared with a net well which is
the sum of the fractional working interests owned in the gross wells. For
example, a 50% working interest owned in three wells is three gross wells, but
1.5 net wells.

On the other hand, to the extent more than the minimum subscription proceeds are
received by a partnership and the number of wells drilled increases, the
partnership's overall investment return may decrease if the managing general
partner is unable to find enough suitable wells to be drilled. (See "Proposed
Activities - Acquisition of Leases.") Also, to the extent a partnership's
subscription proceeds and number of wells it drills increase, greater demands
will be placed on the managing general partner's management capabilities.

In addition, the cost of drilling and completing a well is often uncertain and
there may be cost overruns in drilling and completing the wells because the
wells will not be drilled and completed on a turnkey basis for a fixed price,
that would shift


                                       13

<PAGE>

certain risks of loss to the managing general partner as drilling contractor.
The majority of the equipment costs of each partnership's wells will be paid by
the managing general partner. However, all of the intangible drilling costs of a
partnership's wells will be charged to you and the other investors in that
partnership. If a partnership incurs a cost overrun for the intangible drilling
costs of a well or wells, then the managing general partner anticipates that it
would use the partnership's subscription proceeds, if available, to pay the cost
overrun or advance the necessary funds to the partnership. Using subscription
proceeds to pay cost overruns charged to you and the other investors under the
partnership agreement will result in a partnership drilling fewer wells.

INCREASES IN THE COSTS OF THE WELLS MAY ADVERSELY AFFECT YOUR RETURN. The
increase in natural gas and oil prices over the last several years has increased
the demand for drilling rigs and other related equipment, and the costs of
drilling and completing natural gas and oil wells also have increased. Because
each partnership's wells will be drilled on a modified cost plus basis as
described in "Compensation - Drilling Contracts," these increased costs will
increase the cost to drill and complete each partnership's wells. Also, the
reduced availability of drilling rigs and other related equipment may make it
more difficult to drill a partnership's wells in a timely manner or to comply
with the prepaid intangible drilling costs rules discussed in "Federal Income
Tax Consequences - Drilling Contracts."

THE PARTNERSHIPS DO NOT OWN ANY PROSPECTS, THE MANAGING GENERAL PARTNER HAS
COMPLETE DISCRETION TO SELECT WHICH PROSPECTS ARE ACQUIRED BY A PARTNERSHIP, AND
THE POSSIBLE LACK OF INFORMATION FOR A MAJORITY OF THE PROSPECTS DECREASES YOUR
ABILITY TO EVALUATE THE FEASIBILITY OF A PARTNERSHIP. The partnerships do not
currently hold any interests in any prospects on which the wells will be
drilled, and the managing general partner has absolute discretion in determining
which prospects will be acquired to be drilled. The managing general partner has
identified in "Proposed Activities" the general areas where each partnership
will drill wells and the managing general partner intends that Atlas America
Public #16-2007(A) L.P. will drill the prospects described in "Appendix A -
Information Regarding Currently Proposed Prospects for Atlas America Public
#16-2007(A) L.P." These prospects represent the wells currently proposed to be
drilled if a portion of the targeted nonbinding amount of subscription proceeds
is received by Atlas America Public #16-2007(A) L.P. as described in "Terms of
the Offering - Subscription to a Partnership."

If there are material adverse events with respect to any of the currently
proposed prospects, the managing general partner will substitute a new prospect.
The managing general partner also anticipates that it will designate a portion
of the prospects in Atlas America Public #16-2007(B) L.P., if units are offered
in that partnership, by a supplement or an amendment to the registration
statement of which this prospectus is a part. With respect to the identified
prospects to be drilled by a partnership, the managing general partner has the
right on behalf of the partnership to:

     o    substitute prospects;

     o    take a lesser working interest in the prospects;

     o    drill in other areas; or

     o    do any combination of the foregoing.

Thus, you do not have any geological or production information to evaluate any
additional and/or substituted prospects and wells. Also, if the subscription
proceeds received by a partnership are insufficient to drill all of the
identified prospects, then the managing general partner will choose those
prospects which it believes are most suitable for the partnership. You must rely
entirely on the managing general partner to select the prospects and wells for a
partnership.

In addition, the partnerships do not have the right of first refusal in the
selection of prospects from the inventory of the managing general partner and
its affiliates, and they may sell their prospects to other partnerships,
companies, joint ventures, or other persons at any time.

DRILLING PROSPECTS IN ONE AREA MAY INCREASE RISK. If multiple wells are drilled
in one area at approximately the same time, then there is a greater risk that
two or more of the wells will be marginal or nonproductive since the managing
general partner will not be using the drilling results of one or more of those
wells to decide whether or not to continue drilling


                                       14

<PAGE>

prospects in that area or to substitute other prospects in other areas. This is
contrasted with the situation in which a partnership drills one well in an area,
and then assesses the drilling results before it decides to drill a second well
in the same area or to substitute a different prospect in another area.

This risk is further increased with respect to wells for which the drilling and
completing costs are prepaid in one year, and the drilling of the wells must
begin within the first 90 days of the immediately following year under the tax
laws associated with deducting the intangible drilling costs of the prepaid
wells in the year in which the prepayment is made, rather than the year in which
the wells are drilled. For example, if the partnership prepays in 2007 the costs
of drilling one or more wells to be drilled in 2008, potential bad weather
conditions during the first 90 days of 2008 could delay beginning the drilling
of one or more of the prepaid wells beyond the 90 day time limit under the tax
laws. This would have a greater adverse effect on the partnership's deduction
for prepaid intangible drilling costs if the managing general partner is
required to begin drilling many wells at the same time, rather than only a few
wells. Also, "frost laws" prohibit drilling rigs and other heavy equipment from
using certain roads during the winter, which may delay beginning the drilling of
the prepaid wells within the 90 day time limit in 2007 under the tax laws. In
addition, there could be shortages of drilling rigs, equipment, supplies and
personnel during this time period, or unexpected operational events and drilling
conditions. (See "Federal Income Tax Consequences - Drilling Contracts"
regarding prepaid wells and the 90 day time constraint.)

LACK OF PRODUCTION INFORMATION INCREASES YOUR RISK AND DECREASES YOUR ABILITY TO
EVALUATE THE FEASIBILITY OF A PARTNERSHIP'S DRILLING PROGRAM. Production
information from wells previously drilled in the area surrounding the location
where a new well is proposed to be drilled is an important indicator in
evaluating the economic potential of the well proposed to be drilled. However,
generally, there will be a lack of production information from surrounding wells
for the majority of the wells to be drilled by a partnership, which results in
greater uncertainty to you and the other investors. This lack of production
information results from the Pennsylvania Department of Environmental Resources
keeping production data confidential for the first five years from the time a
well starts producing, so if there was a third-party operation and the well has
been drilled within five years the production information is not available.
Also, when the managing general partner is the operator the wells may often be
drilled adjacent to wells which are not yet completed, not on-line to sell
production, or have been producing for only a short period of time so there is
little or no production information available.

THE PARTNERSHIPS IN THIS PROGRAM AND OTHER PARTNERSHIPS SPONSORED BY THE
MANAGING GENERAL PARTNER MAY COMPETE WITH EACH OTHER FOR PROSPECTS, EQUIPMENT,
SUBCONTRACTORS, AND PERSONNEL. One or more partnerships in this program and
other partnerships sponsored by the managing general partner may have unexpended
capital funds at the same time. Thus, these partnerships may compete for
suitable prospects, equipment, subcontractors, and the managing general
partner's personnel. For example, a partnership previously organized by the
managing general partner may still be acquiring prospects to drill when the
partnerships in this program are attempting to acquire their prospects. This may
make it more difficult for the partnerships to complete their prospect
acquisition and drilling activities and may make each partnership less
profitable.

MANAGING GENERAL PARTNER'S SUBORDINATION IS NOT A GUARANTEE OF THE RETURN OF ANY
OF YOUR INVESTMENT. If your cash distributions from the partnership in which you
invest are less than a 10% return of capital for each of the first five 12-month
periods beginning with the partnership's first cash distribution from
operations, then the managing general partner has agreed to subordinate a
portion of its share of the partnership's net production revenues. However, if
the wells produce only small natural gas and oil volumes, and/or natural gas and
oil prices decrease, then even with subordination you may not receive the 10%
return of capital for each of the first five years as described above, or a
return of your capital during the term of the partnership. Also, at any time
during the subordination period the managing general partner is entitled to an
additional share of partnership revenues to recoup previous subordination
distributions to the extent your cash distributions from the partnership exceed
the 10% return of capital described above. (See "Participation in Costs and
Revenues - Subordination of Portion of Managing General Partner's Net Revenue
Share.")

BORROWINGS BY THE MANAGING GENERAL PARTNER COULD REDUCE FUNDS AVAILABLE FOR ITS
SUBORDINATION OBLIGATION. With respect to each partnership, the managing general
partner has or will pledge either its partnership interest and/or an undivided
interest in the partnership's assets equal to or less than its revenue interest,
which will range from 32% to 40%, depending on the amount of its capital
contribution, to secure borrowings for its and its affiliates' general purposes.
(See "Participation in


                                       15

<PAGE>

Costs and Revenues" and "Conflicts of Interest - Conflicts Regarding Managing
General Partner Withdrawing or Assigning an Interest.") Under agreements
previously entered into as described in "Management's Discussion and Analysis of
Financial Condition, Results of Operations, Liquidity and Capital Resources,"
the managing general partner's lenders have required a first lien on the
managing general partner's interest in the natural gas and oil properties and
other assets of each partnership, and the lenders will have priority over the
managing general partner's subordination obligation under the partnership
agreement for each partnership. Thus, if there was a default by the managing
general partner to the lenders under this pledge arrangement, or if there was a
default by an affiliate of the managing general partner under this pledge
arrangement or another loan secured by this pledge arrangement, the amount of
each partnership's net production revenues available to the managing general
partner for its subordination obligation to you and the other investors would be
reduced or eliminated. Also, under certain circumstances, if the managing
general partner made a subordination distribution to you and the other investors
after a default to its lenders, then the lenders may be able to recoup that
subordination distribution from you and the other investors.

COMPENSATION AND FEES TO THE MANAGING GENERAL PARTNER REGARDLESS OF SUCCESS OF A
PARTNERSHIP'S ACTIVITIES WILL REDUCE CASH DISTRIBUTIONS. The managing general
partner and its affiliates will profit from their services in drilling,
completing, and operating each partnership's wells, and will receive the other
fees and reimbursement of direct costs described in "Compensation," regardless
of the success of the partnership's wells. These fees and direct costs will
reduce the amount of cash distributions to you and the other investors. The
amount of the fees is subject to the complete discretion of the managing general
partner, other than the fees must not exceed competitive fees charged by
unaffiliated third-parties in the same geographic area engaged in similar
businesses and they must comply with any other restrictions set forth in
"Compensation." With respect to direct costs, the managing general partner has
sole discretion on behalf of each partnership to select the provider of the
services or goods and the provider's compensation as discussed in
"Compensation."

THE INTENDED MONTHLY DISTRIBUTIONS TO INVESTORS MAY BE REDUCED OR DELAYED. Cash
distributions to you and the other investors may not be paid each month.
Distributions may be reduced or deferred, in the discretion of the managing
general partner, to the extent a partnership's revenues are used for any of the
following:

     o    compensation and fees to the managing general partner as described
          above in "- Compensation and Fees to the Managing General Partner
          Regardless of Success of a Partnership's Activities Will Reduce Cash
          Distributions";

     o    repayment of borrowings;

     o    cost overruns;

     o    remedial work to improve a well's producing capability;

     o    direct costs and general and administrative expenses of the
          partnership;

     o    reserves, including a reserve for the estimated costs of eventually
          plugging and abandoning the wells; or

     o    indemnification of the managing general partner and its affiliates by
          the partnership for losses or liabilities incurred in connection with
          the partnership's activities. (See "Participation in Costs and
          Revenues - Distributions.")

THERE ARE CONFLICTS OF INTEREST BETWEEN THE MANAGING GENERAL PARTNER AND THE
INVESTORS. There are conflicts of interest between you and the other investors
and the managing general partner and its affiliates. These conflicts of
interest, which are not otherwise discussed in this "Risk Factors" section,
include the following:

     o    the managing general partner has determined the compensation and
          reimbursement that it and its affiliates will receive in connection
          with the partnerships without any unaffiliated third-party dealing at
          arms' length on behalf of you and the other investors;


                                       16

<PAGE>

     o    the managing general partner must monitor and enforce, on behalf of
          the partnerships, its own compliance with the drilling and operating
          agreement and the partnership agreement and the compliance of it and
          its affiliate, Atlas Pipeline Partners, with the gas gathering
          agreement;

     o    because the managing general partner will receive a percentage of
          revenues greater than the percentage of costs that it pays, there may
          be a conflict of interest concerning which wells will be drilled based
          on each wells' risk and profit potential;

     o    the allocation of all intangible drilling costs to you and the other
          investors and the majority of the equipment costs to the managing
          general partner may create a conflict of interest concerning whether
          to complete a well;

     o    if the managing general partner, as tax matters partner, represents a
          partnership before the IRS, potential conflicts include, for example,
          whether or not to expend partnership funds to contest a proposed
          adjustment by the IRS, if any, to the amount of your deduction for
          intangible drilling costs, or the credit to the managing general
          partner's capital account for contributing the leases to the
          partnership;

     o    which wells will be drilled by the managing general partner's and its
          affiliates' other affiliated partnerships or third-party programs in
          which they serve as driller/operator and which wells will be drilled
          by the partnerships in this program, and the terms on which the
          partnerships' leases will be acquired;

     o    the managing general partner will have complete discretion in
          determining the terms on which it or its affiliated limited
          partnerships may purchase producing wells from each partnership;

     o    the managing general partner and its officers, directors, and
          affiliates may purchase units at a reduced price, which would dilute
          the voting rights of you and the other investors on certain matters;

     o    the same legal counsel represents the managing general partner and
          each partnership;

     o    Atlas Pipeline Partners, an affiliate of the managing general partner,
          has the right to determine the order of priority for constructing
          gathering lines for each partnership's wells; and

     o    Atlas Pipeline Partners, an affiliate of the managing general partner,
          will benefit from the partnerships drilling wells that will connect to
          its gathering system.

Other than certain guidelines set forth in "Conflicts of Interest," the managing
general partner has no established procedures to resolve a conflict of interest.

THE PRESENTMENT OBLIGATION MAY NOT BE FUNDED AND THE PRESENTMENT PRICE MAY NOT
REFLECT FULL VALUE. Subject to certain conditions, beginning with the fifth
calendar year after the offering of units in your partnership closes you may
present your units to the managing general partner for purchase. However, the
managing general partner may determine, in its sole discretion, that it does not
have the necessary cash flow or cannot borrow funds for this purpose on
reasonable terms. In either event the managing general partner may suspend the
presentment feature. This risk is increased because the managing general partner
has and will incur similar presentment obligations in other partnerships.

Further, the presentment price for your units may not reflect the full value of
a partnership's property or your units because of the difficulty in accurately
estimating natural gas and oil reserves. Reservoir engineering is a subjective
process of estimating underground accumulations of natural gas and oil that
cannot be measured in an exact way, and the accuracy of the reserve estimate is
a function of the quality of the available data and of engineering and
geological interpretation and judgment. Also, the reserves and future net
revenues are based on various assumptions as to natural gas and oil prices,
taxes, development expenses, capital expenses, operating expenses and
availability of funds. Any significant variance in these assumptions could
materially affect the estimated quantity of the reserves. As a result, the
managing general partner's estimates are inherently imprecise and may not
correspond to realizable value. Thus, the presentment price paid for your


                                       17

<PAGE>

units and the amount of any partnership distributions received by you before the
presentment may be less than the subscription amount you paid for your units.
However, because the presentment price is a contractual price it is not reduced
by discounts such as minority interests and lack of marketability that generally
are used to value partnership interests for tax and other purposes. (See
"Presentment Feature.")

Finally, see "- An Investment in a Partnership Must be for the Long-Term Because
the Units Are Illiquid and Not Readily Transferable," above, concerning the tax
effects on you of presenting your units for purchase.

THE MANAGING GENERAL PARTNER MAY NOT DEVOTE THE NECESSARY TIME TO THE
PARTNERSHIPS BECAUSE ITS MANAGEMENT OBLIGATIONS ARE NOT EXCLUSIVE. The
partnerships do not have any employees and must rely on the managing general
partner and its affiliates for the management of it and its business, and they
may not devote the necessary time to the partnerships, which is in the managing
general partner's discretion. Also, the managing general partner depends on its
indirect parent company, Atlas America and its affiliates, for management and
administrative functions and financing for capital expenditures as discussed in
"Management - Transactions with Management and Affiliates." The managing general
partner and its affiliates will be engaged in other oil and gas activities,
including other partnerships and unrelated business ventures for their own
account or for the account of others, during the term of each partnership. Thus,
the competition for time and services of the managing general partner and its
affiliates could result in insufficient attention to the management and
operation of the partnerships.

PREPAYING SUBSCRIPTION PROCEEDS TO THE MANAGING GENERAL PARTNER MAY EXPOSE THE
SUBSCRIPTION PROCEEDS TO CLAIMS OF THE MANAGING GENERAL PARTNER'S CREDITORS.
Under the drilling and operating agreement, each partnership will be required to
immediately pay the managing general partner the investors' share of the entire
estimated price for drilling and completing the partnership's wells. Thus, these
funds could be subject to claims of the managing general partner's creditors.
(See "Financial Information Concerning the Managing General Partner and Atlas
America Public #16-2007(A) L.P.")

LACK OF INDEPENDENT UNDERWRITER MAY REDUCE DUE DILIGENCE INVESTIGATION OF THE
PARTNERSHIPS AND THE MANAGING GENERAL PARTNER. There has not been an extensive
in-depth "due diligence" investigation of the existing and proposed business
activities of the partnerships and the managing general partner that would be
provided by independent underwriters. Anthem Securities, which is affiliated
with the managing general partner, serves as dealer-manager and will receive
reimbursement of bona fide due diligence expenses for certain due diligence
investigations conducted by the selling agents which it will reallow to the
selling agents. However, Anthem Securities' due diligence examination concerning
the partnerships cannot be considered to be independent, nor as comprehensive as
an investigation that would have been conducted by an independent broker/dealer.
(See "Conflicts of Interest.")

A LENGTHY OFFERING PERIOD MAY RESULT IN DELAYS IN THE INVESTMENT OF YOUR
SUBSCRIPTION AND ANY CASH DISTRIBUTIONS FROM THE PARTNERSHIP TO YOU. Because the
offering period for a particular partnership can extend for many months, it is
likely that there will be a delay in the investment of your subscription
proceeds. This may create a delay in the partnership's cash distributions to you
which will be paid only after a portion of the partnership's wells have been
drilled, completed and placed on-line for the delivery and sale of natural gas
and/or oil, and payment has been received from the purchaser of the natural gas
and/or oil. Also, distributions of a partnership's net production revenues will
be made only after payment of the managing general partner's fees and expenses
and only if there is sufficient cash available in the managing general partner's
discretion. See "Terms of the Offering" for a discussion of the procedures
involved in the offering of the units and the formation of a partnership.

YOUR INTERESTS MAY BE DILUTED. The equity interests of you and the other
investors in a partnership may be diluted. You and the other investors will
share in a partnership's production revenues from all of its wells in proportion
to your respective number of units, based on $10,000 per unit, regardless of:

     o    when you subscribe;

     o    which wells are drilled with your subscription proceeds; or

     o    the actual subscription price you paid for your units as described
          below.


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<PAGE>

Because the drilling results of the wells drilled with the subscription proceeds
in your closing may be better than the drilling results of wells drilled with
subscription proceeds from your partnership's other closings, the value of your
units could be diluted when compared to what their value would have been if the
other units had not been sold and the other wells had not been drilled.

Also, some investors, including the managing general partner and its officers
and directors as described in "Plan of Distribution," may buy up to 5% of the
total units in each partnership at discounted prices because the dealer-manager
fee, the sales commission, the reimbursement for bona fide due diligence
expenses and/or the accountable reimbursement for permissible non-cash
compensation, will not be paid for those sales. These discounted subscription
prices will reduce the amount of the subscription proceeds available to a
partnership to drill wells. (See "- Spreading the Risks of Drilling Among a
Number of Wells Will be Reduced if Less than the Maximum Subscription Proceeds
are Received and Fewer Wells are Drilled.") In addition, all of the investors in
each partnership will share in the partnership's production revenues with the
managing general partner, based on the number of units purchased by each
investor, rather than the purchase price paid by the investor for his units.
Thus, investors who pay discounted prices for their units will receive higher
returns on their investments in a partnership as compared to investors who pay
the entire $10,000 per unit.

TAX RISKS

YOUR DEDUCTION FOR INTANGIBLE DRILLING COSTS MAY BE LIMITED FOR PURPOSES OF THE
ALTERNATIVE MINIMUM TAX. You will be allocated a share of your partnership's
deduction for intangible drilling costs in the year 2007 in an amount equal to
90% of the subscription price you pay for your units. Under current tax law,
however, your alternative minimum taxable income in 2007 cannot be reduced by
more than 40% by your deduction for intangible drilling costs. (See "Federal
Income Tax Consequences - Alternative Minimum Tax.")

LIMITED PARTNERS NEED PASSIVE INCOME TO USE THEIR DEDUCTION FOR INTANGIBLE
DRILLING COSTS. If you invest in a partnership as a limited partner (except as
discussed below), your share of the partnership's deduction for intangible
drilling costs in 2007 will be a passive loss that cannot be used to offset
"active" income, such as salary and bonuses, or portfolio income, such as
dividends and interest income. Thus, you may not have enough passive income from
the partnership or net passive income from your other passive activities, if
any, in 2007, to offset a portion or all of your passive deduction for
intangible drilling costs in 2007. However, any unused passive loss from
intangible drilling costs may be carried forward by you to offset your passive
income in subsequent taxable years. Also, except as described below, the passive
activity limitations on your share of the partnership's deduction for intangible
drilling costs in 2007 do not apply to you if you invest in the partnership as a
limited partner and you are a C corporation which:

     o    is not a personal service corporation or a closely held corporation;

     o    is a personal service corporation in which employee-owners hold 10%
          (by value) or less of the stock, but is not a closely held
          corporation; or

     o    is a closely held corporation (i.e., five or fewer individuals own
          more than 50% (by value) of the stock), but is not a personal service
          corporation in which employee-owners own more than 10% (by value) of
          the stock, in which case you may use your passive losses to offset
          your net active income (calculated without regard to your passive
          activity income and losses or portfolio income and losses).

(See "Federal Income Tax Consequences - Limitations on Passive Activity Losses
and Credits.")

YOU MAY OWE TAXES IN EXCESS OF YOUR CASH DISTRIBUTIONS FROM YOUR PARTNERSHIP.
You may become subject to income tax liability for your share of your
partnership's income in any taxable year in an amount that is greater than the
cash and any marginal well production credits you receive from the partnership
in which you invest in that taxable year. For example:

     o    if the partnership borrows money, your share of partnership revenues
          used to pay principal on the loan will be included in your income from
          the partnership and will not be deductible;


                                       19

<PAGE>

     o    income from sales of natural gas and oil may be included in your
          income from the partnership in one tax year, although payment is not
          actually received by the partnership and, thus, cannot be distributed
          to you, until the next tax year;

     o    if there is a deficit in your capital account, the partnership may
          allocate income or gain to you even though you do not receive a
          corresponding distribution of partnership revenues;

     o    the partnership's revenues may be expended by the managing general
          partner for nondeductible costs or retained in the partnership to
          establish a reserve for future estimated costs, including a reserve
          for the estimated costs of eventually plugging and abandoning the
          wells, which will increase your share of the partnership's income
          without a corresponding cash distribution to you; and

     o    the taxable disposition of the partnership's property or your units
          may result in income tax liability to you in excess of the cash you
          receive from the transaction.

INVESTMENT INTEREST DEDUCTIONS OF INVESTOR GENERAL PARTNERS MAY BE LIMITED. If
you invest in a partnership as an investor general partner, your share of the
partnership's deduction for intangible drilling costs will reduce your
investment income and may reduce the amount of your deductible investment
interest expense, if any.

YOUR TAX BENEFITS FROM AN INVESTMENT IN A PARTNERSHIP ARE NOT CONTRACTUALLY
PROTECTED. An investment in a partnership does not give you any contractual
protection against the possibility that part or all of the intended tax benefits
of your investment will be disallowed by the IRS. No one provides any insurance,
tax indemnity or similar agreement for the tax treatment of your investment in a
partnership. You have no right to rescind your investment in a partnership or to
receive a refund of any of your investment in the partnership if a portion or
all of the intended tax consequences of your investment in the partnership are
ultimately disallowed by the IRS or the courts. Also, none of the fees paid by
the partnerships to the managing general partner, its affiliates or independent
third-parties (including special counsel which issued the tax opinion letter)
are refundable or contingent on whether the intended tax consequences of your
investment in a partnership are ultimately sustained if challenged by the IRS.

AN IRS AUDIT OF YOUR PARTNERSHIP MAY RESULT IN AN IRS AUDIT OF YOUR PERSONAL
FEDERAL INCOME TAX RETURNS. The IRS may audit each partnership's annual federal
information income tax returns, particularly since each partnership's investors
will receive a deduction equal to not less than 90% of their investment amount
in 2007, which includes their respective deductions for intangible drilling
costs. If the partnership in which you invest is audited, the IRS also may audit
your personal federal income tax returns, including prior years' returns and
items which are unrelated to the partnership. (See "Federal Income Tax
Consequences - Penalties and Interest.")

EACH PARTNERSHIP'S DEDUCTIONS MAY BE CHALLENGED BY THE IRS. If the IRS audits a
partnership, it may challenge the amount of the partnership's deductions and the
taxable year in which the deductions were claimed, including the deductions for
intangible drilling costs and depreciation. Any adjustments made by the IRS to
the federal information income tax returns of the partnership in which you
invest could lead to adjustments on your personal federal income tax returns and
could reduce the amount of your deductions from the partnership in 2007 and
subsequent tax years. The IRS also could seek to recharacterize a portion of the
partnership's intangible drilling costs for drilling and completing its wells as
some other type of expense, such as lease costs or equipment costs, which would
reduce or defer your share of the partnership's deductions for those costs. (See
"Federal Income Tax Consequences - Business Expenses," "- Depreciation and Cost
Recovery Deductions," and "- Drilling Contracts.")

In addition, depending primarily on when its subscription proceeds are received,
it is possible that each partnership may prepay in 2007 most or all of its
intangible drilling costs for wells the drilling of which will not begin until
2008. In that event, you will not receive a deduction in 2007 for your share of
the partnership's prepaid intangible drilling costs for those wells unless the
drilling of the prepaid wells begins on or before the 90th day following the
close of the partnership's taxable year in which the prepayment was made. Under
the drilling and operating agreement, the drilling of all of each partnership's
prepaid wells, if any, will be required to begin within that 90 day time period.
However, the drilling of any partnership well


                                       20

<PAGE>

may be delayed due to circumstances beyond the control of the managing general
partner, acting as general drilling contractor, without liability to the
managing general partner. If for any reason the drilling of a prepaid
partnership well does not begin within the required 90 day time period in 2008,
your deduction for prepaid intangible drilling costs for that well must be
claimed for your 2008 tax year, instead of your 2007 tax year. Also, there is a
greater risk that the IRS will attempt to defer from 2007 to 2008 your share of
the partnership's deduction for intangible drilling costs for drilling and
completing any prepaid partnership wells if there are other additional working
interest owners of a prepaid well, because those other working interest owners
will not be required to prepay their share of the costs of drilling and
completing the wells. (See "Federal Income Tax Consequences - Drilling
Contracts.")

CHANGES IN THE LAW MAY REDUCE YOUR TAX BENEFITS FROM AN INVESTMENT IN A
PARTNERSHIP. Your tax benefits from an investment in a partnership may be
affected by changes in the tax laws. For example, the top four federal income
tax brackets for individuals were reduced in 2003, including reducing the top
bracket to 35% from 38.6%, until December 31, 2010. The lower federal income tax
rates will reduce to some degree the amount of taxes you save by virtue of your
share of the partnership's deductions for intangible drilling costs, depletion,
and depreciation, and its marginal well production credits, if any. However, the
federal income tax rates described above could be changed again, even before
January 1, 2011, and other changes in the tax laws could be made which would
affect your tax benefits from an investment in a partnership.

IT MAY BE MANY YEARS BEFORE YOU RECEIVE ANY MARGINAL WELL PRODUCTION CREDITS, IF
EVER. There is a federal income tax credit for the sale of qualified marginal
natural gas and oil production. Although the managing general partner
anticipates that each partnership's natural gas and oil production will be
qualified production for purposes of this tax credit, the managing general
partner further anticipates any natural gas and oil production sold by Atlas
America Public #16-2007(A) L.P. or Atlas America Public #16-2007(B) L.P. in 2007
will be sold at prices above the applicable reference prices for 2006 at which
the marginal well production credit would be reduced to zero. In addition,
depending primarily on market prices for natural gas and oil, which are
volatile, you may not receive any marginal well production credits from either
partnership in which you invest for many years, if ever. (See "Federal Income
Tax Consequences - Marginal Well Production Credits.")

                             ADDITIONAL INFORMATION

The program and the partnerships composing the program currently are not
required to file reports with the SEC. However, a registration statement on Form
S-1 has been filed on behalf of the program with the SEC. Certain portions of
the registration statement have been deleted from this prospectus under SEC
rules and regulations. You are urged to refer to the registration statement, as
amended, and its exhibits for further information concerning the provisions of
certain documents referred to in this prospectus.

You may read and copy any materials filed as a part of the registration
statement, including the tax opinion included as Exhibit 8, at the SEC's Public
Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The SEC maintains
an internet world wide web site that contains registration statements, reports,
proxy statements, and other information about issuers who file electronically
with the SEC, including the program. The address of that site is
http://www.sec.gov. Also, you may obtain information on the operation of the
Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, a copy
of the tax opinion may be obtained by you or your advisors from the managing
general partner at no cost. The delivery of this prospectus does not imply that
its information is correct as of any time after its date.

                 FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS

Statements, other than statements of historical facts, included in this
prospectus and its exhibits address activities, events or developments that the
managing general partner and the partnerships anticipate will or may occur in
the future. For example, the words "believes," "anticipates," "will" and
"expects" are intended to identify forward-looking statements. These
forward-looking statements include such things as:

     o    investment objectives;

     o    references to future success in a partnership's drilling and marketing
          activities;


                                       21

<PAGE>

     o    business strategy;

     o    estimated future capital expenditures;

     o    competitive strengths and goals; and

     o    other similar matters.

These statements are based on certain assumptions and analyses made by the
partnerships and the managing general partner in light of their experience and
their perception of historical trends, current conditions, and expected future
developments. However, whether actual results will conform with these
expectations is subject to a number of risks and uncertainties, many of which
are beyond the control of the partnerships and the managing general partner,
including, but not limited to:

     o    general economic, market, or business conditions;

     o    changes in laws or regulations;

     o    the risk that the wells are productive, but do not produce enough
          revenue to return the investment made;

     o    the risk that the wells are dry holes; and

     o    uncertainties concerning the price of natural gas and oil, which may
          decrease.

Thus, all of the forward-looking statements made in this prospectus and its
exhibits are qualified by these cautionary statements. There can be no assurance
that actual results will conform with the managing general partner's and the
partnerships' expectations.

                              INVESTMENT OBJECTIVES

Each partnership's principal investment objectives are to invest its
subscription proceeds in natural gas development wells which will:

     o    Provide monthly cash distributions to you from the partnership in
          which you invest until the wells are depleted, with a minimum annual
          return of capital of 10% during the first five years beginning with
          your partnership's first revenue distribution and based on $10,000 per
          unit for all units sold regardless of the actual subscription price
          you paid for your units. These distributions of a 10% return of
          capital during the first five years are not guaranteed, but are
          subject to the managing general partner's subordination obligation.
          The managing general partner anticipates that investors in a
          partnership will begin to receive monthly cash distributions
          approximately eight months after the offering period for the
          partnership ends and it may take up to 12 months before all of the
          wells in that partnership have been drilled and completed and are
          on-line for the sale of their natural gas or oil production. However,
          if all or the majority of the units are sold in Atlas America Public
          #16-2007(A) L.P., then it may take longer for both cash distributions
          to begin and all of the wells to be drilled, completed and online to
          sell production in that partnership. This will also delay conversion
          of the investor general partner units to limited partner units. Also,
          see "Participation in Costs and Revenues - Subordination of Portion of
          Managing General Partner's Net Revenue Share" for a discussion of the
          subordination feature. The partnerships currently do not hold any
          interests in any prospects on which the wells will be drilled.

     o    Obtain tax deductions from the partnership in which you invest, in the
          year that you invest, from intangible drilling costs to offset a
          portion of your taxable income from sources other than the
          partnership, subject to the passive activity limitations on losses if
          you invest as a limited partner. For example, if you pay $10,000 for a
          unit your investment will produce an income tax deduction for
          intangible drilling costs of $9,000 per unit, 90%, in the year you
          invest against:


                                       22

<PAGE>

          o    ordinary income, or capital gain in some situations, if you
               invest as an investor general partner in a partnership; or

          o    net passive income from your other passive activity investments,
               if any, and passive income from the partnership in the year you
               invest, if any, if you invest as a limited partner in a
               partnership.

          In 2003,  the top four tax  brackets  for  individual  taxpayers  were
          reduced  from 38.6% to 35%,  35% to 33%,  30% to 28%,  and 27% to 25%.
          These changes are scheduled to expire December 31, 2010. If you are in
          either the 35% or 33% tax bracket,  you will save approximately $3,150
          or $2,970, respectively,  per $10,000 unit, in federal income taxes in
          the year  that you  invest.  Most  states  also  allow  this type of a
          deduction  against the state income tax. If the  partnership  in which
          you invest  begins  selling  natural gas and oil  production  from its
          wells  in the  year in  which  you  invest,  however,  then you may be
          allocated  a share of  partnership  income  in that  year that will be
          offset by a portion of your  intangible  drilling  cost  deduction and
          your share of the other partnership deductions discussed below.

     o    Offset a portion of any gross production income generated by your
          partnership with tax deductions from percentage depletion, which is
          anticipated by the managing general partner to be 15% in 2007. The
          percentage depletion rate may fluctuate from year to year depending on
          the price of oil, but under current tax law it will not be less than
          the statutory rate of 15% nor more than 25%.

     o    Obtain tax deductions of the remaining 10% of your investment over a
          seven-year cost recovery period, beginning in the year the wells are
          drilled, completed and placed in service for the production of natural
          gas or oil in the partnership in which you invest. For example, if you
          pay $10,000 for a unit, you will receive additional income tax
          deductions over the cost recovery period totaling $1,000 per unit for
          depreciation of your partnership's equipment costs for its productive
          wells.

     o    If you are self-employed and invest in a partnership as an investor
          general partner, then you may use your share of the partnership's
          deduction for intangible drilling costs to offset a portion of your
          net earnings from self-employment in the year you invest. Also, if
          wells in the partnership are drilled and completed and placed in
          service in the year you invest, you will begin receiving the
          depreciation deductions discussed above which, to the extent they
          exceed your share of your partnership's income, if any, in the year in
          which you invest, also will reduce your net earnings from
          self-employment in the year you invest, and in your subsequent tax
          years during the seven-year cost recovery period.

Attainment of these investment objectives by a partnership will depend on many
factors, including the ability of the managing general partner to select
suitable wells that will be productive and produce enough revenue to return the
investment made. The success of each partnership depends largely on future
economic conditions, especially the future price of natural gas, which is
volatile and may decrease. Also, the extent to which each partnership attains
the foregoing investment objectives will be different, because each partnership
is a separate business entity which:

     o    generally will drill different wells;

     o    will likely receive a different amount of subscription proceeds, as
          intended by the managing general partner, which generally will be the
          primary factor in determining the number of wells that can be drilled
          by each partnership; and

     o    may drill wells situated in different geographical areas, where the
          wells will be drilled to different formations, reservoirs or depths,
          which will affect the cost of the wells and, thus, will also affect
          the number of wells that can be drilled by each partnership.

There can be no guarantee that the foregoing objectives will be attained.


                                       23

<PAGE>

                    ACTIONS TO BE TAKEN BY MANAGING GENERAL
                     PARTNER TO REDUCE RISKS OF ADDITIONAL
                     PAYMENTS BY INVESTOR GENERAL PARTNERS

You may choose to invest in a partnership as an investor general partner so that
you can receive an immediate tax deduction against any type of income. To help
reduce the risk that you and other investor general partners could be required
to make additional payments to the partnership, the managing general partner
will take the actions set forth below.

     o    INSURANCE. The managing general partner will obtain and maintain
          insurance coverage in amounts and for purposes which would be carried
          by a reasonable, prudent general contractor and operator in accordance
          with industry standards. Each partnership will be included as an
          insured under these general, umbrella, and excess liability policies.
          In addition, the managing general partner requires all of its
          subcontractors to certify that they have acceptable insurance coverage
          for worker's compensation and general, auto, and excess liability
          coverage. Major subcontractors are required to carry general and auto
          liability insurance with a minimum of $1 million combined single limit
          for bodily injury and property damage in any one occurrence or
          accident. In the event of a loss caused by a major subcontractor, the
          managing general partner or partnership may attempt to draw on the
          insurance policy of the particular subcontractor before the insurance
          of the managing general partner or that of the partnership, but
          currently would be unable to do so since none of its major
          subcontractors have insurance which would allow this. Also, even if a
          major subcontractor's insurance was initially available, the managing
          general partner or a partnership may choose to draw on its own
          insurance coverage before that of the major subcontractor so that its
          insurance carrier will control the payment of claims.

          The managing general partner's current insurance coverage satisfies
     the following specifications:

          o    worker's compensation insurance in full compliance with the laws
               of the Commonwealth of Pennsylvania and any other applicable
               state laws where the wells will be drilled;

          o    commercial general liability covering bodily injury and property
               damage third party liability, including products/completed
               operations, blow out, cratering, and explosion with limits of $1
               million per occurrence/$2 million general aggregate; and $1
               million products/completed operations aggregate;

          o    underground resources and equipment property damages liability to
               others with a limit of $1 million;

          o    automobile liability with a $1 million combined single limit;

          o    employer's liability with a $500,000 policy limit;

          o    pollution liability resulting from a "pollution incident," which
               is defined as the discharge, dispersal, seepage, migration,
               release or escape of one or more pollutants directly from a well
               site, with a limit of $1 million for bodily injury and property
               damage and a limit of $100,000 for clean-up for third-parties;
               however, coverage does not apply to pollution damage to the well
               site itself or the property of the insured;

          o    commercial umbrella liability composed of:

               o    primary umbrella limit of $25 million over general
                    liability, automobile liability, and employer's liability
                    and a $10 million sublimit for pollution liability; and


                                       24

<PAGE>

               o    excess liability providing excess limits of $24 million over
                    the $25 million provided in the commercial umbrella, which
                    is for general liability only.

          Because the managing general partner is driller and operator of wells
          for other partnerships, the insurance available to each partnership
          could be substantially less if insurance claims are made in the other
          partnerships.

          This insurance has deductibles, which would first have to be paid by a
          partnership, of:

          o    $2,500 per occurrence for bodily injury and property damage; and

          o    $10,000 per pollution incident for pollution damage.

          The insurance also has terms, including exclusions, that are standard
          for the natural gas and oil industry. On request the managing general
          partner will provide you or your representative a copy of its
          insurance policies. The managing general partner will use its best
          efforts to maintain insurance coverage that meets its current
          coverage, but it may be unsuccessful if the coverage becomes
          unavailable or too expensive.

          If you are an investor general partner and there is going to be a
          material adverse change in your partnership's insurance coverage,
          which the managing general partner does not anticipate, then the
          managing general partner will notify you at least 30 days before the
          effective date of the change. You will then have the right to convert
          your units into limited partner units before the change in insurance
          coverage by giving written notice to the managing general partner.

     o    CONVERSION OF INVESTOR GENERAL PARTNER UNITS TO LIMITED PARTNER UNITS.
          Your investor general partner units will be automatically converted by
          the managing general partner to limited partner units after all of the
          wells in your partnership have been drilled and completed. In each
          partnership, the managing general partner anticipates that all of the
          wells will be drilled and completed no more than 12 months after a
          partnership closes, and the conversion will occur before the end of
          the succeeding tax year. However, if all or the majority of the units
          are sold in Atlas America Public #16-2007(A) L.P., then it may take
          longer for both cash distributions to begin and all of the wells to be
          drilled, completed and online to sell production in that partnership.
          This will also delay conversion of the investor general partner units
          to limited partner units.

          Once your units are converted, which is a nontaxable event, you will
          have the lesser liability of a limited partner in your partnership
          under Delaware law for obligations and liabilities arising after the
          conversion. However, you will continue to have the responsibilities of
          a general partner for partnership liabilities and obligations incurred
          before the effective date of the conversion. For example, you might
          become liable for partnership liabilities in excess of your
          subscription amount during the time the partnership is engaged in
          drilling activities and for environmental claims that arose during
          drilling activities, but were not discovered until after the
          conversion.

     o    NONRECOURSE DEBT. The partnerships do not anticipate that they will
          borrow funds. However, if borrowings are required, then the
          partnerships will be permitted to borrow funds only from the managing
          general partner or its affiliates and without recourse against
          non-partnership assets. Thus, if there is a default under this loan
          arrangement you cannot be required to contribute funds to the
          partnership. Any borrowings by a partnership will be repaid from that
          partnership's revenues.

          The amount that may be borrowed at any one time by a partnership may
          not exceed an amount equal to 5% of the investors' subscription
          proceeds in the partnership. However, because you do not bear the risk
          of repaying these borrowings with non-partnership assets, the
          borrowings will not increase the extent to which you are allowed to
          deduct your individual share of partnership losses. (See "Federal
          Income Tax Consequences - Tax Basis of Units" and "- 'At Risk'
          Limitation on Losses.")


                                       25

<PAGE>

     o    INDEMNIFICATION. The managing general partner will indemnify you from
          any liability incurred in connection with your partnership that is in
          excess of your interest in the partnership's:

          o    undistributed net assets; and

          o    insurance proceeds, if any, from all potential sources.

          The managing general partner's indemnification obligation, however,
          will not eliminate your potential liability if the managing general
          partner's assets are insufficient to satisfy its indemnification
          obligation. There can be no assurance that the managing general
          partner's assets, including its liquid assets, will be sufficient to
          satisfy its indemnification obligation.

             CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS

SOURCE OF FUNDS

Each partnership must receive minimum subscription proceeds of $2 million to
close, and the subscription proceeds of both partnerships, in the aggregate, may
not exceed $200 million. There are no other requirements regarding the size of a
partnership, and the subscription proceeds of one partnership may be
substantially more or less than the subscription proceeds of the other
partnership. See the targeted maximum subscription amounts for each partnership
set forth in "Terms of the Offering - Subscription to a Partnership." Also, the
managing general partner has the discretion to accept subscriptions for any
amount up to and including the entire amount in Atlas America Public #16-2007(A)
L.P. and not offer and sell any units in the other partnership. (See "Terms of
the Offering - Subscription to a Partnership.")

On completion of the offering of units in a partnership, the partnership's
source of funds will be as follows assuming each unit is sold for $10,000:

     o    the subscription proceeds of you and the other investors, which will
          be:

          o    $2 million if 200 units are sold; and

          o    $200 million if 20,000 units are sold; and

     o    the managing general partner's capital contribution, which must be at
          least 25% of all capital contributions and includes its credit for
          organization and offering costs and contributing the leases, which
          will be:

          o    not less than approximately $781,233 if 200 units are sold; and

          o    not less than approximately $78,810,820 if 20,000 units are sold.

Thus, the total amount available to a partnership will be not less than
approximately $2,781,233 if 200 units are sold ranging to not less than
approximately $278,810,820 if 20,000 units are sold.

The managing general partner has made the largest single capital contribution in
each of its prior partnerships and no individual investor has contributed more,
although the total investor contributions in each partnership have exceeded the
managing general partner's contribution. The managing general partner also
expects to make the largest single capital contribution in each of the
partnerships.

USE OF PROCEEDS

The subscription proceeds received from you and the other investors will be used
by the partnership in which you invest as follows:

     o    90% of the subscription proceeds will be used to pay 100% of the
          intangible drilling costs of drilling and completing the partnership's
          wells; and


                                       26

<PAGE>

     o    10% of the subscription proceeds will be used to pay a portion of the
          equipment costs of drilling and completing the partnership's wells.

The managing general partner will contribute all of the leases to each
partnership covering the acreage on which the partnership's wells will be
drilled, and pay all of the equipment costs of drilling and completing the
partnership's wells that exceed 10% of the partnership's subscription proceeds.
Thus, the managing general partner will pay the majority of each partnership's
equipment costs. The managing general partner also will be charged with 100% of
the organization and offering costs for each partnership. A portion of these
contributions to each partnership will be in the form of payments to itself, its
affiliates and third-parties and the remainder will be in the form of services
related to organizing this offering. The managing general partner will receive a
credit towards its required capital contribution to each partnership for these
payments and services as discussed in "Participation in Costs and Revenues."

The following tables present information concerning each partnership's use of
the proceeds provided by both you and the other investors and the managing
general partner. The tables are based in part on the managing general partner's
estimate of its capital contribution to a partnership based on the applicable
number of units sold as shown in the table. The managing general partner's
estimated capital contribution shown in the tables includes its credit for
organization and offering costs and contributing the leases, and exceeds in each
case its required capital contribution of not less than 25% of all capital
contributions to a partnership. Anthem Securities, an affiliate of the managing
general partner, will be the dealer-manager of each offering and it will receive
the dealer-manager fee, the sales commissions and the up to .5% reimbursement
for bona fide due diligence expenses. A portion of these payments and
reimbursements, including all of the up to .5% reimbursement for bona fide due
diligence expenses, will be reallowed by the dealer-manager to the
broker/dealers, which are referred to as selling agents, as discussed in "Plan
of Distribution." Subject to the above, a partnership's organizational costs
will be paid to the managing general partner, its affiliates and various
third-parties, and the intangible drilling costs and tangible costs of drilling
and completing a partnership's wells will be paid to the managing general
partner as general drilling contractor and operator under the drilling and
operating agreement.

The tables are presented based on:

     o    the sale of 200 units ($2 million), which is the minimum number of
          units for each partnership; and

     o    the sale of 20,000 units, which is the maximum number of units, in the
          aggregate, for all the partnerships in the program.

Substantially all of the proceeds available to each partnership will be expended
for the following purposes and in the following manner:

                                INVESTOR CAPITAL

<TABLE>
<CAPTION>
                                                                         20,000
                                                    200                   UNITS
NATURE OF PAYMENT                                UNITS SOLD   % (1)       SOLD       % (1)
----------------------------------------------   ----------   -----   ------------   -----
<S>                                              <C>          <C>     <C>            <C>
ORGANIZATION AND OFFERING EXPENSES
Dealer-manager fee, sales commissions and up to
..5% reimbursement for bona fide due diligence
expenses......................................          -0-     -0-            -0-    -0-
Organization costs............................          -0-     -0-            -0-    -0-
AMOUNT AVAILABLE FOR INVESTMENT:
Intangible drilling costs (2).................   $1,800,000      90%  $180,000,000     90%
Equipment costs (2)...........................     $200,000      10%   $20,000,000     10%
Leases........................................          -0-     -0-            -0-    -0-
                                                 ----------     ---   ------------    ---
TOTAL INVESTOR CAPITAL........................   $2,000,000     100%  $200,000,000    100%
                                                 ==========     ===   ============    ===
</TABLE>


                                       27

<PAGE>

----------
(1)  The percentage is based on the investors' total subscription proceeds, and
     excludes the managing general partner's estimate of its capital
     contributions in the "- Managing General Partner Capital" table below.

(2)  Ninety percent of the subscription proceeds provided by you and the other
     investors to each partnership will be used to pay 100% of the partnership's
     intangible drilling costs. Ten percent of the subscription proceeds
     provided by you and the other investors to each partnership will be used to
     pay a portion of the partnership's equipment costs. (See "Participation in
     Costs and Revenues.") The managing general partner will pay all of the
     remaining equipment costs of each partnership. In this regard, the managing
     general partner's share of each partnership's equipment costs as set forth
     in the "- Managing General Partner Capital" and the "- Total Partnership
     Capital" tables below is based on the managing general partner's estimate
     of the average cost of drilling and completing wells in each partnership's
     primary areas as discussed in "Compensation - Drilling Contracts."

                        MANAGING GENERAL PARTNER CAPITAL

<TABLE>
<CAPTION>
                                                     200                20,000
                                                    UNITS               UNITS
NATURE OF PAYMENT                                   SOLD     % (1)       SOLD      % (1)
-----------------------------------------------   --------   -----   -----------   -----
<S>                                               <C>        <C>     <C>           <C>
ORGANIZATION AND OFFERING EXPENSES
Dealer-manager fee, sales commissions and up to
..5% reimbursement for bona fide due diligence
expenses (2)...................................   $200,000   25.60%  $20,000,000   26.65%
Organization costs (2).........................   $100,000   12.80%  $10,000,000   11.42%
AMOUNT AVAILABLE FOR INVESTMENT:
Intangible drilling costs......................        -0-     -0-           -0-     -0-
Equipment costs (3)............................   $402,063   51.47%  $40,780,720   51.74%
Leases (4).....................................   $ 79,170   10.13%  $ 8,030,100   10.19%
                                                  --------   -----   -----------   -----
TOTAL MANAGING GENERAL PARTNER CAPITAL            $781,233     100%  $78,810,820     100%
                                                  ========   =====   ===========   =====
</TABLE>

----------
(1)  The percentage is based on the managing general partner's estimate of its
     capital contributions, and excludes the investors' total subscription
     proceeds set forth in the "- Investor Capital" table above.

(2)  As discussed in "Participation in Costs and Revenues," if these fees, sales
     commissions, reimbursements and organization costs exceed 15% of the
     investors' total subscription proceeds in a partnership, then the excess
     will be charged to the managing general partner, but will not be included
     as part of its capital contribution.

(3)  The managing general partner's share of equipment costs is described in
     "Compensation - Drilling Contracts" and "Participation in Costs and
     Revenues." However, these costs will vary depending on the actual equipment
     costs of drilling and completing the wells. Also, see footnote (2) to the
     "- Investor Capital" table above.

(4)  Instead of contributing cash for the leases, the managing general partner
     will assign to each partnership the leases covering the acreage on which
     the partnership's wells will be drilled. Generally, as described in
     "Compensation - Lease Costs," the managing general partner's lease costs
     are approximately $11,310 per prospect. For purposes of this table, the
     managing general partner's lease costs have been quantified using this
     amount based on its estimate of the number of net wells that will be
     drilled with the amount of subscription proceeds available as set forth in
     the table. The actual number of net wells drilled by the partnerships is
     likely to vary from the managing general partner's estimate, based
     primarily on where the wells are drilled and the actual costs of drilling
     and completing the wells. Also, the managing general partner's lease costs
     on a prospect may be significantly higher than the above-referenced amount,
     and its credit for the leases contributed will equal its cost, unless it
     has a reason to believe that cost is materially more than fair market value
     of the property, in which case its credit for its lease contribution must
     not exceed fair market value.


                                       28

<PAGE>

                            TOTAL PARTNERSHIP CAPITAL

<TABLE>
<CAPTION>
                                                                200                  20,000
NATURE OF PAYMENT                                            UNITS SOLD   % (1)    UNITS SOLD    % (1)
----------------------------------------------------------   ----------   -----   ------------   -----
<S>                                                          <C>          <C>     <C>            <C>
ORGANIZATION AND OFFERING EXPENSES
Dealer-manager fee, sales commissions and up to .5%
reimbursement for bona fide due diligence expenses (2) ...   $  200,000    7.19%  $ 20,000,000    7.17%
Organization costs (2) ...................................   $  100,000    3.59%  $ 10,000,000    3.59%
AMOUNT AVAILABLE FOR INVESTMENT:
Intangible drilling costs (3) ............................   $1,800,000   64.72%  $180,000,000   64.56%
Equipment costs (3) ......................................   $  602,063   21.65%  $ 60,780,720   21.80%
Leases (4) ...............................................   $   79,170    2.85%  $  8,030,100    2.88%
                                                             ----------   -----   ------------   -----
TOTAL PARTNERSHIP CAPITAL ................................   $2,781,233     100%  $278,810,820     100%
                                                             ==========   =====   ============   =====
</TABLE>

----------
(1)  The percentage is based on investors' total subscription proceeds in the "-
     Investor Capital Table" above, and the managing general partner's estimate
     of its capital contributions in the "- Managing General Partner Capital"
     table above.

(2)  As discussed in "Participation in Costs and Revenues," if these fees, sales
     commissions, reimbursements and organization costs exceed 15% of the
     investors' total subscription proceeds in a partnership, then the excess
     will be charged to the managing general partner, but will not be included
     as part of its capital contribution.

(3)  The managing general partner's share of equipment costs is described in
     "Compensation - Drilling Contracts" and "Participation in Costs and
     Revenues." Although these costs will vary depending on the actual equipment
     costs of drilling and completing the wells, 90% of the subscription
     proceeds provided by you and the other investors will be used to pay
     intangible drilling costs and 10% will be used to pay equipment costs.
     Also, see footnote (2) to the "- Investor Capital" table, above.

(4)  Instead of contributing cash for the leases, the managing general partner
     will assign to each partnership the leases covering the acreage on which
     that partnership's wells will be drilled as set forth in footnote (4) to
     the "- Managing General Partner Capital" table above.

                                  COMPENSATION

The items of compensation to be paid to the managing general partner and its
affiliates from each partnership are set forth below. Most of these items of
compensation depend on how many wells a partnership drills and how much of the
working interest in each of the wells is owned by the partnership. In this
regard, the managing general partner estimates that approximately eight gross
wells, which will be approximately seven net wells, will be drilled if the
minimum required subscription proceeds of $2 million are received by a
partnership, and approximately 777 gross wells, which will be approximately 710
net wells, will be drilled, in the aggregate, if subscription proceeds of $200
million are received by a partnership or the partnerships.

A gross well is a well in which a partnership owns a working interest. This is
compared with a net well, which is the sum of the fractional working interests
owned in the gross wells. For example, a 50% working interest owned in three
wells is three gross wells, but 1.5 net wells. However, the managing general
partner's estimated number of wells to be drilled by a partnership or the
partnerships is subject to risks that can cause the actual number of wells
drilled by a partnership or the partnerships to vary from the managing general
partner's estimate. (See "Risk Factors - Risks Related to an Investment in a
Partnership - The Partnerships Do Not Own Any Prospects, the Managing General
Partner Has Complete Discretion to Select Which Prospects are Acquired By a
Partnership, and The Possible Lack of Information for a Majority of the
Prospects Decreases Your Ability to Evaluate the Feasibility of a Partnership.")


                                       29

<PAGE>

NATURAL GAS AND OIL REVENUES

Subject to the managing general partner's subordination obligation, the
investors and the managing general partner will share in each partnership's
revenues in the same percentages as their respective capital contributions bear
to the total partnership capital contributions for that partnership except that
the managing general partner will receive an additional 7% of that partnership's
revenues. However, the managing general partner's total revenue share may not
exceed 40% of that partnership's revenues regardless of the amount of its
capital contribution.

For example, if the managing general partner contributes the minimum of 25% of
the partnership's total capital contributions and the investors contribute 75%
of the partnership's total capital contributions, then the managing general
partner will receive 32% of the partnership's revenues and the investors will
receive 68% of the partnership's revenues. On the other hand, if the managing
general partner contributes 35% of the partnership's total capital contributions
and the investors contribute 65% of the partnership's total capital
contributions, then the managing general partner will receive 40% of the
partnership's revenues, not 42%, because its revenue share cannot exceed 40% of
the partnership's revenues, and the investors will receive 60% of the
partnership's revenues.

As noted above, up to 50% of the managing general partner's revenue share from
each partnership is subject to its subordination obligation as described in
"Participation in Costs and Revenues - Subordination of Portion of Managing
General Partner's Net Revenue Share" and the accompanying tables. For example,
if the managing general partner's revenue share is 35% of the partnership's
revenues, then up to 17.5% of the managing general partner's partnership net
production revenues could be used for its subordination obligation.

LEASE COSTS

Under the partnership agreement the managing general partner will contribute to
each partnership all the undeveloped leases necessary to cover each of the
partnership's prospects. The managing general partner will receive a credit to
its capital account equal to:

     o    the cost of the leases; or

     o    the fair market value of the leases if the managing general partner
          has reason to believe that cost is materially more than the fair
          market value.

In the primary drilling areas, the managing general partner's lease costs are
approximately $11,310 per prospect assuming a partnership acquires 100% of the
working interest in the prospect. The cost of the leases includes a portion of
the managing general partner's reasonable, necessary and actual expenses for
geological, engineering, drafting, accounting, legal and other like services
allocated to the leases in conformity with generally accepted accounting
principles and industry standards. Also, the managing general partner has
averaged the cost of all of its leases to arrive at the average lease cost of
$11,310 per prospect, which the managing general partner believes is less than
fair market value. Notwithstanding, from time to time, the managing general
partner's lease costs on a prospect may be significantly higher than this
amount, and in that event the managing general partner's credit to its capital
contribution to the partnership and its capital account under the partnership
agreement will be the greater amount.

The managing general partner's credit for its lease costs for a prospect will be
proportionally reduced to the extent a partnership acquires less than 100% of
the working interest in the prospect. In this regard, a working interest
generally means an interest in the lease under which the owner of the working
interest must pay some portion of the cost of development, operation, or
maintenance of the well. Assuming all the leases are situated in the primary
areas, the managing general partner estimates that its total credit for lease
costs will be:

     o    $79,170 if subscription proceeds of $2 million are received, which is
          seven net wells times $11,310 per prospect; and

     o    $8,030,100 if subscription proceeds of $200 million are received,
          which is 710 net wells times $11,310 per prospect.


                                       30

<PAGE>

Drilling a partnership's wells also may provide the managing general partner
with offset prospects to be drilled by allowing it to determine at the
partnership's expense the value of adjacent acreage in which the partnership
would not have any interest. Further, the managing general partner may drill
wells on leases that are scheduled to expire in order to prevent the expiration
of the lease.

DRILLING CONTRACTS

Each partnership will enter into the drilling and operating agreement with the
managing general partner to drill and complete each partnership's wells for an
amount equal to the sum of the following items: (i) the cost of permits,
supplies, materials, equipment, and all other items used in the drilling and
completion of a well provided by third-parties, or if the foregoing items are
provided by affiliates of the managing general partner, then those items will be
charged at competitive rates; (ii) fees for third-party services; (iii) fees for
services provided by the managing general partner's affiliates, which will be
charged at competitive rates; (iv) an administration and oversight fee of
$15,000 per well, which will be charged to you and the other investors as part
of each well's intangible drilling costs and the portion of equipment costs paid
by you and the other investors; and (v) a mark-up in an amount equal to 15% of
the sum of (i), (ii), (iii) and (iv), above, for the managing general partner's
services as general drilling contractor.

The managing general partner has determined that this is a competitive rate
based on:

     o    information it has concerning drilling rates of third-party operators
          in the Appalachian Basin;

     o    the estimated costs of non-affiliated persons to drill and equip wells
          in the Appalachian Basin as reported for 2004 by an independent
          industry association that surveyed operators in the area, including
          the managing general partner and its affiliates; and

     o    information it has concerning increases in drilling costs in the area
          since 2004.

If this rate subsequently exceeds competitive rates available from
non-affiliated persons in the area engaged in the business of rendering or
providing comparable services or equipment, then the rate will be adjusted to
the competitive rate. Additionally, the 15% mark-up and the managing general
partner's administration and oversight fee in the amount of $15,000 per well
will not be increased by the managing general partner during the term of the
partnership.

The managing general partner expects to subcontract some of the actual drilling
and completion of each partnership's wells to third-parties selected by it as
well as to its affiliates. The managing general partner may not benefit by
interpositioning itself between the partnership and the actual provider of
drilling contractor services, and may not profit by drilling in contravention of
its fiduciary obligations to the partnership. However, the managing general
partner's affiliates may charge a competitive rate if they meet the requirements
described in "Conflicts of Interest - Conflicts Regarding Transactions with the
Managing General Partner and its Affiliates."

The cost of each partnership well includes all of the ordinary costs of
drilling, testing and completing the well. This includes the cost of the
following items with respect to each natural gas well, which will be the
classification of the majority of the wells:

     o    multiple completions, which generally means treating separately all
          potentially productive geological formations in an attempt to enhance
          the natural gas production from the well;

     o    installing gathering lines of up to 2,500 feet per well to connect the
          well's natural gas production to a pipeline; and

     o    the necessary surface facilities for producing natural gas from the
          well.

The amount paid to the managing general partner for drilling and completing a
partnership well will be proportionately reduced to the extent the partnership
acquires less than 100% of the working interest in the prospect. In addition,
the amount


                                       31

<PAGE>

of compensation that the managing general partner could earn as a result of
these arrangements depends on many other factors as well, including the
following:

     o    where the wells are drilled and their depths;

     o    the method used to complete the well; and

     o    the number of wells drilled.

Assuming the maximum subscription proceeds of $200 million are received, the
managing general partner anticipates that the partnerships' weighted average
cost of drilling and completing approximately 710 net wells and 777 gross wells,
excluding lease costs, will be approximately $339,128 per net well, which
includes the administration and oversight fee of $15,000 per well (included as
part of the intangible drilling costs and the portion of the equipment costs of
the well charged to the investors) and the 15% mark-up per well paid to the
managing general partner for its services as general drilling contractor. This
estimate also was based on the managing general partner's estimate of:

     o    the number of wells that will be drilled in each area by the
          partnerships;

     o    the percentage of working interest that the partnerships will acquire
          in the prospects in each area; and

     o    the estimated drilling and completion costs of the wells to be drilled
          by the partnerships, which are different for wells in each area,
          primarily because of different depths of the wells and different
          completion methods.

Thus, the managing general partner's estimated weighted average cost of drilling
and completing one net well as set forth above, in all likelihood, will vary
from the actual average cost of the wells in each of the primary areas and for a
partnership's wells as a whole.

Based on the assumptions and the estimated weighted average cost for one net
well as set forth above, the managing general partner expects that its 15%
mark-up will be approximately $42,254 per net well with respect to the
intangible drilling costs and the portion of equipment costs paid by you and the
other investors. The actual compensation received by the managing general
partner as a result of each partnership's drilling operations will vary from
these estimates, and the managing general partner anticipates that the
partnerships will acquire less than 100% of the working interest in some of
their respective prospects.

Subject to the foregoing, the managing general partner estimates that its
administration and oversight fee of $15,000 and its 15% mark-up of approximately
$42,254 for one net well, which totals $57,254 per net well, will be:

     o    $400,778 if subscription proceeds of $2 million are received, which is
          seven net wells times $57,254; and

     o    $40,650,340 if subscription proceeds of $200 million are received,
          which is 710 net wells times $57,254.

Additionally, affiliates of the general partner will provide subcontracting
services, equipment and materials in drilling, completing or operating the
partnership's wells for which they will receive competitive rates, because they
meet the requirements described in "Conflicts of Interest - Conflicts Regarding
Transactions with the Managing General Partner and its Affiliates." Thus, the
total compensation paid to the managing general partner and its affiliates per
net well will be greater than the estimated amount to be paid to the managing
general partner as described above to the extent compensation is paid by the
partnerships to the managing general partner's affiliates for services,
equipment or supplies they provide to the partnerships.

The managing general partner's estimated weighted average cost of $339,128 for
one net well to be drilled by a partnership as discussed above consists of:

     o    intangible drilling costs of approximately $253,521 (75%); and


                                       32

<PAGE>

     o    equipment costs of approximately $85,607 (25%).

The managing general partner further anticipates that a partnership's cost of
drilling and completing any given well in the primary areas as described in
"Proposed Activities," excluding lease costs, may be considerably more or less
than the average weighted cost of approximately $339,128 to drill and complete
one net well, excluding lease costs, depending primarily on the area where the
well is situated, the partnership's percentage ownership of the working interest
in the well and unanticipated cost overruns.

PER WELL CHARGES

Under the drilling and operating agreement the managing general partner, as
operator of the wells, will receive the following compensation from each
partnership when the wells begin producing natural gas or oil:

     o    reimbursement at actual cost for all direct expenses incurred on
          behalf of the partnership; and

     o    well supervision fees at a competitive rate for operating and
          maintaining the wells during producing operations.

Currently the competitive rate for well supervision fees is $362 per well per
month in the primary and secondary areas discussed in "Proposed Activities." The
well supervision fees will be proportionately reduced to the extent the
partnership acquires less than 100% of the working interest in the well. Also,
the managing general partner's well supervision fees may be adjusted annually
beginning with the first calendar year after a partnership closes for inflation
since January 1, 2007. If the managing general partner's well supervision fee
would exceed a competitive rate in the area where the well is situated, then the
rate will be adjusted to the competitive rate. Conversely, if in the future the
managing general partner's well supervision fee set forth above would be less
than a competitive rate in the area where the well is situated, then regardless
of the inflation adjustment, the rate may be increased automatically to the
competitive rate from time to time by the managing general partner, as operator,
as determined in its sole discretion. The managing general partner may not
benefit by interpositioning itself between the partnership and the actual
provider of operator services. In no event will any consideration received for
operator services be duplicative of any consideration or reimbursement received
under the partnership agreement.

The well supervision fee covers all normal and regularly recurring operating
expenses for the production, delivery, and sale of natural gas and oil, such as:

     o    well tending, routine maintenance, and adjustment;

     o    reading meters, recording production, pumping, maintaining appropriate
          books and records; and

     o    preparing reports to the partnership and to government agencies.

The well supervision fees do not include costs and expenses related to: o the
purchase of equipment, materials, or third-party services;

     o    brine disposal; and

     o    rebuilding of access roads.

These costs will be charged to a partnership at the invoice cost of the
materials purchased or the third-party services performed.

The managing general partner estimates that it will receive well supervision
fees for a partnership's first 12 months of operation after all of the wells
have been placed in production of:


                                       33

<PAGE>

     o    $30,408 if subscription proceeds of $2 million are received, which is
          seven net wells at $362 per well per month; and

     o    $3,084,240 if subscription proceeds of $200 million are received,
          which is 710 net wells at $362 per well per month.

GATHERING FEES

Under the partnership agreement the managing general partner will be responsible
for gathering and transporting the natural gas produced by the partnerships to
interstate pipeline systems, local distribution companies, and/or end-users in
the area (the "gathering services"). The managing general partner anticipates
that it will use the gathering system owned by Atlas Pipeline Partners for the
majority of the partnerships' natural gas production as described in "Proposed
Activities - Sale of Natural Gas and Oil Production - Gathering of Natural Gas."
The managing general partner's affiliate, Atlas America, Inc., which is
sometimes referred to in this prospectus as "Atlas America," or another
affiliate controls and manages the gathering system for Atlas Pipeline Partners.
(See "Management - Organizational Diagram and Security Ownership of Beneficial
Owners.") Also, Atlas America and the managing general partner's affiliates,
Resource Energy, LLC, sometimes referred to in this prospectus as "Resource
Energy," and Viking Resources LLC, sometimes referred to in this prospectus as
"Viking Resources," which are sometimes referred to collectively in this
prospectus as the "Atlas Entities," which do not include the partnerships, have
an agreement with Atlas Pipeline Partners under which generally all of the gas
produced by their affiliated partnerships, which does include the partnerships,
will be gathered and transported through the gathering system owned by Atlas
Pipeline Partners, and that the Atlas Entities must pay the greater of $.35 per
mcf or 16% of the gross sales price for each mcf transported by these affiliated
partnerships through Atlas Pipeline Partners' gathering system. Gross sales
price means the price that is actually received, adjusted to take into account
proceeds received or payments made pursuant to hedging arrangements. Subject to
the agreement with Atlas Pipeline Partners described above, in providing the
gathering services the managing general partner may use gathering systems owned
by Atlas Pipeline Partners, independent third-parties and/or affiliates of Atlas
America other than Atlas Pipeline Partners.

Each partnership will pay a gathering fee directly to the managing general
partner at competitive rates for the gathering services. The gathering fee paid
by the partnership to the managing general partner may be increased from
time-to-time by the managing general partner, in its sole discretion, but may
not be increased beyond competitive rates as determined by the managing general
partner. Currently, the managing general partner has determined that the
competitive rate in each of its primary and secondary areas where it drills its
wells as described in "Proposed Activities" is an amount equal to 10% of the
gross sales price received by each partnership for its natural gas.

The payment of a competitive fee to the managing general partner for its
gathering services shall be subject to the following conditions:

     o    If the gathering system owned by Atlas Pipeline Partners is used by a
          partnership, then the managing general partner will apply the
          gathering fee it receives from the partnership towards the payments
          owed by the Atlas Entities under their agreement with Atlas Pipeline
          Partners.

     o    If a third-party gathering system is used by a partnership, the
          managing general partner will pay a portion or all of the gathering
          fee it receives from the partnership to the third-party gathering the
          natural gas. The managing general partner may retain the excess of any
          gathering fees it receives from the partnership over the payments it
          makes to third-party gas gatherers. If the third-party's gathering
          system charges more than an amount equal to 10% of the gross sales
          price, then the managing general partner's gathering fee charged to a
          partnership will be the actual transportation and compression fees
          charged by the third-party gathering system with respect to the
          partnership's natural gas in the area.

     o    If both a third-party gathering system and the Atlas Pipeline Partners
          gathering system (or a gas gathering system owned by an affiliate of
          Atlas America other than Atlas Pipeline Partners) are used by a
          partnership, then the managing general partner will receive an amount
          equal to 10% of the gross sales price plus the amount charged by the
          third-party gathering system. For purposes of illustration, but not
          limitation, certain


                                       34

<PAGE>

          wells drilled by a partnership in the Upper Devonian Sandstone
          Reservoirs in the McKean County, Pennsylvania secondary area will
          deliver natural gas produced in this area into a gathering system, a
          segment of which will be provided by Atlas Pipeline Partners and a
          segment of which will be provided by a third-party. In this area, the
          managing general partner's competitive gathering fee will include the
          third-party's fee of $.35 per mcf for transportation and compression,
          including any increase in the fee by the third-party gatherer from
          time-to-time, which it will then pay to the third-party gatherer, and
          the managing general partner will also receive a gathering fee equal
          to 10% of the gross sales price.

Finally, in connection with the Knox project in the Mississippian and Devonian
Shale Reservoirs in the Anderson, Campbell, Morgan, Roane and Scott Counties,
Tennessee area, as discussed in "Proposed Activities - Primary Areas of
Operations - Mississippian Carbonate and Devonian Shale Reservoirs in Anderson,
Campbell, Morgan, Roane and Scott Counties, Tennessee," a partnership will
deliver natural gas into a gathering system provided by Knox Energy, which is
referred to as the Coalfield Pipeline. The Coalfield Pipeline will receive
gathering fees of $.55 per mcf plus fees for compression, which it may increase
from time-to-time. If the Coalfield Pipeline does not have sufficient capacity
to compress and transport the natural gas produced from a partnership's wells as
determined by Atlas America, then Atlas America or an affiliate other than Atlas
Pipeline Partners may construct an additional gathering system and/or
enhancements to the Coalfield Pipeline. On completion of the construction, Atlas
America will transfer its ownership in the additional gathering system and/or
enhancements to the owners of the Coalfield Pipeline, which will then pay Atlas
America an amount equal to $.12 per mcf of natural gas transported through the
newly constructed and/or enhanced gathering system. If the events described
above occur, Coalfield Pipeline will pay this amount to Atlas America from the
gathering and compression fees it charges to a partnership. The managing general
partner's gathering fee in this area also will be 10% of the gross sales price
of the partnership's natural gas, but will be increased to include the amount of
the Coalfield Pipeline fees, if greater, which the managing general partner will
then pay to the Coalfield Pipeline.

The actual amount of gathering fees to be paid by a partnership to the managing
general partner cannot be quantified, because the volume of natural gas that
will be produced and transported from the partnership's wells cannot be
predicted.

DEALER-MANAGER FEES

Subject to certain exceptions described in "Plan of Distribution," Anthem
Securities, the dealer-manager and an affiliate of the managing general partner,
will receive on each unit sold to an investor:

     o    a 2.5% dealer-manager fee;

     o    a 7% sales commission; and

     o    an up to .5% reimbursement of the selling agents' bona fide due
          diligence expenses.

Assuming the above amounts are paid for all units sold, the dealer-manager will
receive:

     o    $200,000 if subscription proceeds of $2 million are received by a
          partnership; and

     o    $20 million if subscription proceeds of $200 million are received by
          the partnerships.

All of the reimbursement of the selling agents' bona fide due diligence
expenses, and generally all of the sales commissions, will be reallowed to the
selling agents. A portion of the 2.5% dealer-manager fee will be reallowed to
the wholesalers who are associated with the managing general partner and
registered through Anthem Securities for subscriptions obtained through their
efforts. Also, a portion of the dealer-manager fee may be reallowed to the
selling agents as described in "Plan of Distribution." The dealer-manager will
retain any of the compensation which is not reallowed. See "Management" for the
ownership of Anthem Securities.

INTEREST AND OTHER COMPENSATION

The managing general partner or an affiliate will have the right to charge a
competitive rate of interest on any loan it may make to or on behalf of a
partnership. If the managing general partner provides equipment, supplies, and
other services to a


                                       35

<PAGE>

partnership, then it may do so at competitive industry rates. The managing
general partner will determine competitive industry rates for equipment,
supplies and other services by conducting a survey of the interest and/or fees
charged by unaffiliated third-parties in the same geographic area engaged in
similar businesses. If possible, the managing general partner will contact at
least two unaffiliated third-parties, however, the managing general partner will
have sole discretion in determining the amount to be charged a partnership.

ESTIMATE OF ADMINISTRATIVE COSTS AND DIRECT COSTS TO BE BORNE BY THE
PARTNERSHIPS

The managing general partner and its affiliates will receive from each
partnership a nonaccountable, fixed payment reimbursement for their
administrative costs, which has been determined by the managing general partner
to be $75 per well per month. This payment per well is subject to the following:

     o    it will not be increased in amount during the term of the partnership;

     o    it will be proportionately reduced to the extent the partnership
          acquires less than 100% of the working interest in the well;

     o    it will be the entire payment to reimburse the managing general
          partner for the partnership's administrative costs; and

     o    it will not be received for plugged or abandoned wells.

The managing general partner estimates that the nonaccountable, fixed payment
reimbursement for administrative costs allocable to a partnership's first 12
months of operation after all of its wells have been placed into production will
not exceed approximately:

     o    $6,300 if subscription proceeds of $2 million are received, which is
          seven net wells at $75 per well per month; and

     o    $639,000 if subscription proceeds of $200 million are received, which
          is 710 net wells at $75 per well per month.

Direct costs will be determined by the managing general partner, in its sole
discretion, including the provider of the services or goods and the amount of
the provider's compensation. Direct costs will be billed directly to and paid by
each partnership to the extent practicable. The anticipated direct costs set
forth below for a partnership's first 12 months of operation after all of its
wells have been placed into production may vary from the estimates shown for
numerous reasons that cannot accurately be predicted. These reasons include:

     o    the number of the partnership's investors;

     o    the number of wells drilled by the partnership;

     o    the partnership's degree of success in its activities;

     o    the extent of any production problems encountered by the partnership;

     o    inflation; and

     o    various other factors involving the administration of the partnership.


                                       36

<PAGE>

<TABLE>
<CAPTION>
                                                          Minimum            Maximum
                                                       Subscriptions      Subscriptions
                                                       of $2 million   of $200 million (1)
                                                       -------------   -------------------
<S>                                                       <C>                <C>
DIRECT COSTS
   External Legal ..................................      $ 6,000            $ 24,000
   Accounting Fees for Audit and Tax Preparation ...       25,000             150,000
   Independent Engineering Reports .................        1,500              40,000
                                                          -------            --------
   TOTAL ...........................................      $32,500            $214,000
                                                          =======            ========
</TABLE>

----------
(1)  This assumes two partnerships are formed as described below in "Terms of
     the Offering - Subscription to a Partnership" and the targeted nonbinding
     subscriptions of each partnership are received.

                              TERMS OF THE OFFERING

SUBSCRIPTION TO A PARTNERSHIP

Atlas America Public #16-2007 Program was formed to offer for sale an aggregate
of $200 million of units in a series of up to two limited partnerships, each of
which has been formed under the Delaware Revised Uniform Limited Partnership
Act.

The targeted subscriptions for each partnership are set forth below. These
targeted amounts are not mandatory, and the managing general partner may
determine the final subscription amount for each partnership in its sole
discretion. The maximum subscription of any partnership, however, must be the
lesser of:

     o    $200 million; or

     o    $200 million less the total subscription proceeds received by any
          prior partnership in the program.

Also, set forth below are the targeted ending dates for each partnership, which
are not binding except that the units in each partnership may not be offered
beyond that partnership's offering termination date as set forth below. The
managing general partner may close the offering of units in a partnership at any
time before that partnership's offering termination date once the partnership is
in receipt of the minimum required subscriptions, and the managing general
partner may withdraw the offering of units in any partnership at any time.

<TABLE>
<CAPTION>
                                     REQUIRED       TARGETED       TARGETED      OFFERING
                                      MINIMUM     SUBSCRIPTION      ENDING     TERMINATION
PARTNERSHIP NAME                   SUBSCRIPTION     PROCEEDS     DATE (1)(2)   DATE (1)(2)
--------------------------------   ------------   ------------   -----------   -----------
<S>                                <C>            <C>              <C>           <C>
Atlas America Public #16-2007(A)   $2 million     $100 million     06/30/07      12/31/07
Atlas America Public #16-2007(B)   $2 million     $100 million     12/31/07      12/31/07
</TABLE>

----------
(1)  The units in the above partnerships will be offered and sold only during
     2007.

(2)  Units in Atlas America Public #16-2007(B) L.P. will not be offered until
     the offering of units in Atlas America Public #16-2007(A) L.P. has
     terminated.

Units are offered at a subscription price of $10,000 per unit, subject to
certain exceptions described in "Plan of Distribution," and must be paid 100% in
cash at the time of subscribing. The subscription price of the units has been
arbitrarily determined by the managing general partner because the partnerships
do not have any prior operations, assets, earnings, liabilities or present
value. Your minimum subscription is one unit ($10,000). Larger fractional
subscriptions will be accepted in $1,000 increments, beginning with $11,000,
$12,000, etc.

You may elect to purchase units in a partnership as either an investor general
partner or a limited partner. However, even though you may elect to subscribe as
an investor general partner the managing general partner will have exclusive
management authority for each partnership. Each partnership will be a separate
business entity from the other partnership.


                                       37

<PAGE>

Thus, as an investor, you will be a partner only in the partnership in which you
invest. You will have no interest in the business, distributions, assets or tax
benefits of the other partnership unless you also invest in the other
partnership. Your investment return will depend solely on the operations and
success or lack of success of the particular partnership in which you invest.

PARTNERSHIP CLOSINGS AND ESCROW

You and the other investors should make your checks for units payable to "Atlas
America Public #16-2007(A) L.P., Escrow Agent, National City Bank of PA" or
"Atlas America Public #16-2007(B) L.P., Escrow Agent, National City Bank of PA,"
depending on which partnership is then being offered at the time you subscribe
for units, and give your check to your broker/dealer for submission to the
dealer-manager and escrow agent. Subscription proceeds for each partnership will
be held in a separate interest bearing escrow account at National City Bank of
Pennsylvania until each partnership has received subscription proceeds of at
least $2 million, excluding the subscription price discounts described in "Plan
of Distribution" and excluding any subscriptions by the managing general partner
or its affiliates. However, on receipt of the minimum subscription proceeds and
written instructions to the escrow agent from the managing general partner and
the dealer-manager, the managing general partner on behalf of a partnership may
break escrow and transfer the escrowed subscription proceeds to a partnership
account, enter into the drilling and operating agreement with itself or an
affiliate as operator, and begin drilling operations for the partnership.

If the minimum subscription proceeds are not received by the offering
termination date of a partnership, then the subscription proceeds deposited in
the escrow account will be promptly returned to you and the other subscribers in
that partnership with interest and without deduction for any fees. In this
regard, the latest offering termination date for each partnership is December
31, 2007. Although the managing general partner and its affiliates may buy up to
5% of the total units sold in this offering, currently they do not anticipate
purchasing any units. If they do buy units, then those units will not be applied
towards the minimum subscription proceeds required for a partnership to break
escrow and begin operations. Also, any units purchased by the managing general
partner and its affiliates must be purchased for investment purposes only, and
not with a view toward redistribution.

You will receive interest on your subscription proceeds from the time they are
deposited in the escrow account, or the partnership account if you subscribe
after the minimum subscription proceeds have been received and escrow has been
broken, until the final closing of the offering period for the partnership to
which you subscribed. The interest will be paid to you not later than your
partnership's first cash distribution from operations.

During each partnership's escrow period its subscription proceeds will be
invested only in institutional investments comprised of, or secured by,
securities of the United States government. After the funds are transferred to a
partnership account and before their use in partnership operations, they may be
temporarily invested in income producing short-term, highly liquid investments,
in which there is appropriate safety of principal, such as U.S. Treasury Bills.
If the managing general partner determines that a partnership may be deemed to
be an investment company under the Investment Company Act of 1940, then the
investment activity will cease. Subscription proceeds will not be commingled
with the funds of the managing general partner or its affiliates, nor will
subscription proceeds be subject to their creditors' claims, before they are
paid to the managing general partner under the drilling and operating agreement.

ACCEPTANCE OF SUBSCRIPTIONS

Your execution of the subscription agreement constitutes your offer to buy units
in the partnership then being offered and to hold the offer open until either:

o    your subscription is accepted or rejected by the managing general partner;
     or

o    you withdraw your offer.

To rescind or withdraw your subscription agreement, you must give written notice
to the managing general partner before your subscription agreement is accepted
by the managing general partner.

Also, the managing general partner will:


                                       38

<PAGE>

     o    not complete a sale of units to you until at least five business days
          after the date you receive a final prospectus; and

     o    send you a confirmation of purchase.

Subject to the foregoing, your subscription agreement will be accepted or
rejected by the partnership within 30 days of its receipt. The managing general
partner's acceptance of your subscription is discretionary, and the managing
general partner may reject your subscription for any reason without incurring
any liability to you for this decision. If your subscription is rejected, then
all of your funds will be promptly returned to you together with any interest
earned on your subscription proceeds and without deduction for any fees.

When you will be admitted to a partnership depends on whether your subscription
is accepted before or after a partnership breaks escrow. If your subscription is
accepted:

     o    before breaking escrow, then you will be admitted to the partnership
          to which you subscribed not later than 15 days after the release from
          escrow of the investors' subscription proceeds to that partnership; or

     o    after breaking escrow, then you will be admitted to the partnership to
          which you subscribed not later than the last day of the calendar month
          in which your subscription was accepted by that partnership.

Your execution of the subscription agreement and the managing general partner's
acceptance also constitutes your:

     o    execution of the partnership agreement and agreement to be bound by
          its terms as a partner; and

     o    grant of a special power of attorney to the managing general partner
          to file amended certificates of limited partnership and governmental
          reports, and perform certain other actions on behalf of you and the
          other investors as partners of a partnership.

SUITABILITY STANDARDS

IN GENERAL. It is the obligation of persons selling the units to make every
reasonable effort to assure that the units are suitable for you based on your
investment objectives and financial situation, regardless of your income or net
worth. However, you should invest in a partnership only if you are willing to
assume the risk of a speculative, illiquid, and long-term investment. Also,
subscriptions to a partnership will not be accepted from IRAs, Keogh plans and
qualified retirement plans, because the partnership's income would be
characterized as unrelated business taxable income, which is subject to federal
income tax.

The decision to accept or reject your subscription will be made by the managing
general partner, in its sole discretion, and is final. The managing general
partner will not accept your subscription until it has reviewed your apparent
qualifications, and the suitability determination must be maintained by the
managing general partner during the partnership's term and for at least six
years thereafter.

GENERAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF LIMITED PARTNER UNITS. If you
are a resident of any of the following states or jurisdictions:


                                       39

<PAGE>

     o    ALABAMA,

     o    ALASKA,

     o    ARIZONA,

     o    ARKANSAS,

     o    COLORADO,

     o    CONNECTICUT,

     o    DELAWARE,

     o    DISTRICT OF COLUMBIA,

     o    FLORIDA,

     o    GEORGIA,

     o    HAWAII,

     o    IDAHO,

     o    ILLINOIS,

     o    INDIANA,

     o    IOWA,

     o    KANSAS,

     o    KENTUCKY,

     o    LOUISIANA,

     o    MAINE,

     o    MARYLAND,

     o    MASSACHUSETTS,

     o    MINNESOTA,

     o    MISSISSIPPI,

     o    MISSOURI,

     o    MONTANA,

     o    NEBRASKA,

     o    NEVADA,

     o    NEW MEXICO,

     o    NEW YORK,

     o    NORTH DAKOTA,

     o    OKLAHOMA,

     o    OREGON,

     o    PENNSYLVANIA,

     o    RHODE ISLAND,

     o    SOUTH CAROLINA,

     o    SOUTH DAKOTA,

     o    TENNESSEE,

     o    TEXAS,

     o    UTAH,

     o    VERMONT,

     o    VIRGINIA,

     o    WASHINGTON,

     o    WEST VIRGINIA,

     o    WISCONSIN, OR

     o    WYOMING,

then limited partner units may be sold to you if you meet either of the
following requirements:

     o    a minimum net worth of $225,000, exclusive of home, home furnishings,
          and automobiles; or

     o    a minimum net worth of $60,000, exclusive of home, home furnishings,
          and automobiles, and had during the last tax year or estimate that you
          will have during the current tax year "taxable income" as defined in
          Section 63 of the Internal Revenue Code of at least $60,000, without
          regard to an investment in the partnership.

In addition, if you are a resident of PENNSYLVANIA, then you must not make an
investment in a partnership which is in excess of 10% of your net worth,
exclusive of home, home furnishings and automobiles. Finally, if you are a
resident of KANSAS, it is recommended by the Office of the Kansas Securities
Commissioner that Kansas investors should limit their investment in the program
and substantially similar programs to no more than 10% of their net worth,
excluding home, furnishings and automobiles.

However, if you are a resident of the states set forth below, then different
suitability requirements apply to you.

SPECIAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF LIMITED PARTNER UNITS.

     o    If you are a resident of CALIFORNIA or NEW JERSEY and you subscribe
          for limited partner units, then you must meet any one of the following
          special suitability requirements:

          o    a net worth of not less than $250,000, exclusive of home, home
               furnishings, and automobiles, and expect to have gross income in
               the current tax year of $65,000 or more; or


                                       40

<PAGE>

          o    a net worth of not less than $500,000, exclusive of home, home
               furnishings, and automobiles; or

          o    a net worth of not less than $1 million; or

          o    expected gross income in the current tax year of not less than
               $200,000.

     o    If you are a resident of MICHIGAN or NORTH CAROLINA and you subscribe
          for limited partner units, then you must meet either of the following
          special suitability requirements:

          o    a net worth of not less than $225,000, exclusive of home, home
               furnishings, and automobiles; or

          o    a net worth of not less than $60,000, exclusive of home, home
               furnishings, and automobiles, and estimated current tax year
               taxable income as defined in Section 63 of the Internal Revenue
               Code of $60,000 or more without regard to an investment in the
               partnership.

          Additionally, if you are a resident of MICHIGAN, then you must not
          make an investment in a partnership which is in excess of 10% of your
          net worth, exclusive of home, home furnishings and automobiles.

     o    If you are a resident of NEW HAMPSHIRE and you subscribe for limited
          partner units, then you must meet either of the following special
          suitability requirements:

          o    a net worth of not less than $250,000, exclusive of home, home
               furnishings, and automobiles; or

          o    a net worth of not less than $125,000, exclusive of home, home
               furnishings, and automobiles and $50,000 of taxable income.

     o    If you are a resident of OHIO and you subscribe for limited partner
          units, then you must meet, without regard to your investment in a
          partnership, either of the following special suitability requirements:

          o    a net worth of not less than $330,000, exclusive of home, home
               furnishings, and automobiles; or

          o    a net worth of not less than $85,000, exclusive of home, home
               furnishings, and automobiles, and an annual gross income during
               the current tax year of at least $85,000.

          Additionally, if you are a resident of OHIO you must not make an
          investment in a partnership which would, after including your previous
          investments in prior Atlas Resources programs, if any, and any other
          similar natural gas and oil drilling programs, exceed 10% of your net
          worth, exclusive of home, home furnishings and automobiles.

GENERAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF INVESTOR GENERAL PARTNER
UNITS. If you are a resident of any of the following states or jurisdictions:


                                       41

<PAGE>

     o    ALASKA,

     o    COLORADO,

     o    CONNECTICUT,

     o    DELAWARE,

     o    DISTRICT OF COLUMBIA,

     o    FLORIDA,

     o    GEORGIA,

     o    HAWAII,

     o    IDAHO,

     o    ILLINOIS,

     o    LOUISIANA,

     o    MARYLAND,

     o    MONTANA,

     o    NEBRASKA,

     o    NEVADA,

     o    NEW YORK,

     o    NORTH DAKOTA,

     o    RHODE ISLAND,

     o    SOUTH CAROLINA,

     o    UTAH,

     o    VIRGINIA,

     o    WEST VIRGINIA,

     o    WISCONSIN, OR

     o    WYOMING,

then investor general partner units may be sold to you if you meet either of the
following requirements:

     o    a minimum net worth of $225,000, exclusive of home, home furnishings,
          and automobiles; or

     o    a minimum net worth of $60,000, exclusive of home, home furnishings,
          and automobiles, and had during the last tax year or estimate that you
          will have during the current tax year "taxable income" as defined in
          Section 63 of the Internal Revenue Code of at least $60,000, without
          regard to an investment in the partnership.

However, if you are a resident of the states set forth below, then different
suitability requirements apply to you if you purchase investor general partner
units.

SPECIAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF INVESTOR GENERAL PARTNER
UNITS.

     o    If you are a resident of any of the following states:

          o    ALABAMA,

          o    ARKANSAS,

          o    INDIANA,

          o    MAINE,

          o    MASSACHUSETTS,

          o    MINNESOTA,

          o    NORTH CAROLINA,

          o    OKLAHOMA,

          o    PENNSYLVANIA,

          o    TENNESSEE,

          o    TEXAS, OR

          o    WASHINGTON

          and you subscribe for investor general partner units, then you must
          meet any one of the following special suitability requirements:

          o    an individual or joint net worth with your spouse of $225,000 or
               more, without regard to the investment in the partnership,
               exclusive of home, home furnishings, and automobiles, and A
               COMBINED GROSS INCOME OF $100,000 OR MORE FOR THE CURRENT YEAR
               AND FOR THE TWO PREVIOUS YEARS; or

          o    an individual or joint net worth with your spouse in excess of $1
               million, inclusive of home, home furnishings, and automobiles; or

          o    an individual or joint net worth with your spouse in excess of
               $500,000, exclusive of home, home furnishings, and automobiles;
               or


                                       42

<PAGE>

          o    a combined "gross income" as defined in Internal Revenue Code
               Section 61 in excess of $200,000 in the current year and the two
               previous years.

          o    In addition, if you are a resident of PENNSYLVANIA, then you must
               not make an investment in a partnership which is in excess of 10%
               of your net worth, exclusive of home, home furnishings, and
               automobiles.

     o    If you are a resident of any of the following states:

          o    ARIZONA,

          o    IOWA,

          o    KANSAS,

          o    KENTUCKY,

          o    MICHIGAN,

          o    MISSISSIPPI,

          o    MISSOURI,

          o    NEW MEXICO,

          o    OREGON,

          o    SOUTH DAKOTA, OR

          o    VERMONT

          and you subscribe for investor general partner units, then you must
          meet any one of the following special suitability requirements:

          o    an individual or joint net worth with your spouse of $225,000 or
               more, without regard to the investment in the partnership,
               exclusive of home, home furnishings, and automobiles, and A
               COMBINED "TAXABLE INCOME" OF $60,000 OR MORE FOR THE PREVIOUS
               YEAR AND EXPECT TO HAVE A COMBINED "TAXABLE INCOME" OF $60,000 OR
               MORE FOR THE CURRENT YEAR AND FOR THE SUCCEEDING YEAR; or

          o    an individual or joint net worth with your spouse in excess of $1
               million, inclusive of home, home furnishings, and automobiles; or

          o    an individual or joint net worth with your spouse in excess of
               $500,000, exclusive of home, home furnishings, and automobiles;
               or

          o    a combined "gross income" as defined in Internal Revenue Code
               Section 61 in excess of $200,000 in the current year and the two
               previous years.

          o    In addition, if you are a resident of IOWA OR MICHIGAN, then you
               must not make an investment in a partnership which is in excess
               of 10% of your net worth, exclusive of home, home furnishings,
               and automobiles.

          o    Finally, if you are a resident of KANSAS, it is recommended by
               the Office of the Kansas Securities Commissioner that Kansas
               investors should limit their investment in the program and
               substantially similar programs to no more than 10% of their net
               worth, excluding home, furnishings and automobiles.

     o    If you are a resident of CALIFORNIA or NEW JERSEY and you subscribe
          for investor general partner units, then you must meet any one of the
          following special suitability requirements:

          o    a net worth of not less than $250,000, exclusive of home, home
               furnishings, and automobiles, and expect to have gross income in
               the current tax year of $120,000 or more; or

          o    a net worth of not less than $500,000, exclusive of home, home
               furnishings, and automobiles; or

          o    a net worth of not less than $1 million; or


                                       43

<PAGE>

          o    expected gross income in the current tax year of not less than
               $200,000.

     o    If you are a resident of NEW HAMPSHIRE and you subscribe for investor
          general partner units, then you must meet either of the following
          special suitability requirements:

          o    a net worth of not less than $250,000, exclusive of home, home
               furnishings, and automobiles; or

          o    a net worth of not less than $125,000, exclusive of home, home
               furnishings, and automobiles, and $50,000 of taxable income.

     o    If you are a resident of OHIO and you subscribe for investor general
          partner units, then you must meet, without regard to your investment
          in a partnership, either of the following special suitability
          requirements:

          o    a net worth of not less than $750,000, exclusive of home, home
               furnishings, and automobiles; or

          o    a net worth of not less than $330,000, exclusive of home, home
               furnishings, and automobiles, and an annual gross income of at
               least $150,000 for the current year and the two previous years.

          Additionally, if you are a resident of OHIO you must not make an
          investment in a partnership which would, after including your previous
          investments in prior Atlas Resources programs, if any, and any other
          similar natural gas and oil drilling programs, exceed 10% of your net
          worth, exclusive of home, home furnishings and automobiles.

FIDUCIARY ACCOUNTS. If there is a sale of a unit to a fiduciary account, then
all of the suitability standards set forth above must be met by the beneficiary,
the fiduciary account, or the donor or grantor who directly or indirectly
supplies the funds to purchase the units if the donor or grantor is the
fiduciary.

Generally, you are required to execute your own subscription agreement, and the
managing general partner will not accept any subscription agreement that has
been executed by someone other than you. The only exception is if you have given
someone else the legal power of attorney to sign on your behalf and you meet all
of the conditions in this prospectus.

                                PRIOR ACTIVITIES

The following tables reflect certain historical data with respect to the private
drilling partnerships and the public drilling partnerships that the managing
general partner has sponsored. The tables also reflect certain historical data
with respect to 1999 Viking Resources LP, a private drilling program that raised
$4,555,210, and is the only drilling program sponsored by Viking Resources after
it was acquired by Resource America, Inc. in August 1999. Information concerning
this program and other programs sponsored by Viking Resources before it was
acquired by Resource America will be provided to you on written request to the
managing general partner. The tables also do not include information concerning
wells acquired by Atlas Resources through merger or other form of acquisition,
and this information also will be available to you on written request to the
managing general partner.

Although past performance is no guarantee of future results, the investor
general partners in the managing general partner's prior partnerships have not
had to make additional capital contributions to their partnerships because of
their status as investor general partners.

IT SHOULD NOT BE ASSUMED THAT YOU AND THE OTHER INVESTORS IN A PARTNERSHIP WILL
EXPERIENCE RETURNS, IF ANY, COMPARABLE TO THOSE EXPERIENCED BY INVESTORS IN THE
PRIOR DRILLING PARTNERSHIPS FOR SEVERAL REASONS, INCLUDING, BUT NOT LIMITED TO,
DIFFERENCES IN:

     o    PARTNERSHIP TERMS;

     o    PROPERTY LOCATIONS;


                                       44

<PAGE>

     o    PARTNERSHIP SIZE; AND

     o    ECONOMIC CONSIDERATIONS.

THE RESULTS OF THE PRIOR DRILLING PARTNERSHIPS SHOULD BE VIEWED ONLY AS A
MEASURE OF THE LEVEL OF ACTIVITY AND EXPERIENCE OF THE MANAGING GENERAL PARTNER
WITH RESPECT TO DRILLING PARTNERSHIPS.


                                       45

<PAGE>

Table 1 sets forth certain sales information of previous development drilling
partnerships sponsored by the managing general partner and its affiliates.

                                     TABLE 1
                           EXPERIENCE IN RAISING FUNDS
                            AS OF SEPTEMBER 15, 2006

<TABLE>
<CAPTION>
                                                                         Managing
                                             Number                      General
                                          of Original     Investor       Partner         Total
              Partnership                  Investors       Capital       Capital        Capital
---------------------------------------   -----------   ------------   -----------   ------------
<S>                                           <C>       <C>            <C>            <C>
1.    Atlas L.P. #1 - 1985                      19      $    600,000   $   114,800   $    714,800
2.    A.E. Partners 1986                        24           631,250       120,400        751,650
3.    A.E. Partners 1987                        17           721,000       158,269        879,269
4.    A.E. Partners 1988                        21           617,050       135,450        752,500
5.    A.E. Partners 1989                        21           550,000       120,731        670,731
6.    A.E. Partners 1990                        27           887,500       244,622      1,132,122
7.    A.E. Nineties-10                          60         2,200,000       484,380      2,684,380
8.    A.E. Nineties-11                          25           750,000       268,003      1,018,003
9.    A.E. Partners 1991                        26           868,750       318,063      1,186,813
10.   A.E. Nineties-12                          87         2,212,500       791,833      3,004,333
11.   A.E. Nineties-JV 92                      155         4,004,813     1,414,917      5,419,730
12.   A.E. Partners 1992                        21           600,000       176,100        776,100
13.   A.E. Nineties-Public #1                  221         2,988,960       528,934      3,517,894
14.   A.E. Nineties-1993 Ltd.                  125         3,753,937     1,264,183      5,018,120
15.   A.E. Partners 1993                        21           700,000       219,600        919,600
16.   A.E. Nineties-Public #2                  269         3,323,920       587,340      3,911,260
17.   A.E. Nineties-14                         263         9,940,045     3,584,027     13,524,072
18.   A.E. Partners 1994                        23           892,500       231,500      1,124,000
19.   A.E. Nineties-Public #3                  391         5,800,990       928,546      6,729,536
20.   A.E. Nineties-15                         244        10,954,715     3,435,936     14,390,651
21.   A.E. Partners 1995                       23            600,000       244,725        844,725
22.   A.E. Nineties-Public #4                  324         6,991,350     1,287,752      8,279,102
23.   A.E. Nineties-16                         274        10,955,465     1,643,320     12,598,785
24.   A.E. Partners 1996                        21           800,000       367,416      1,167,416
25.   A.E. Nineties-Public #5                  378         7,992,240     1,654,740      9,646,980
26.   A.E. Nineties-17                         217         8,813,488     2,113,947     10,927,435
27.   A.E. Nineties-Public #6                  393         9,901,025     1,950,345     11,851,370
28.   A.E. Partners 1997                        13           506,250       231,050        737,300
29.   A.E. Nineties-18                         225        11,391,673     3,448,751     14,840,424
30.   A.E. Nineties-Public #7                  366        11,988,350     3,812,150     15,800,500
31.   A.E. Partners 1998                        26         1,740,000       756,360      2,496,360
32.   A.E. Nineties-19                         288        15,720,450     4,776,598     20,497,048
33.   A.E. Nineties-Public #8                  380        11,088,975     3,148,181     14,237,156
34.   A.E. Partners 1999                         8           450,000       196,500        646,500
35.   1999 Viking Resources LP                 131         4,555,210     1,678,038      6,233,248
36.   Atlas America-Series 20                  361        18,809,150     6,297,945     25,107,095
37.   Atlas America - Public #9                530        14,905,465     6,256,271     21,161,736
38.   Atlas America - Series 21-A              282        12,510,713     4,535,799     17,046,512
39.   Atlas America - Series 21-B              360        17,411,825     6,442,761     23,854,586
40.   Atlas America - Public #10               818        21,281,170     7,227,432     28,508,602
41.   Atlas America - Series 22                258        10,156,375     3,481,591     13,637,966
42.   Atlas America - Series 23                246         9,644,550     3,214,850     12,859,400
43.   Atlas America - Public #11-2002         1017        31,178,145    13,295,226     44,473,371
44.   Atlas America - Series 24-2003(A)        325        14,363,955     4,949,143     19,313,098
45.   Atlas America - Series 24-2003(B)        422        20,542,850     7,300,020     27,842,870
46.   Atlas America - Public #12-2003         1102        40,170,308    13,708,076     53,878,384
47.   Atlas America Series 25-2004(A)          635        27,601,053    10,266,771     37,867,824
48.   Atlas America Series 25-2004(B)          634        31,531,035    16,006,953     47,537,988
49.   Atlas America Public #14-2004           1494        52,506,570    25,971,721     78,478,291
50.   Atlas America Public #14-2005(A)        2192        69,674,900    30,912,583    100,587,483
51.   Atlas America Series 26-2005             579        34,886,465    15,903,570     50,790,035
52.   Atlas America Public #15-2005(A)        1625        52,245,720    21,412,609     73,658,329
53.   Atlas America Public #15-2006(B)        4108       147,513,130    55,159,085    202,672,215

<CAPTION>
                                                                          Years
                                             Date         Date of         Wells     Previous
                                          Operations       First           In        Assess-
              Partnership                    Began     Distributions   Production     ments
---------------------------------------   ----------   -------------   ----------   --------
<S>                                        <C>            <C>            <C>           <C>
1.    Atlas L.P. #1 - 1985                 12/31/85       07/02/86       20.13         -0-
2.    A.E. Partners 1986                   12/31/86       04/02/87       19.13         -0-
3.    A.E. Partners 1987                   12/31/87       04/02/88       18.13         -0-
4.    A.E. Partners 1988                   12/31/88       04/02/89       17.13         -0-
5.    A.E. Partners 1989                   12/31/89       04/02/90       16.13         -0-
6.    A.E. Partners 1990                   12/31/90       04/02/91       15.13         -0-
7.    A.E. Nineties-10                     12/31/90       03/31/91       14.91         -0-
8.    A.E. Nineties-11                     09/30/91       01/31/92       14.08         -0-
9.    A.E. Partners 1991                   12/31/91       04/02/92       13.91         -0-
10.   A.E. Nineties-12                     12/31/91       04/30/92       13.83         -0-
11.   A.E. Nineties-JV 92                  10/28/92       04/05/93       13.16         -0-
12.   A.E. Partners 1992                   12/14/92       07/02/93       12.66         -0-
13.   A.E. Nineties-Public #1              12/31/92       07/15/93       12.41         -0-
14.   A.E. Nineties-1993 Ltd.              10/08/93       02/10/94       12.08         -0-
15.   A.E. Partners 1993                   12/31/93       07/02/94       11.83         -0-
16.   A.E. Nineties-Public #2              12/31/93       06/15/94       11.58         -0-
17.   A.E. Nineties-14                     08/11/94       01/10/95       11.08         -0-
18.   A.E. Partners 1994                   12/31/94       07/02/95       10.83         -0-
19.   A.E. Nineties-Public #3              12/31/94       06/05/95       10.83         -0-
20.   A.E. Nineties-15                     09/12/95       02/07/96       10.00         -0-
21.   A.E. Partners 1995                   12/31/95       10/02/96        9.58         -0-
22.   A.E. Nineties-Public #4              12/31/95       07/08/96        9.83         -0-
23.   A.E. Nineties-16                     07/31/96       01/12/97        9.16         -0-
24.   A.E. Partners 1996                   12/31/96       07/02/97        8.83         -0-
25.   A.E. Nineties-Public #5              12/31/96       06/08/97        8.83         -0-
26.   A.E. Nineties-17                     08/29/97       12/12/97        8.25         -0-
27.   A.E. Nineties-Public #6              12/31/97       06/08/98        7.83         -0-
28.   A.E. Partners 1997                   12/31/97       07/02/98        7.66         -0-
29.   A.E. Nineties-18                     07/31/98       01/07/99        6.91         -0-
30.   A.E. Nineties-Public #7              12/31/98       07/10/99        6.58         -0-
31.   A.E. Partners 1998                   12/31/98       07/02/99        6.58         -0-
32.   A.E. Nineties-19                     09/30/99       01/14/00        6.08         -0-
33.   A.E. Nineties-Public #8              12/31/99       06/09/00        5.58         -0-
34.   A.E. Partners 1999                   12/31/99       10/02/00        5.58         -0-
35.   1999 Viking Resources LP             12/31/99       06/01/00        5.58         -0-
36.   Atlas America-Series 20              09/30/00       01/30/01        5.33         -0-
37.   Atlas America - Public #9            12/31/00       07/13/01        4.93         -0-
38.   Atlas America - Series 21-A          05/15/01       11/16/01        4.68         -0-
39.   Atlas America - Series 21-B          09/19/01       03/02/02        4.08         -0-
40.   Atlas America - Public #10           12/31/01       06/20/02        3.83         -0-
41.   Atlas America - Series 22            05/31/02       11/12/02        3.33         -0-
42.   Atlas America - Series 23            09/30/02       02/18/03        3.08         -0-
43.   Atlas America - Public #11-2002      12/31/02      7/15/2003        2.83         -0-
44.   Atlas America - Series 24-2003(A)    05/31/03       12/05/03        2.33         -0-
45.   Atlas America - Series 24-2003(B)    08/29/03       02/05/04        2.08         -0-
46.   Atlas America - Public #12-2003      12/31/03        6/15/04        1.83         -0-
47.   Atlas America Series 25-2004(A)      05/31/04        11/5/04        1.58         -0-
48.   Atlas America Series 25-2004(B)      08/31/04         2/5/05        1.17         -0-
49.   Atlas America Public #14-2004        11/15/04        7/15/05         0.7         -0-
50.   Atlas America Public #14-2005(A)     06/17/05        2/15/06        0.50         -0-
51.   Atlas America Series 26-2005         09/16/05         6/5/06        0.33         -0-
52.   Atlas America Public #15-2005(A)     12/31/05        8/15/06        0.17         -0-
53.   Atlas America Public #15-2006(B)     08/31/06            (1)          (1)        -0-
</TABLE>

----------
(1)  This program closed August 31, 2006, and its first distribution is expected
     early spring 2007.


                                       46

<PAGE>

Table 2 reflects the drilling activity of previous development drilling
partnerships sponsored by the managing general partner and its affiliates. All
the wells were development wells. You should not assume that the past
performance of prior partnerships is indicative of the future results of the
partnerships.

                                     TABLE 2
                       WELL STATISTICS - DEVELOPMENT WELLS
                            AS OF SEPTEMBER 15, 2006

<TABLE>
<CAPTION>
                                              GROSS WELLS (1)          NET WELLS (2)
                                           --------------------   -----------------------
              Partnership                  Oil    Gas   Dry (3)   Oil     Gas     Dry (3)
---------------------------------------    ---   ----   -------   ---   -------   -------
<S>                                         <C>  <C>       <C>     <C>  <C>        <C>
1.  Atlas L.P. #1 - 1985                    0       6       1      0       2.83     0.50
2.  A.E. Partners 1986                      0       8       0      0       3.50     0.00
3.  A.E. Partners 1987                      0       9       0      0       4.10     0.00
4.  A.E. Partners 1988                      0       9       0      0       3.80     0.00
5.  A.E. Partners 1989                      0      10       0      0       3.30     0.00
6.  A.E. Partners 1990                      0      12       0      0       5.00     0.00
7.  A.E. Nineties-10                        0      12       0      0      11.50     0.00
8.  A.E. Nineties-11                        0      14       0      0       4.30     0.00
9.  A.E. Partners 1991                      0      12       0      0       4.95     0.00
10. A.E. Nineties-12                        0      14       0      0      12.50     0.00
11. A.E. Nineties-JV 92                     0      52       0      0      24.44     0.00
12. A.E. Partners 1992                      0       7       0      0       3.50     0.00
13. A.E. Nineties-Public #1                 0      14       0      0      14.00     0.00
14. A.E. Nineties-1993 Ltd.                 0      20       1      0      19.40     1.00
15. A.E. Partners 1993                      0       8       0      0       4.00     0.00
16. A.E. Nineties-Public #2                 0      16       0      0      15.31     0.00
17. A.E. Nineties-14                        0      53       2      0      53.00     2.00
18. A.E. Partners 1994                      0      12       0      0       5.00     0.00
19. A.E. Nineties-Public #3                 0      26       1      0      25.50     1.00
20. A.E. Nineties-15                        0      61       1      0      55.50     1.00
21. A.E. Partners 1995                      0       6       0      0       3.00     0.00
22. A.E. Nineties-Public #4                 0      32       0      0      30.50     0.00
23. A.E. Nineties-16                        0      51       6      0      40.50     4.50
24. A.E. Partners 1996                      0      13       0      0       4.84     0.00
25. A.E. Nineties-Public #5                 0      36       0      0      35.91     0.00
26. A.E. Nineties-17                        0      47       5      0      42.00     3.50
27. A.E. Nineties-Public #6                 0      55       0      0      44.45     0.00
28. A.E. Partners 1997                      0       6       0      0       2.81     0.00
29. A.E. Nineties-18                        0      63       0      0      58.00     0.00
30. A.E. Nineties-Public #7                 0      64       0      0      57.50     0.00
31. A.E. Partners 1998                      0      19       0      0       9.50     0.00
32. A.E. Nineties-19                        0      82       4      0      75.75     4.00
33. A.E. Nineties-Public #8                 0      58       0      0      54.66     0.00
34. A.E. Partners 1999                      0       5       0      0       2.50     0.00
35. 1999 Viking Resources LP                0      23       2      0      23.00     2.00
36. Atlas America - Series 20               0     106       1      0     100.25     1.00
37. Atlas America - Public #9               0      83       2      0      78.75     2.00
38. Atlas America - Series 21-A             0      68       0      0      62.50     0.00
39. Atlas America - Series 21-B             0      89       2      0      84.05     1.00
40. Atlas America - Public #10              0     107       3      0     103.15     3.00
41. Atlas America - Series 22               0      51       1      0      49.55     1.00
42. Atlas America - Series 23               0      47       1      0      47.00     1.00
43. Atlas America - Public #11-2002         0     167       0      0     160.50     0.00
44. Atlas America - Series 24-2003(A)       0      76       0      0      69.50     0.00
45. Atlas America - Series 24-2003(B)       0     121       1      0     113.00     1.00
46. Atlas America-Public #12-2003           0     226       1      0     214.25     1.00
47. Atlas America Series 25-2004(A)         0     137       4      0     130.80     4.00
48. Atlas America Series 25-2004(B)         0     171       4      0     153.40     4.00
49. Atlas America Public #14-2004           0     256      11      0     233.50    11.00
50. Atlas America Public #14-2005(A)        0     338       5      0     315.49     5.00
51. Atlas America Series 26-2005            0     142       2      0     132.31     2.00
52. Atlas America Public #15-2005(A)        0     187       1      0     181.50     1.00
53. Atlas America Public #15-2006(B) (4)    0     243       1      0     228.18     1.00
                                           ---   ----     ---     ---   -------    -----
                                            0    3550      63      0    3218.03    58.50
                                           ---   ----     ---     ---   -------    -----
</TABLE>

----------
(1)  A "gross well" is one in which a leasehold interest is owned.

(2)  A "net well" equals the actual leasehold interest owned in one gross well
     divided by one hundred. For example, a 50% leasehold interest in a well is
     one gross well, but a .50 net well.

(3)  For purposes of this Table only, a "Dry Hole" means a well which is plugged
     and abandoned with or without a completion attempt because the operator has
     determined that it will not be productive of gas and/or oil in commercial
     quantities.

(4)  This partnership closed August 31, 2006, as of the date of this table this
     is the number of wells drilled. The total tentative gross well count is
     638.


                                       47

<PAGE>

TABLE 3 PROVIDES INFORMATION CONCERNING THE OPERATING RESULTS OF PREVIOUS
DEVELOPMENT DRILLING PARTNERSHIPS SPONSORED BY THE MANAGING GENERAL PARTNER AND
ITS AFFILIATES. YOU SHOULD NOT ASSUME THAT THE PAST PERFORMANCE OF PRIOR
PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF THE PARTNERSHIPS.

                                     TABLE 3
                 INVESTOR OPERATING RESULTS - INCLUDING EXPENSES
                            AS OF SEPTEMBER 15, 2006

<TABLE>
<CAPTION>
                                                                       TOTAL COSTS
                                                            ---------------------------------          Cash
              Partnership                 Investor Capital  Operating (5)   Admin.    Direct   Distributions (1)(3)
----------------------------------------  ----------------  -------------  --------  --------  --------------------
<S>                                         <C>               <C>          <C>       <C>          <C>
1.  Atlas L.P. #1 - 1985                    $    600,000      $  246,260   $ 49,967  $ 17,678     $ 1,717,271
2.  A.E. Partners 1986                           631,250         197,025     82,316    16,196         852,501
3.  A.E. Partners 1987                           721,000         198,889     68,752    16,350         845,668
4.  A.E. Partners 1988                           617,050         168,710     66,684    14,778         771,388
5.  A.E. Partners 1989                           550,000         165,526     71,726    15,415         955,193
6.  A.E. Partners 1990                           887,500         249,952    104,450    23,602       1,426,035
7.  A.E. Nineties - 10                         2,200,000         533,309    121,585    59,407       2,190,506
8.  A.E. Nineties - 11                           750,000         201,069    105,922    73,996       1,193,605
9.  A.E. Partners 1991                           868,750         227,964    135,067    34,813       1,526,499
10. A.E. Nineties - 12                         2,212,500         520,878    109,334   143,133       2,331,334
11. A.E. Nineties - JV 92                      4,004,813         922,806    184,470   242,597       4,866,243 (2)
12. A.E. Partners 1992                           600,000         129,828     67,013    19,466       1,000,961
13. A.E. Nineties - Public #1                  2,988,960         581,781    116,566   146,119       2,618,662
14. A.E. Nineties - 1993 Ltd.                  3,753,937         635,915    123,548    71,437       2,361,866
15. A.E. Partners 1993                           700,000         171,899     49,763    19,086       1,178,306
16. A.E. Nineties - Public #2                  3,323,920         580,711    104,698   110,927       2,540,499
17. A.E. Nineties - 14                         9,940,045       1,807,042    336,152   113,405       6,750,557
18. A.E. Partners 1994                           892,500         185,487     62,924    26,609       1,320,908
19. A.E. Nineties - Public #3                  5,800,990         991,061    182,985   130,204       4,538,918
20. A.E. Nineties - 15                        10,954,715       1,884,667    344,261   127,317       8,897,138
21. A.E. Partners 1995                           600,000         106,556     25,383    14,620         427,548
22. A.E. Nineties - Public #4                  6,991,350       1,117,338    203,928   120,643       3,710,556
23. A.E. Nineties - 16                        10,955,465       1,641,546    266,642   141,148       6,765,625
24. A.E. Partners 1996                           800,000         153,259     33,713    54,833         640,836
25. A.E. Nineties - Public #5                  7,992,240       1,140,608    203,538   135,393       4,710,605
26. A.E. Nineties - 17                         8,813,488       1,287,100    207,159   207,902       6,447,218
27. A.E. Nineties - Public #6                  9,901,025       1,493,313    242,910   179,899       7,107,063
28. A.E. Partners 1997                           506,250          90,167     19,823    38,043         514,426
29. A.E. Nineties - 18                        11,391,673       1,669,791    262,007   314,187       7,327,951
30. A.E. Nineties - Public #7                 11,988,350       1,450,751    225,489   107,945       5,479,124
31. A.E. Partners 1998                         1,740,000         280,963     36,200    74,686       1,402,588
32. A.E. Nineties - 19                        15,720,450       1,952,845    295,250    85,481       8,310,083
33. A.E. Nineties - Public #8                 11,088,975       1,329,345    204,089   142,233       6,076,885
34. A.E. Partners 1999                           450,000          58,826      6,366    21,934         418,504
35. 1999 Viking Resources LP                   4,555,210       1,487,131          0   216,784       7,542,360
36. Atlas America - Series 20                 18,809,150       3,299,254    337,934   298,679      16,267,754
37. Atlas America - Public #9                 14,905,465       2,121,813    239,046   117,761       9,778,961
38. Atlas America - Series 21-A               12,510,713       1,451,012    176,823    18,289       7,701,889
39. Atlas America - Series 21-B               17,411,825       1,807,214    211,516    18,966       9,229,676
40. Atlas America - Public #10                21,281,170       2,230,967    263,178   111,093      12,728,308
41. Atlas America - Series 22                 10,156,375         975,362    113,029    16,623       6,504,235
42. Atlas America - Series 23                  9,644,550         886,545    104,040    16,799       5,154,434
43. Atlas America - Public #11-2002           31,178,145       2,599,868    294,130    97,250      15,645,315
44. Atlas America - Series 24-2003(A)         14,363,955         974,675    114,634    12,523       6,789,533
45. Atlas America - Series 24-2003(B)         20,542,850       1,571,054    158,769    11,157      11,080,773

<CAPTION>
                                                                                                           Present Value of
                                                                               Estimated Future          Estimated Future Net
                                                        Latest Quarterly     Net Cash Flows from        Cash Flows from Proved
                                             Cash      Cash Distribution    Proved Reserves as of     Reserves Discounted at 10%
               Partnership                Return (3)  As of Date of Table  January 1, 2006 (7) (8)  as of January 1, 2006 (7) (9)
----------------------------------------  ----------  -------------------  -----------------------  -----------------------------
<S>                                          <C>            <C>                   <C>                         <C>
1.  Atlas L.P. #1 - 1985                     286%           $ 18,038                       (6)                         (6)
2.  A.E. Partners 1986                       135%              9,713                       (6)                         (6)
3.  A.E. Partners 1987                       117%             12,063                       (6)                         (6)
4.  A.E. Partners 1988                       125%              9,016                       (6)                         (6)
5.  A.E. Partners 1989                       174%              9,966                       (6)                         (6)
6.  A.E. Partners 1990                       161%             23,050                       (6)                         (6)
7.  A.E. Nineties - 10                       100%             32,620              2,786,335                   1,338,459
8.  A.E. Nineties - 11                       159%             12,942              1,216,578                     550,127
9.  A.E. Partners 1991                       176%             22,395                       (6)                         (6)
10. A.E. Nineties - 12                       105%             28,306              2,323,292                   1,087,659
11. A.E. Nineties - JV 92                    122%             46,776              2,271,517                   2,271,517
12. A.E. Partners 1992                       167%             11,171                       (6)                         (6)
13. A.E. Nineties - Public #1                 88%             38,046              3,159,562                   1,474,933
14. A.E. Nineties - 1993 Ltd.                 63%             12,500              1,344,478                     710,020
15. A.E. Partners 1993                       168%             15,053                       (6)                         (6)
16. A.E. Nineties - Public #2                 76%             19,335              1,947,940                     926,225
17. A.E. Nineties - 14                        68%             77,279              8,282,295                   4,122,517
18. A.E. Partners 1994                       148%             26,732                       (6)                         (6)
19. A.E. Nineties - Public #3                 78%             67,170              6,576,342                   2,957,611
20. A.E. Nineties - 15                        81%            153,709             14,614,389                   6,587,541
21. A.E. Partners 1995                        71%              6,360                       (6)                         (6)
22. A.E. Nineties - Public #4                 53%             86,881              6,936,030                   3,187,313
23. A.E. Nineties - 16                        62%            151,489             14,968,351                   6,464,413
24. A.E. Partners 1996                        80%             23,178                       (6)                         (6)
25. A.E. Nineties - Public #5                 59%             93,240              8,082,368                   3,784,776
26. A.E. Nineties - 17                        73%            178,045             15,285,565                   6,704,964
27. A.E. Nineties - Public #6                 72%            188,078             15,277,189                   6,955,093
28. A.E. Partners 1997                       102%             20,637                       (6)                         (6)
29. A.E. Nineties - 18                        64%            187,234             15,555,530                   7,214,431
30. A.E. Nineties - Public #7                 46%            145,083             10,902,072                   5,216,299
31. A.E. Partners 1998                        81%             43,408                       (6)                         (6)
32. A.E. Nineties - 19                        53%            228,618             18,262,903                   8,531,658
33. A.E. Nineties - Public #8                 55%            140,803             11,229,630                   5,491,322
34. A.E. Partners 1999                        93%             12,756                       (6)                         (6)
35. 1999 Viking Resources LP                 166%            161,075             10,938,303                   4,868,453
36. Atlas America - Series 20                 86%            449,685             32,188,897                  15,135,852
37. Atlas America - Public #9                 66%            311,229             23,408,497                  10,948,104
38. Atlas America - Series 21-A               62%            314,790             21,577,560                  10,082,423
39. Atlas America - Series 21-B               53%            383,276             27,352,982                  12,644,429
40. Atlas America - Public #10                60%            522,588             35,891,965                  16,628,127
41. Atlas America - Series 22                 64%            297,033             19,796,477                   9,053,570
42. Atlas America - Series 23                 53%            245,055             14,063,560                   6,906,104
43. Atlas America - Public #11-2002           50%            760,984             45,868,431                  22,353,045
44. Atlas America - Series 24-2003(A)         47%            519,571             26,989,322                  12,330,024
45. Atlas America - Series 24-2003(B)         54%            653,565             36,780,376                  17,910,462
</TABLE>


                                       48

<PAGE>

TABLE 3 PROVIDES INFORMATION CONCERNING THE OPERATING RESULTS OF PREVIOUS
DEVELOPMENT DRILLING PARTNERSHIPS SPONSORED BY THE MANAGING GENERAL PARTNER AND
ITS AFFILIATES. YOU SHOULD NOT ASSUME THAT THE PAST PERFORMANCE OF PRIOR
PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF THE PARTNERSHIPS.

                                     TABLE 3
                 INVESTOR OPERATING RESULTS - INCLUDING EXPENSES
                            AS OF SEPTEMBER 15, 2006

<TABLE>
<CAPTION>
                                                                       TOTAL COSTS
                                                            ---------------------------------          Cash
               Partnership                Investor Capital  Operating (5)   Admin.    Direct   Distributions (1)(3)
----------------------------------------  ----------------  -------------  --------  --------  --------------------
<S>                                          <C>               <C>          <C>       <C>          <C>
46. Atlas America - Public #12-2003           40,170,308       2,309,645    257,283    81,371      15,786,993
47. Atlas America Series 25-2004(A)           27,601,053       1,373,402    114,762    60,140      11,893,622
48. Atlas America Series 25-2004(B)           31,531,035       1,207,893    114,202    63,778       8,130,183
49. Atlas America Public #14-2004             52,506,570       1,311,067    111,806    59,329       8,648,613
50. Atlas America Public #14-2005(A) (4)      69,674,900       1,132,841     86,116    39,734       7,117,275
51. Atlas America Series 26-2005 (4)          34,886,465         273,477     22,365    37,418       1,146,583
52. Atlas America Public #15-2005(A) (4)      52,245,720         223,282     14,612   27940.2         880,735
53. Atlas America Public #15-2006(B) (4)     147,513,130               0          0         0               0

<CAPTION>
                                                                                                           Present Value of
                                                                               Estimated Future          Estimated Future Net
                                                        Latest Quarterly     Net Cash Flows from        Cash Flows from Proved
                                             Cash      Cash Distribution    Proved Reserves as of     Reserves Discounted at 10%
               Partnership                Return (3)  As of Date of Table  January 1, 2006 (7) (8)  as of January 1, 2006 (7) (9)
----------------------------------------  ----------  -------------------  -----------------------  -----------------------------
<S>                                           <C>          <C>                  <C>                          <C>
46. Atlas America - Public #12-2003           39%          1,255,983             44,426,619                  24,311,567
47. Atlas America Series 25-2004(A)           43%          1,552,570             47,244,326                  25,810,186
48. Atlas America Series 25-2004(B)           26%          1,309,287             42,121,836                  23,328,766
49. Atlas America Public #14-2004             16%          2,437,821             71,009,319                  39,354,877
50. Atlas America Public #14-2005(A) (4)      10%          3,332,777            114,641,497                  62,932,887
51. Atlas America Series 26-2005 (4)           3%            993,525             39,721,982                  21,181,210
52. Atlas America Public #15-2005(A) (4)       2%            880,735              3,240,412                   1,858,667
53. Atlas America Public #15-2006(B) (4)       0%                  0                       (6)                         (6)
</TABLE>

----------
(1)  All cash distributions were from the sale of gas. The following
     partnerships also include revenue from the sale of properties: A.E.
     Nineties-16 ($4,776), A.E. Nineties-19 ($1,607), Atlas America Series 20
     ($6,662), Atlas America Series 24-2003(A) ($9,066), Atlas America Series
     24-2003(B) ($ 9,904), Atlas America Series 25-2004(A) ($595), Atlas America
     Series 25-2004(B) ($3,813), A.E. Nineties-Public #1 ($2,453), A.E.
     Nineties-Public #2 ($3,292), A.E. Nineties-Public #3 ($2,491), A.E.
     Nineties-Public #5 ($8,639), A.E. Nineties-Public #7 ($2,206), Atlas
     America Public #11-2002 ($2,789) and Atlas America Public #12-2003
     ($1,568).

(2)  A portion of the cash distributions was used to drill three reinvestment
     wells at a cost of $307,434 in accordance with the terms of the offering.

(3)  This column reflects total cash distributions beginning with the first
     production from the program as a percentage of the total amount invested in
     the program and includes the return of the investors' capital.

(4)  As of the date of this table there is not twelve months of production
     and/or not all of the wells are drilled or on-line to sell production.

(5)  Operating costs consist of gathering fees, water hauling fees, meter
     reading fees, repairs and maintenance, insurance and severance tax.

(6)  Current reserve information is either not available for these partnerships.
     The most current reserve report is dated 1/1/06. Also, reserve information
     for Public # 15-2005(A) which closed at 12/31/05 is incomplete since not
     all of its wells were drilled at 1/1/06.

(7)  The information presented in this column has been prepared in conformity
     with SEC guidelines by making the standardized estimates of future net cash
     flow from proved td.,rAtlausing natural gas and oil prices in effect as of
     the date of the estimates, which was a weighted average price of $10.08 per
     mcf for the natural gas, and which are held constant throughout the life of
     the properties. The information presented for future net cash flows based
     on estimated proved reserves has been prepared by the managing general
     partner's petroleum engineers and reviewed by an independent petroleum
     consultant, Wright & Company, Inc., as noted below with respect to the
     managing general partner's prior public partnerships and three Regulation D
     offerings which were registered under Section 12(g) of the Securities
     Exchange Act of 1934: Atlas-Energy for the Nineties-Public #1 Ltd.,
     Atlas-Energy for the Nineties-Public #2 Ltd., Atlas-Energy for the
     Nineties-Public #3 Ltd., Atlas-Energy for the Nineties-Public #4 L #12-2003
     Limited Partnership, Atlas America Series 25-2004(A) L.P., Atlas America
     Series 25-2004(B) L.P., Atlas America Public #14-2004 L.P., Atlas America
     Public #14-2005(A) L.P., Atlas America Series 26-2005 L.P., and Atlas
     America Public #15-2005(A) L.P. The other partnerships have not been
     reviewed by Wright & Company, Inc. You should understand that reserve
     estimates are imprecise and may change. There are inherent uncertainties in
     interpreting the engineering data and the projection of future rates of
     production. Also, prices received from the sale of natural gas and oil may
     be different from those estimates in preparing the reports, and the amounts
     and timing of future operating and development costs may also differ from
     those used. The cash flow information based on estimated proved reserves
     shown for a partnership does not include this information for the managing
     general partner.

(8)  This column represents a partnership's estimate of future net cash flows
     from its proved reserves using natural gas sales prices in effect as of the
     dates of the estimates which are held constant throughout the life of the
     partnership's properties. As natural gas prices change, these estimates
     will change. The information in this column has not been discounted.

(9)  This column represents a partnership's estimate of future net cash flows
     from its proved reserves using natural gas sales prices in effect as of the
     dates of the estimates which are held constant throughout the life of the
     partnership's properties. As natural gas prices change, these estimates
     will change. The present value of estimated future net cash flows is
     calculated by discounting estimated future net cash flows by 10% annually
     in accordance with SEC guidelines. You should not construe the estimated
     PV-10 values as representative of the fair market value of a partnership's
     properties.


                                       49

<PAGE>

Table 3A provides information concerning the operating results of previous
development drilling partnerships sponsored by the managing general partner and
its affiliates.

                                    TABLE 3A
                            MANAGING GENERAL PARTNER
                     OPERATING RESULTS - INCLUDING EXPENSES
                            AS OF SEPTEMBER 15, 2006

<TABLE>
<CAPTION>
                                                                        Total Costs
                                          Managing General  ----------------------------------
              Partnership                  Partner Capital  Operating (3)   Admin.     Direct
----------------------------------------  ----------------  -------------  --------  ---------
<S>                                          <C>              <C>          <C>       <C>
1.  Atlas L.P. #1 - 1985                     $   114,800      $   46,907   $  9,517  $   3,367
2.  A.E. Partners 1986                           120,400          37,528     15,679      3,085
3.  A.E. Partners 1987                           158,269          57,345     19,823      4,714
4.  A.E. Partners 1988                           135,450          54,333     21,476      4,759
5.  A.E. Partners 1989                           120,731          36,335     15,745      3,384
6.  A.E. Partners 1990                           244,622          83,317          0          0
7.  A.E. Nineties - 10                           484,380         177,770          0          0
8.  A.E. Nineties - 11                           268,003          86,173     45,395     26,655
9.  A.E. Partners 1991                           318,063          75,988          0          0
10. A.E. Nineties - 12                           791,833         223,233     46,857     35,836
11. A.E. Nineties - JV 92                      1,414,917         454,516     90,859     37,948
12. A.E. Partners 1992                           176,100          43,276          0          0
13. A.E. Nineties - Public #1                    528,934         183,720     36,810     34,336
14. A.E. Nineties - 1993 Ltd.                  1,264,183         272,535     52,949     27,034
15. A.E. Partners 1993                           219,600          57,300          0          0
16. A.E. Nineties - Public #2                    587,340         183,382     33,062     35,030
17. A.E. Nineties - 14                         3,584,027         890,036    165,567     48,677
18. A.E. Partners 1994                           231,500          61,829          0          0
19. A.E. Nineties - Public #3                    928,546         330,354     60,995     43,401
20. A.E. Nineties - 15                         3,435,936         807,715    147,540     54,565
21. A.E. Partners 1995                           244,725          35,519          0          0
22. A.E. Nineties - Public #4                  1,287,752         372,446     67,976     40,214
23. A.E. Nineties - 16                         1,643,320         449,595     73,029     33,853
24. A.E. Partners 1996                           367,416          51,086          0          0
25. A.E. Nineties - Public #5                  1,654,740         380,203     67,846     45,131
26. A.E. Nineties - 17                         2,113,947         464,057     74,690     45,613
27. A.E. Nineties - Public #6                  1,950,345         497,771     80,970     59,966
28. A.E. Partners 1997                           231,050          30,056          0          0
29. A.E. Nineties - 18                         3,448,751         767,860    120,485     31,609
30. A.E. Nineties - Public #7                  3,812,150         651,787    101,307     48,497
31. A.E. Partners 1998                           756,360          93,654          0          0
32. A.E. Nineties - 19                         4,776,598         898,024    135,772     39,309
33. A.E. Nineties - Public #8                  3,148,181         542,972     83,360     58,095
34. A.E. Partners 1999                           196,500          19,609          0          0
35. 1999 Viking Resources LP                   1,678,038         495,710          0     72,261
36. Atlas America - Series 20                  6,297,945       1,220,272    124,989    110,470
37. Atlas America - Public #9                  6,256,271         891,005    100,759     48,100
38. Atlas America - Series 21-A                4,535,799         741,962     90,417      9,352
39. Atlas America - Series 21-B                6,442,761         930,989    108,963      9,770
40. Atlas America - Public #10                 7,227,432       1,049,871    123,849     52,279
41. Atlas America - Series 22                  3,481,591         470,263     53,190      8,014
42. Atlas America - Series 23                  3,214,850         417,206     48,960      7,906
43. Atlas America - Public #11-2002           13,295,226       1,339,326    154,621     50,098
44. Atlas America - Series 24-2003(A)          4,949,143         472,074     55,522      6,066
45. Atlas America - Series 24-2003(B)          7,300,020         781,527     78,981      5,550

<CAPTION>
                                                                          Latest Quarterly Cash
                                                 Cash                       Distribution As of
              Partnership                 Distributions (1)  Cash Return      Date of Table
----------------------------------------  -----------------  -----------  ---------------------
<S>                                           <C>                <C>            <C>
1.  Atlas L.P. #1 - 1985                      $  327,099         285%           $    3,436
2.  A.E. Partners 1986                           162,381         135%                1,850
3.  A.E. Partners 1987                           243,830         154%                3,478
4.  A.E. Partners 1988                           248,456         183%                2,904
5.  A.E. Partners 1989                           285,170         236%                2,188
6.  A.E. Partners 1990                           435,070         178%                8,654
7.  A.E. Nineties - 10                           784,136         162%               12,131
8.  A.E. Nineties - 11                           511,780         191%                5,547
9.  A.E. Partners 1991                           546,289         172%                8,579
10. A.E. Nineties - 12                           999,144         126%               12,131
11. A.E. Nineties - JV 92                      1,468,616         104%               23,039
12. A.E. Partners 1992                         1,000,961         568%                4,437
13. A.E. Nineties - Public #1                    784,716         148%               12,014
14. A.E. Nineties - 1993 Ltd.                    542,568          43%                5,357
15. A.E. Partners 1993                           410,171         187%                5,848
16. A.E. Nineties - Public #2                    636,225         108%                6,106
17. A.E. Nineties - 14                         2,159,572          60%               38,063
18. A.E. Partners 1994                           465,059         201%                9,569
19. A.E. Nineties - Public #3                  1,450,980         156%               22,390
20. A.E. Nineties - 15                         2,893,896          84%               65,875
21. A.E. Partners 1995                           154,941          63%                2,683
22. A.E. Nineties - Public #4                  1,119,663          87%               28,960
23. A.E. Nineties - 16                         1,454,645          89%               41,491
24. A.E. Partners 1996                           243,222          66%                8,390
25. A.E. Nineties - Public #5                  1,223,820          74%               31,080
26. A.E. Nineties - 17                         2,177,234         103%               64,193
27. A.E. Nineties - Public #6                  2,271,798         116%               62,693
28. A.E. Partners 1997                           182,535          79%                7,611
29. A.E. Nineties - 18                         3,163,902          92%               86,100
30. A.E. Nineties - Public #7                  1,543,414          40%               65,182
31. A.E. Partners 1998                           491,253          65%               15,333
32. A.E. Nineties - 19                         3,681,168          77%              105,131
33. A.E. Nineties - Public #8                  2,261,028          72%               57,511
34. A.E. Partners 1999                           148,888          76%                4,684
35. 1999 Viking Resources LP                   2,514,120         150%               53,692
36. Atlas America - Series 20                  6,022,060          96%              166,322
37. Atlas America - Public #9                  4,104,730          66%              171,297
38. Atlas America - Series 21-A                3,938,292          87%              160,965
39. Atlas America - Series 21-B                4,748,410          74%              197,445
40. Atlas America - Public #10                 5,989,220          83%              245,925
41. Atlas America - Series 22                  3,135,963          90%              143,212
42. Atlas America - Series 23                  2,425,667          75%              115,322
43. Atlas America - Public #11-2002            8,184,812          62%              406,979
44. Atlas America - Series 24-2003(A)          3,301,620          67%              252,885
45. Atlas America - Series 24-2003(B)          5,505,659          75%              325,118
</TABLE>


                                       50

<PAGE>

Table 3A provides information concerning the operating results of previous
development drilling partnerships sponsored by the managing general partner and
its affiliates.

                                    TABLE 3A
                            MANAGING GENERAL PARTNER
                     OPERATING RESULTS - INCLUDING EXPENSES
                            AS OF SEPTEMBER 15, 2006

<TABLE>
<CAPTION>
                                                                        Total Costs
                                          Managing General  ----------------------------------
              Partnership                  Partner Capital  Operating (3)   Admin.     Direct
----------------------------------------  ----------------  -------------  --------  ---------
<S>                                           <C>              <C>          <C>       <C>
46. Atlas America - Public #12-2003           13,708,076       1,109,013    133,148     39,072
47. Atlas America Series 25-2004(A)           10,266,771         739,524     61,795     32,383
48. Atlas America Series 25-2004(B)           16,006,953         650,404     61,493     34,342
49. Atlas America Public #14-2004             25,971,721         705,959     60,203     31,947
50. Atlas America Public #14-2005(A) (2)      30,912,583         609,991     46,370     21,395
51. Atlas America Series 26-2005 (2)          15,903,570         169,832     13,889     23,237
52. Atlas America Public #15-2005(A) (2)      21,412,609         125,978      8,244   15044.72
52. Atlas America Public #15-2006(B) (2)               0               0          0          0

<CAPTION>
                                                                          Latest Quarterly Cash
                                                 Cash                       Distribution As of
              Partnership                 Distributions (1)  Cash Return      Date of Table
----------------------------------------  -----------------  -----------  ---------------------
<S>                                            <C>                <C>            <C>
46. Atlas America - Public #12-2003            8,198,524          60%              676,936
47. Atlas America Series 25-2004(A)            6,403,391          62%              835,701
48. Atlas America Series 25-2004(B)            4,385,152          27%              712,739
49. Atlas America Public #14-2004              4,656,946          18%            1,312,673
50. Atlas America Public #14-2005(A) (2)       3,832,379          12%            1,794,572
51. Atlas America Series 26-2005 (2)             712,038           4%              616,987
52. Atlas America Public #15-2005(A) (2)         496,920           2%              496,920
52. Atlas America Public #15-2006(B) (2)               0           0%                    0
</TABLE>

----------
(1)  All cash distributions were from the sale of gas. The following
     partnerships also include revenue from the sale of properties: A.E. for the
     Nineties-1993 LTD ($6,337), A.E. Nineties-14 ($7,964), A.E. Nineties-15
     ($4,776), A.E. Nineties-19 ($2,473), Atlas America Series 20 ($8,562),
     Atlas America Series 24-2003(B) ($17,598), Atlas America Series 24-2003(B)
     ($19,226), Atlas America Series 25-2004(A) ($1,445), Atlas America Series
     25-2004(B) ($1,761), A.E. Nineties-Public #1 ($25), A.E. Nineties-Public #2
     ($33), A.E. Nineties-Public #3 ($25), A.E. Nineties-Public #5 ($1,406),
     A.E. Nineties-Public #7 ($2,296), Atlas America Public #9 ($4,446), Atlas
     America Public #11-2002 ($5,696) and Atlas America Public #12-2003
     ($3,582).

(2)  As of the date of this table there is not twelve months of production
     and/or not all wells are drilled or on-line to sell production.

(3)  Operating costs consist of gathering fees, water hauling fees, meter
     reading fees, repairs and maintenance, insurance and severance tax.


                                       51

<PAGE>

Table 4 sets forth the managing general partner's estimate of the federal tax
savings to investors in the managing general partner's prior development
drilling partnerships, based on the maximum marginal tax rate in each year, the
share of tax deductions as a percentage of their subscriptions, and the
aggregate cash distributions. YOU ARE URGED TO CONSULT WITH YOUR OWN TAX
ADVISORS CONCERNING YOUR SPECIFIC TAX SITUATION AND SHOULD NOT ASSUME THAT THE
PAST PERFORMANCE OF PRIOR PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF
THE PARTNERSHIPS.

                                     TABLE 4
         SUMMARY OF INVESTOR TAX BENEFITS AND CASH DISTRIBUTION RETURNS
                            AS OF SEPTEMBER 15, 2006

<TABLE>
<CAPTION>
                                                                                    Estimated Federal Tax Savings From (1):
                                                                          --------------------------------------------------------
                                                         1st Year    Eff    1st Year                                    Section 29
                                             Investor      Tax       Tax     I.D.C.      Depletion                         Tax
              Partnership                    Capital    Deduct.(2)  Rate  Deduct. (3)  Allowance (3)  Depreciation (3)  Credit (4)
----------------------------------------   -----------  ----------  ----  -----------  -------------  ----------------  ----------
<S>                                        <C>           <C>        <C>   <C>             <C>            <C>             <C>
1.   Atlas L.P. #1 - 1985                     $600,000      99%     50.0%   $298,337      $134,206           N/A           $55,915
2.   A.E. Partners 1986                        631,250      99%     50.0%    312,889        77,378           N/A           13,507
3.   A.E. Partners 1987                        721,000      99%     38.5%    356,895        59,520           N/A             N/A
4.   A.E. Partners 1988                        617,050      99%     33.0%    244,351        53,846           N/A             N/A
5.   A.E. Partners 1989                        550,000      99%     33.0%    179,685        73,294           N/A             N/A
6.   A.E. Partners 1990                        887,500      99%     33.0%    275,125       106,390           N/A           281,660
7.   A.E. Nineties - 10                      2,200,000     100%     33.0%    726,000       172,936           N/A           521,602
8.   A.E. Nineties - 11                        750,000     100%     31.0%    232,500       105,638           N/A           329,800
9.   A.E. Partners 1991                        868,750     100%     31.0%    269,313       119,815           N/A           315,893
10.  A.E. Nineties - 12                      2,212,500     100%     31.0%    685,875       214,464           N/A           617,285
11.  A.E. Nineties - JV 92                   4,004,813    92.5%     31.0%  1,322,905       379,240           N/A         1,002,109
12.  A.E. Partners 1992                        600,000     100%     31.0%    186,000        84,409           N/A           224,631
13.  A.E. Nineties - Public  #1              2,988,960    80.5%     36.0%    877,511       238,350         254,729           N/A
14.  A.E. Nineties - 1993 Ltd.               3,753,937    92.5%     39.6%  1,378,377       217,988           N/A             N/A
15.  A.E. Partners 1993                        700,000     100%     39.6%    273,216        92,558           N/A             N/A
16.  A.E. Nineties - Public  #2              3,323,920    78.7%     39.6%  1,036,343       214,344         279,039           N/A
17.  A.E. Nineties - 14                      9,940,045      95%     39.6%  3,739,445       566,141           N/A             N/A
18.  A.E. Partners 1994                        892,500     100%     39.6%    353,430        93,923           N/A             N/A
19.  A.E. Nineties - Public  #3              5,800,990    76.2%     39.6%  1,752,761       374,267         521,115           N/A
20.  A.E. Nineties - 15                     10,954,715    90.0%     39.6%  3,904,261       690,471           N/A             N/A
21.  A.E. Partners 1995                        600,000     100%     39.6%    237,600        30,162           N/A             N/A
22.  A.E. Nineties - Public  #4              6,991,350    80.0%     39.6%  2,214,860       329,901         537,551           N/A
23.  A.E. Nineties - 16                     10,955,465    86.8%     39.6%  3,361,289       498,319         872,185           N/A
24.  A.E. Partners 1996                        800,000     100%     39.6%    316,800        49,573           N/A             N/A
25.  A.E. Nineties - Public  #5              7,992,240    84.9%     39.6%  2,530,954       352,048         602,746           N/A
26.  A.E. Nineties - 17                      8,813,488    85.2%     39.6%  2,966,366       474,038         453,739           N/A
27.  A.E. Nineties - Public  #6              9,901,025    80.0%     39.6%  3,166,406       523,630         728,024           N/A
28.  A.E. Partners 1997                        506,250     100%     39.6%    200,475        35,302           N/A             N/A
29.  A.E. Nineties - 18                     11,391,673    90.0%     39.6%  4,030,884       397,479         433,716           N/A
30.  A.E. Nineties - Public  #7             11,988,350    85.0%     39.6%  4,043,670       366,218         623,927           N/A
31.  A.E. Partners 1998                      1,740,000   100.0%     39.6%    689,040       100,924           N/A             N/A
32.  A.E. Nineties - 19                     15,720,450    90.0%     39.6%  5,602,767       557,977         523,962           N/A
33.  A.E. Nineties - Public  #8             11,088,975    85.0%     39.6%  3,734,654       414,476         540,985           N/A
34.  A.E. Partners 1999                        450,000   100.0%     39.6%    178,200        26,609           N/A             N/A
35.  1999 Viking Resources LP                4,555,210    92.0%     39.6%  1,678,038       500,421           N/A             N/A
36.  Atlas America - Series 20              18,809,150    90.0%     39.6%  6,712,802       973,619         544,217           N/A
37.  Atlas America - Public  #9             14,905,465    90.0%     39.6%  5,349,744       633,024           N/A             N/A
38.  Atlas America - Series 21-A            12,510,713    91.0%     39.1%  4,468,617       439,859         275,025           N/A
39.  Atlas America - Series 21-B            17,411,825    91.0%     39.1%  6,197,907       523,241         351,033           N/A
40.  Atlas America - Public #10             21,281,170    91.0%     39.1%  7,550,729       685,415         563,453           N/A
41.  Atlas America - Series 22              10,156,375    91.0%     38.6%  3,564,312       318,593         261,761           N/A
42.  Atlas America - Series 23               9,644,550    91.0%     38.6%  3,404,803       252,265         230,415           N/A
43.  Atlas America - Public #11-2002        31,178,145    91.0%     38.6%  1,003,503       776,817         671,955           N/A
44.  Atlas America - Series 24-2003(A)      14,363,955    91.0%     35.0%  4,578,250       265,230         301,871           N/A
45.  Atlas America - Series 24-2003(B)      20,542,850    91.0%     35.0%  6,514,764       484,032         494,559           N/A
46.  Atlas America - Public #12-2003        40,170,308    91.0%     35.0%  2,879,332       632,604         890,093           N/A

<CAPTION>
                                                                                Total      Cumulative Percent
                                                        Cash Distribution     Cash Dist.    of Cash Dist. And
                                                              As of            And Tax         Tax Savings
              Partnership                     Total    Date of Table(5)(6)  Savings(5)(6)  to Date (5)(6)(7)
----------------------------------------   ----------  -------------------  -------------  ------------------
<S>                                        <C>              <C>                <C>                <C>
1.   Atlas L.P. #1 - 1985                    $488,458       $1,717,271         $2,205,729         368%
2.   A.E. Partners 1986                       403,774          852,501          1,256,275         199%
3.   A.E. Partners 1987                       416,415          845,668          1,262,084         175%
4.   A.E. Partners 1988                       298,197          771,388          1,069,585         173%
5.   A.E. Partners 1989                       252,979          955,193          1,208,172         220%
6.   A.E. Partners 1990                       663,175        1,426,035          2,089,210         235%
7.   A.E. Nineties - 10                     1,420,538        2,190,506          3,611,044         153%
8.   A.E. Nineties - 11                       667,938        1,193,605          1,861,543         236%
9.   A.E. Partners 1991                       705,022        1,526,499          2,231,521         257%
10.  A.E. Nineties - 12                     1,517,624        2,331,334          3,848,958         164%
11.  A.E. Nineties - JV 92                  2,704,253        4,866,243          7,570,496         189%
12.  A.E. Partners 1992                       495,040        1,000,961          1,496,001         249%
13.  A.E. Nineties - Public  #1             1,370,590        2,618,662          3,989,252         125%
14.  A.E. Nineties - 1993 Ltd.              1,596,365        2,361,866          3,958,231         105%
15.  A.E. Partners 1993                       365,774        1,178,306          1,544,080         221%
16.  A.E. Nineties - Public  #2             1,529,726        2,540,499          4,070,225         122%
17.  A.E. Nineties - 14                     4,305,586        6,750,557         11,056,143         111%
18.  A.E. Partners 1994                       447,353        1,320,908          1,768,261         198%
19.  A.E. Nineties - Public  #3             2,648,143        4,538,918          7,187,061         124%
20.  A.E. Nineties - 15                     4,594,732        8,897,138         13,491,870         123%
21.  A.E. Partners 1995                       267,762          427,548            695,310         116%
22.  A.E. Nineties - Public  #4             3,082,312        3,710,556          6,792,868          97%
23.  A.E. Nineties - 16                     4,731,793        6,765,625         11,497,417         105%
24.  A.E. Partners 1996                       366,373          640,836          1,007,209         126%
25.  A.E. Nineties - Public  #5             3,485,748        4,710,605          8,196,353         103%
26.  A.E. Nineties - 17                     3,894,143        6,447,218         10,341,361         117%
27.  A.E. Nineties - Public  #6             4,418,059        7,107,063         11,525,123         116%
28.  A.E. Partners 1997                       235,777          514,426            750,204         148%
29.  A.E. Nineties - 18                     4,862,079        7,327,951         12,190,030         107%
30.  A.E. Nineties - Public  #7             5,033,816        5,479,124         10,512,940          87%
31.  A.E. Partners 1998                       789,964        1,402,588          2,192,552         126%
32.  A.E. Nineties - 19                     6,684,706        8,310,083         14,994,789          95%
33.  A.E. Nineties - Public  #8             4,690,115        6,076,885         10,767,000          97%
34.  A.E. Partners 1999                       204,809          418,504            623,313         139%
35.  1999 Viking Resources LP               2,178,459        7,542,360          9,720,819         213%
36.  Atlas America - Series 20              8,230,638       16,267,754         24,498,392         130%
37.  Atlas America - Public  #9             5,982,768        9,778,961         15,761,729          99%
38.  Atlas America - Series 21-A            5,183,501        7,701,889         12,885,391         103%
39.  Atlas America - Series 21-B            7,072,182        9,229,676         16,301,858          93%
40.  Atlas America - Public #10             8,799,597       12,728,308         21,527,905         101%
41.  Atlas America - Series 22              4,144,666        6,504,235         10,648,901         105%
42.  Atlas America - Series 23              3,887,483        5,154,434          9,041,917          93%
43.  Atlas America - Public #11-2002       12,452,275       15,645,315         28,097,590          90%
44.  Atlas America - Series 24-2003(A)      5,145,351        6,789,533         11,934,884          83%
45.  Atlas America - Series 24-2003(B)      7,493,356       11,080,773         18,574,129          90%
46.  Atlas America - Public #12-2003       14,402,029       15,786,993         30,189,022          75%
</TABLE>


                                       52

<PAGE>

Table 4 sets forth the managing general partner's estimate of the federal tax
savings to investors in the managing general partner's prior development
drilling partnerships, based on the maximum marginal tax rate in each year, the
share of tax deductions as a percentage of their subscriptions, and the
aggregate cash distributions. YOU ARE URGED TO CONSULT WITH YOUR OWN TAX
ADVISORS CONCERNING YOUR SPECIFIC TAX SITUATION AND SHOULD NOT ASSUME THAT THE
PAST PERFORMANCE OF PRIOR PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF
THE PARTNERSHIPS.

                                     TABLE 4
         SUMMARY OF INVESTOR TAX BENEFITS AND CASH DISTRIBUTION RETURNS
                            AS OF SEPTEMBER 15, 2006

<TABLE>
<CAPTION>
                                                                                    Estimated Federal Tax Savings From (1):
                                                                          --------------------------------------------------------
                                                         1st Year    Eff    1st Year                                    Section 29
                                             Investor      Tax       Tax     I.D.C.      Depletion                         Tax
              Partnership                    Capital    Deduct.(2)  Rate  Deduct. (3)  Allowance (3)  Depreciation (3)  Credit (4)
----------------------------------------   -----------  ----------  ----  -----------  -------------  ----------------  ----------
<S>                                        <C>            <C>       <C>    <C>             <C>           <C>                 <C>
47.  Atlas America Series 25-2004(A)        27,601,053    91.0%     35.0%   8,694,332      452,773         891,447           N/A
48.  Atlas America Series 25-2004(B)        31,531,035    91.0%     35.0%   9,932,276      265,868       1,089,408           N/A
49.  Atlas America Public #14-2004          52,506,570    91.0%     35.0%  16,543,643      316,342         471,926           N/A
50.  Atlas America Public #14-2005(A) (8)   69,674,900    91.0%     35.0%  22,107,994      101,748         276,015           N/A
51.  Atlas America Series 26-2005 (8)       34,886,465    91.0%     35.0%  10,989,458            0          21,461           N/A
52.  Atlas America Public #15-2005(A) (8)   52,245,720    91.0%     35.0%  16,457,402            0               0           N/A
53.  Atlas America Public #15-2006(B) (8)  147,513,130    91.0%     35.0%           0            0               0           N/A

<CAPTION>
                                                                                Total      Cumulative Percent
                                                        Cash Distribution     Cash Dist.    of Cash Dist. And
                                                              As of            And Tax         Tax Savings
              Partnership                     Total    Date of Table(5)(6)  Savings(5)(6)  to Date (5)(6)(7)
----------------------------------------   ----------  -------------------  -------------  ------------------
<S>                                        <C>              <C>                <C>                 <C>
47.  Atlas America Series 25-2004(A)       10,038,552       11,893,622         21,932,175          79%
48.  Atlas America Series 25-2004(B)       11,287,552        8,130,183         19,417,735          61%
49.  Atlas America Public #14-2004         17,331,912        8,648,613         25,980,525          49%
50.  Atlas America Public #14-2005(A) (8)  22,485,757        7,117,275         29,603,032          42%
51.  Atlas America Series 26-2005 (8)      11,010,919        1,146,583         12,157,502          35%
52.  Atlas America Public #15-2005(A) (8)  16,457,402          880,735         17,338,137          33%
53.  Atlas America Public #15-2006(B) (8)           0                                0
</TABLE>

----------
1.   These columns reflect the savings in taxes which would have been paid by an
     investor, assuming full use of deductions available to the investor.

2.   Atlas Resources anticipates that approximately 90% of an investor general
     partner's subscription to a partnership will be deductible in the year in
     which he invests.

3.   The I.D.C. Deductions, Depletion Allowance and MACRS depreciation
     deductions have been reduced to credit equivalents.

4.   The Section 29 tax credit is not available with respect to wells drilled
     after December 31, 1992. N/A means not applicable.

5.   These distributions were all from production revenues. The following
     partnerships also include revenue from the sale of properties: A.E.
     Nineties-16 ($4,776), A.E. Nineties-19 ($1,607), Atlas America Series 20
     ($6,662), Atlas America Series 24-2003(A) ($9,066), Atlas America Series
     24-2003(B) ($9,904), Atlas America Series 25-2004(A) ($595), Atlas America
     Series 25-2004(B) ($3,813), A.E. Nineties-Public #1 ($2,453), A.E.
     Nineties-Public #2 ($3,292), A.E. Nineties-Public #3 ($2,491), A.E.
     Nineties-Public #5 ($8,639), A.E. Nineties-Public #7 ($2,206), Atlas
     America Public #11 ($2,789) and Atlas America Public #12-2003 ($1,568).

6.   This column reflects total cash distributions beginning with the first
     production from the program and includes the return of investor's capital.

7.   These percentages are calculated by dividing the entry for each partnership
     in the "Total Cash Dist. And Tax Savings" column by that partnership 's
     entry in the "Investor Capital" column.

8.   As of the date of this table there is not twelve months of production
     and/or not all wells are drilled or on-line to sell production.


                                       53

<PAGE>

Table 5 sets forth payments made to the managing general partners and its
affiliates from its previous partnerships.

                                     TABLE 5
       SUMMARY OF PAYMENTS TO THE MANAGING GENERAL PARTNER AND AFFILIATES
                           FROM PRIOR PARTNERSHIPS (1)
                            AS OF SEPTEMBER 15, 2006

<TABLE>
<CAPTION>
                                                                                                    Cumulative
                                                                      Leasehold                    Reimbursement
                                                       Cumulative   Drilling and     Cumulative   of General and
                                          Investor      Gathering    Completion      Operator's   Administrative
              Partnership                  Capital      Fees (1)      Costs (2)        Charges       Overhead
-------------------------------------   ------------   ----------   ------------     ----------   --------------
<S>                                     <C>             <C>         <C>              <C>             <C>
 1. Atlas L.P. #1 - 1985                $    600,000            0   $    600,000     $  293,167      $ 59,484
 2. A.E. Partners 1986                       631,250            0        631,250        234,553        97,996
 3. A.E. Partners 1987                       721,000            0        721,000        256,235        88,576
 4. A.E. Partners 1988                       617,050            0        617,050        223,043        88,160
 5. A.E. Partners 1989                       550,000            0        550,000        201,861        87,470
 6. A.E. Partners 1990                       887,500            0        887,500        333,269       104,450
 7. A.E. Nineties-10                       2,200,000            0      2,200,000        711,079       121,585
 8. A.E. Nineties-11                         750,000            0        761,802(3)     287,242       151,317
 9. A.E. Partners 1991                       868,750            0        867,500        303,952       135,067
10. A.E. Nineties-12                       2,212,500            0      2,272,017(3)     744,111       156,191
11. A.E. Nineties-JV 92                    4,004,813            0      4,157,700      1,377,322       275,329
12. A.E. Partners 1992                       600,000            0        600,000        173,104        67,013
13. A.E. Nineties-Public #1                2,988,960            0      3,026,348(3)     765,502       153,376
14. A.E. Nineties-1993 Ltd.                3,753,937            0      3,480,656(3)     908,451       176,498
15. A.E. Partners 1993                       700,000            0        689,940        229,199        49,763
16. A.E. Nineties-Public #2                3,323,920            0      3,324,668(3)     764,093       137,760
17. A.E. Nineties-14                       9,940,045            0      9,512,015(3)   2,697,078       501,719
18. A.E. Partners 1994                       892,500            0        892,500        247,316        62,924
19. A.E. Nineties-Public #3                5,800,990            0      5,800,990      1,321,414       243,980
20. A.E. Nineties-15                      10,954,715            0      9,859,244(3)   2,692,382       491,801
21. A.E. Partners 1995                       600,000            0        600,000        142,075        25,383
22. A.E. Nineties-Public #4                6,991,350            0      6,991,350      1,489,783       271,904
23. A.E. Nineties-16                      10,955,465            0     10,955,465      2,091,142       339,671
24. A.E. Partners 1996                       800,000            0        800,000        204,345        33,713
25. A.E. Nineties-Public #5                7,992,240            0      7,992,240      1,520,810       271,384
26. A.E. Nineties-17                       8,813,488            0      8,813,488      1,751,157       281,849
27. A.E. Nineties-Public #6                9,901,025            0      9,901,025      1,991,084       323,880
28. A.E. Partners 1997                       506,250            0        506,250        120,223        19,823
29. A.E. Nineties-18                      11,391,673            0     11,391,673      2,437,652       382,492
30. A.E. Nineties-Public #7               11,988,350            0     11,988,350      2,102,538       326,796
31. A.E. Partners 1998                     1,740,000            0      1,740,000        374,617        36,200
32. A.E. Nineties-19                      15,720,450            0     15,720,450      2,850,869       431,022
33. A.E. Nineties-Public #8               11,088,975            0     11,088,975      1,872,317       287,450
34. A.E. Partners 1999                       450,000            0        450,000         78,434         6,366
35. 1999 Viking Resources LP               4,555,210            0      4,555,210      1,982,841             0
36. Atlas America-Series 20               18,809,150            0     18,809,150      4,519,526       462,923
37. Atlas America-Public #9               14,905,465    1,014,515     14,905,465      1,998,304       305,719
38. Atlas America-Series 21-A             12,510,713      709,002     12,510,713      1,483,972       267,240
39. Atlas America-Series 21-B             17,411,825      919,399     17,411,825      1,818,803       320,480
40. Atlas America-Public #10              21,281,170    1,283,921     21,281,170      1,996,917       387,027
41. Atlas America-Series 22               10,156,375      591,474     10,156,375        854,151       166,219
42. Atlas America-Series 23                9,644,550      553,080      9,644,550        750,670       153,000
43. Atlas America-Public #11-2002         31,178,145    1,411,829     31,178,145      2,527,364       448,751
44. Atlas America - Series 24-2003(A)     14,363,955      507,095     14,363,955        939,654       170,156
45. Atlas America - Series 24-2003(B)     20,542,850      869,235     20,542,850      1,483,346       237,750
46. Atlas America - Public 12-2003        40,170,308    1,366,333     40,170,308      2,052,125       390,431
47. Atlas America Series 25-2004(A)       27,601,053    1,073,685     27,601,053      1,039,242       176,558
48. Atlas America Series 25-2004(B)       31,531,035      694,459     31,531,035      1,163,838       175,695
49. Atlas America Public #14-2004         52,506,570      882,979     52,506,570      1,134,047       172,009
50. Atlas America Public #14-2005(A)      69,674,900    1,077,515     69,674,900        665,317       132,486
51. Atlas America Series 26-2005          34,886,465      201,123     34,886,465        242,186        36,253
52. Atlas America Public #15-2005(A)      52,245,720      173,725     52,245,720        175,536        22,856
53. Atlas America Public #15-2006(B)     147,513,130            0    147,513,130              0             0
</TABLE>

----------
(1)  The amount of gathering fees paid to the managing general partner and its
     affiliates from 2001 to the date of this table are shown for those
     partnerships which began operations on or after December 31, 2000. The
     books and records of the earlier partnerships do not separately allocate
     all of the gathering fees paid by them. Additional information concerning
     the gathering fees paid by those partnerships will be provided to you on
     written request to the managing general partner.

(2)  Excluding the managing general partner's capital contributions.

(3)  Includes additional drilling costs paid with production revenues.


                                       54

<PAGE>

                                   MANAGEMENT

MANAGING GENERAL PARTNER AND OPERATOR

The partnerships will have no officers, directors or employees. Instead, Atlas
Resources, LLC, a Pennsylvania limited liability company, which was originally
formed as a corporation in 1979 and then changed to a limited liability company
on March 28, 2006, will serve as the managing general partner of each
partnership. However, see "- Transactions with Management and Affiliates,"
below, regarding the managing general partner's dependence on its indirect
parent company, Atlas America and its affiliates, for facilities, management and
administrative functions and financing for capital expenditures. The managing
general partner and its affiliates operate more than 5,100 natural gas and oil
wells located in the Appalachian Basin in the states of Ohio, Pennsylvania, New
York and Tennessee.

In addition, Atlas America (ATLS) has announced that it intends to transfer to
Atlas Energy Resources, LLC, a newly-formed, wholly-owned limited liability
company subsidiary of Atlas America, substantially all of its natural gas and
oil exploration and production assets. On July 28, 2006, Atlas Energy Resources,
LLC filed a registration statement with the SEC for an initial public offering
of 5,750,000 of its limited partner units. After the offering has concluded,
Atlas America will retain 83% of the limited partner units of Atlas Energy
Resources, LLC, which will continue to provide Atlas America control over Atlas
Energy Resources, LLC and its assets and business. This prospectus does not
constitute an offer to sell or a solicitation of an offer to buy any such
securities. Rather than transferring its energy assets directly to Atlas Energy
Resources, LLC, Atlas America intends to change its subsidiaries that currently
own those assets, including the managing general partner, into limited liability
company subsidiaries of Atlas Energy Resources, LLC, which would make Atlas
Energy Resources, LLC the indirect owner of the energy assets currently owned by
Atlas America's subsidiaries, including the managing general partner. Atlas
America anticipates that all of these transactions will be completed sometime
during 2007 on or following the closing of the public offering of limited
partner interests in Atlas Energy Resources, LLC discussed above. The
anticipated effect of Atlas America's intended transactions in connection with
Atlas Energy Resources, LLC can be seen by comparing the "- Current
Organizational Diagram" with the "- Pro Forma Organizational Diagram (Subject to
Change)" in "- Organizational Diagrams and Security Ownership of Beneficial
Owners," below.

Since 1985 the managing general partner has sponsored 16 public and 37 private
partnerships to conduct natural gas drilling and development activities in
Pennsylvania, Ohio, New York and Tennessee. In these partnerships the managing
general partner and its affiliates acted as the operator and the general
drilling contractor and were responsible for drilling, completing, and operating
the wells. Atlas Resources has a 97% completion rate for wells drilled by its
development partnerships.

In September 1998, Atlas Energy Group, Inc., the former parent company of the
managing general partner, merged into Atlas America, Inc., a Delaware holding
company, which was a subsidiary of Resource America, Inc., a publicly-traded
company, which is sometimes referred to in this private placement memorandum as
Resource America. In May 2004 Resource America conducted a public offering of a
portion of its common stock (the "shares") in Atlas America. Two million six
hundred forty-five thousand shares were registered and sold at a price of at
$15.50 per share resulting in gross proceeds of $41 million. Further, in May
2004, in connection with the Atlas America offering, the following officers and
key employees of the managing general partner and Atlas America set forth in "-
Officers, Directors and Other Key Personnel," below, resigned their positions
with Resource America and all of its subsidiaries that are not also subsidiaries
of Atlas America: Mr. Freddie M. Kotek, Mr. Frank P. Carolas, Mr. Jeffrey C.
Simmons, Ms. Nancy J. McGurk, Mr. Michael L. Staines, and Ms. Marci Bleichmar.

After the public offering, Resource America continued to own approximately 80.2%
of Atlas America's common stock until it distributed all of its remaining 10.7
million shares of common stock in Atlas America to its common stockholders on
June 30, 2005. The distribution was in the form of a spin-off by means of a tax
free dividend of approximately 0.6 shares of Atlas America to Resource America
common stockholders for each share of Resource America common stock owned. As a
result of the spin-off, Resource America is no longer in a position to determine
the outcome of corporate actions requiring the approval of Atlas America's
stockholders, such as:

     o    the election and removal of directors;


                                       55

<PAGE>

     o    mergers or other business combinations involving Atlas America;

     o    future issuances of Atlas America's common stock or other securities;
          and

     o    amendments to Atlas America's certificate of incorporation and bylaws.

These actions will be passed on by Atlas America's stockholders existing at the
record dates for such matters. Resource America's rights following the
distribution are defined by agreements between Resource America and Atlas
America.

Atlas America is headquartered at 311 Rouser Road, Moon Township, Pennsylvania
15108, near the Pittsburgh International Airport, which is also the managing
general partner's primary office.

OFFICERS, DIRECTORS AND OTHER KEY PERSONNEL OF MANAGING GENERAL PARTNER

The officers and directors of the managing general partner will serve until
their successors are elected. The officers, directors, and key personnel of the
managing general partner are as follows:

<TABLE>
<CAPTION>
NAME                  AGE   POSITION OR OFFICE
----                  ---   ------------------
<S>                    <C>  <C>
Freddie M. Kotek       50   Chairman of the Board of Directors, Chief Executive Officer and President
Frank P. Carolas       47   Executive Vice President - Land and Geology and a Director
Jeffrey C. Simmons     48   Executive Vice President - Operations and a Director
Jack L. Hollander      50   Senior Vice President - Direct Participation Programs
Nancy J. McGurk        50   Senior Vice President, Chief Financial Officer and Chief Accounting Officer
Michael L. Staines     57   Senior Vice President, Secretary and a Director
Michael G. Hartzell    51   Vice President - Land Administration
Donald R. Laughlin     58   Vice President - Drilling and Production
Marci F. Bleichmar     36   Vice President of Marketing
Sherwood S. Lutz       55   Senior Geologist/Manager of Geology
Michael W. Brecko      48   Director of Energy Sales
Karen A. Black         46   Vice President - Partnership Administration
Justin T. Atkinson     33   Director of Due Diligence
Winifred C. Loncar     65   Director of Investor Services
</TABLE>

With respect to the biographical information set forth below:

     o    The approximate amount of an individual's professional time devoted to
          the business and affairs of the managing general partner, Atlas
          America, Atlas Energy Resources, LLC and Atlas Energy Management,
          Inc., as set forth below, on completion of Atlas Energy Resources,
          LLC's initial public offering have been aggregated because there is no
          reasonable method for them to distinguish their activities between the
          companies.

     o    For those individuals who also hold senior positions with other
          affiliates of the managing general partner, if it is stated that they
          devote approximately 100% of their professional time to the managing
          general partner and Atlas America, it is because there is no
          reasonable method to distinguish their activities between the managing
          general partner and Atlas America as compared with the other
          affiliates of the managing general partner.

FREDDIE M. KOTEK. President and Chief Executive Officer since January 2002 and
Chairman of the Board of Directors since September 2001. Mr. Kotek has been
Executive Vice President of Atlas America since February 2004, and served as a
director from September 2001 until February 2004 and served as Chief Financial
Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice
President of Resource America and President of Resource Leasing, Inc. (a
wholly-owned subsidiary of Resource America) from 1995 until May 2004 when he
resigned from Resource America and all of its


                                       56

<PAGE>

subsidiaries which are not subsidiaries of Atlas America. Mr. Kotek was
President of Resource Properties from September 2000 to October 2001 and its
Executive Vice President from 1993 to August 1999. Mr. Kotek received a Bachelor
of Arts degree from Rutgers College in 1977 with high honors in Economics. He
also received a Master in Business Administration degree from the Harvard
Graduate School of Business Administration in 1981. Mr. Kotek will devote
approximately 95% of his professional time to the business and affairs of the
managing general partner and Atlas America, and the remainder of his
professional time to the business and affairs of the managing general partner's
affiliates.

FRANK P. CAROLAS. Executive Vice President - Land and Geology and a Director
since January 2001. Mr. Carolas has been an Executive Vice President of Atlas
America since January 2001 and served as a Director of Atlas America from
January 2002 until February 2004. Mr. Carolas has been a Senior Vice President
of Atlas Energy Management, Inc. since 2006. Mr. Carolas was a Vice President of
Resource America from April 2001 until May 2004 when he resigned from Resource
America. Mr. Carolas served as Vice President of Land and Geology for the
managing general partner from July 1999 until December 2000 and for Atlas
America from 1998 until December 2000. Before that Mr. Carolas served as Vice
President of Atlas Energy Group, Inc. from 1997 until 1998, which was the former
parent company of the managing general partner. Mr. Carolas is a certified
petroleum geologist and has been with the managing general partner and its
affiliates since 1981. He received a Bachelor of Science degree in Geology from
Pennsylvania State University in 1981 and is an active member of the American
Association of Petroleum Geologists. Mr. Carolas devotes approximately 100% of
his professional time to the business and affairs of the managing general
partner and Atlas America.

JEFFREY C. SIMMONS. Executive Vice President - Operations and a Director since
January, 2001. Mr. Simmons has been an Executive Vice President of Atlas America
since January 2001 and was a Director of Atlas America from January 2002 until
February 2004. Mr. Simmons has been a Senior Vice President of Atlas Energy
Management, Inc. since 2006. Mr. Simmons was a Vice President of Resource
America from April 2001 until May 2004 when he resigned from Resource America.
Mr. Simmons served as Vice President of Operations for the managing general
partner from July 1999 until December 2000 and for Atlas America from 1998 until
December 2000. Mr. Simmons joined Resource America in 1986 as a senior petroleum
engineer and has served in various executive positions with its energy
subsidiaries since then. Mr. Simmons received his Bachelor of Science degree
with honors in Petroleum Engineering from Marietta College in 1981 and his
Masters degree in Business Administration from Ashland University in 1992. Mr.
Simmons devotes approximately 90% of his professional time to the business and
affairs of the managing general partner and Atlas America, and the remainder of
his professional time to the business and affairs of the managing general
partner's affiliates, primarily Viking Resources and Resource Energy.

JACK L. HOLLANDER. Senior Vice President - Direct Participation Programs since
January 2002 and before that he served as Vice President - Direct Participation
Programs from January 2001 until December 2001. Mr. Hollander also serves as
Senior Vice President - Direct Participation Programs of Atlas America since
January 2002. Mr. Hollander practiced law with Rattet, Hollander & Pasternak,
concentrating in tax matters and real estate transactions, from 1990 to January
2001, and served as in-house counsel for Integrated Resources, Inc. (a
diversified financial services company) from 1982 to 1990. Mr. Hollander earned
a Bachelor of Science degree from the University of Rhode Island in 1978, his
law degree from Brooklyn Law School in 1981, and a Master of Law degree in
Taxation from New York University School of Law Graduate Division in 1982. Mr.
Hollander is a member of the New York State bar and the Chairman of the
Investment Program Association, which is an industry association, as of March
2005. Mr. Hollander devotes approximately 100% of his professional time to the
business and affairs of the managing general partner and Atlas America.

NANCY J. MCGURK. Senior Vice President since January 2002, Chief Financial
Officer and Chief Accounting Officer since January 2001. Ms. McGurk also serves
as Senior Vice President since January 2002 and Chief Accounting Officer of
Atlas America since January 2001. Ms. McGurk has been Chief Accounting Officer
of Atlas Energy Resources, LLC and Atlas Energy Management, Inc. since 2006. Ms.
McGurk served as Chief Financial Officer for Atlas America from January 2001
until February 2004. Ms. McGurk was a Vice President of Resource America from
1992 until May 2004 and its Treasurer and Chief Accounting Officer from 1989
until May 2004 when she resigned from Resource America. Also, since 1995 Ms.
McGurk has served as Vice President - Finance of Resource Energy, Inc. Ms.
McGurk received a Bachelor of Science degree in Accounting from Ohio State
University in 1978, and has been a Certified Public Accountant since 1982. Ms.


                                       57

<PAGE>

McGurk will devote approximately 80% of her professional time to the business
and affairs of the managing general partner and Atlas America, and the remainder
of her professional time to the business and affairs of the managing general
partner's affiliates.

MICHAEL L. STAINES. Senior Vice President, Secretary, and a Director since 1998.
Mr. Staines has been an Executive Vice President and Secretary of Atlas America
since 1998. Mr. Staines was a Senior Vice President of Resource America from
1989 until May 2004 when he resigned from Resource America. Mr. Staines was a
director of Resource America from 1989 to February 2000 and Secretary from 1989
to October 1998. Mr. Staines has been President of Atlas Pipeline Partners GP
since January 2001 and its Chief Operating Officer and a member of its Managing
Board since its formation in November 1999. Mr. Staines is a member of the Ohio
Oil and Gas Association and the Independent Oil and Gas Association of New York.
Mr. Staines received a Bachelor of Science degree from Cornell University in
1971 and a Master of Business degree from Drexel University in 1977. Mr. Staines
will devote approximately 5% of his professional time to the business and
affairs of the managing general partner and Atlas America, and the remainder of
his professional time to the business and affairs of the managing general
partner's affiliates, including Atlas Pipeline Partners GP.

MICHAEL G. HARTZELL. Vice President - Land Administration since September 2001.
Mr. Hartzell has been Vice President - Land Administration of Atlas America
since January 2002, and before that served as Senior Land Coordinator from
January 1999 to January 2002. Mr. Hartzell has been Vice President - Land
Administration of Atlas Energy Management, Inc. since 2006. Mr. Hartzell has
been with the managing general partner and its affiliates since 1980 when he
began his career as a land department representative. Mr. Hartzell manages all
Land Department functions. Mr. Hartzell serves on the Environmental Committee of
the Independent Oil and Gas Association of Pennsylvania and is a past Chairman
of the Committee. Mr. Hartzell received his Bachelor of Science degree in
Business Management from the University of Phoenix in 2004. Mr. Hartzell devotes
approximately 100% of his professional time to the business and affairs of the
managing general partner and Atlas America.

DONALD R. LAUGHLIN. Vice President - Drilling and Production since September
2001. Mr. Laughlin also serves as Vice President - Drilling and Production for
Atlas America since January 2002, and before that served as Senior Drilling
Engineer since May 2001 when he joined Atlas America. Mr. Laughlin has been Vice
President - Drilling and Production of Atlas Energy Management, Inc. since 2006.
Mr. Laughlin has over thirty years of experience as a petroleum engineer in the
Appalachian Basin, having been employed by Columbia Gas Transmission Corporation
from October 1995 to May 2001 as a senior gas storage engineer and team leader,
Cabot Oil & Gas Corporation from 1989 to 1995 as Manager of Drilling Operations
and Technical Services, Doran & Associates, Inc. from 1977 until 1989 as Vice
President--Operations, and Columbia Gas from 1970 to 1977 as Drilling Engineer
and Gas Storage Engineer. Mr. Laughlin received his Petroleum Engineering degree
from the University of Pittsburgh in 1970. He is a member of the Society of
Petroleum Engineers. Mr. Laughlin devotes approximately 100% of his professional
time to the business and affairs of the managing general partner and Atlas
America.

MARCI F. BLEICHMAR. Vice President of Marketing since February 2001. Ms.
Bleichmar also serves as Vice President of Marketing for Atlas America since
February 2001 and was with Resource America from February 2001 until May 2004
when she resigned from Resource America. From March 2000 until February 2001,
Ms. Bleichmar served as Director of Marketing for Jacob Asset Management (a
mutual fund manager), and from March 1998 until March 2000, she was an account
executive at Bloomberg Financial Services LP. From November 1994 until 1998, Ms.
Bleichmar was an Associate on the Derivatives Trading Desk of JP Morgan. Ms.
Bleichmar received a Bachelor of Arts degree from the University of Wisconsin in
1992. Ms. Bleichmar devotes approximately 100% of her professional time to the
business and affairs of the managing general partner and Atlas America.

SHERWOOD S. LUTZ. Senior Geologist/Manager of Geology. In 1996 Mr. Lutz joined
Viking Resources, which was purchased by Resource America in 1999 as senior
geologist. Since 1999 Mr. Lutz has been a senior geologist for the managing
general partner and Atlas America. Mr. Lutz received his Bachelor of Science
degree in Geological Sciences from the Pennsylvania State University in 1973.
Mr. Lutz is a certified petroleum geologist with the American Association of
Petroleum Geologists as well as a licensed professional geologist in
Pennsylvania. Mr. Lutz devotes approximately 100% of his professional time to
the business and affairs of the managing general partner and Atlas America.


                                       58

<PAGE>

MICHAEL W. BRECKO. Director of Energy Sales since November 2002. Mr. Brecko has
over 19 years of natural gas marketing experience in the oil and natural gas
industry. Mr. Brecko is a 1980 graduate from The Pennsylvania State University
with a Bachelor of Science degree in Civil Engineering. His career in natural
gas marketing began when he joined Equitable Gas Company, a local distribution
company, as a marketing representative in the commercial/ industrial marketing
division from May 1986 to August 1992. He subsequently joined O&R Energy, a
subsidiary of Orange and Rockland Utilities, as regional marketing manager from
August 1992 to November 1993. Beginning in December 1993 through July 2001, Mr.
Brecko worked for Cabot Oil & Gas Corporation, a mid-sized Appalachian oil and
natural gas producer, as an account executive and he was promoted in August 1998
to natural gas trader. In November 2001, he joined Sprague Energy Corporation, a
multi-energy sourced company, as a regional account manager before joining Atlas
America in 2002. Mr. Brecko devotes approximately 100% of his professional time
to the business and affairs of the managing general partner and Atlas America.

KAREN A. BLACK. Vice President - Partnership Administration since February 2003.
Ms. Black is also Vice President and Financial and Operations Principal of
Anthem Securities since October 2002. Ms. Black joined the managing general
partner and Atlas America in July 2000 and served as manager of production,
revenue and partnership accounting from July 2000 through October 2001, after
which she served as manager and financial analyst until her appointment as Vice
President - Partnership Administration. Before joining the managing general
partner in 2000, Ms. Black was associated with Texas Keystone, Inc. as
controller from April 1997 through June 2000. Ms. Black was employed as a tax
accountant for Sobol Bosco & Associates, Inc. from May 1996 through March 1997.
Ms. Black received a Bachelor of Arts degree from the University of Pittsburgh,
Johnstown in 1982. Ms. Black devotes approximately 50% of her professional time
to the business and affairs of the managing general partner and Atlas America,
and the remainder of her professional time to the business and affairs of Anthem
Securities.

JUSTIN T. ATKINSON. Director of Due Diligence since February 2003. Mr. Atkinson
also serves as President of Anthem Securities since February 2004 and as Chief
Compliance Officer since October 2002. Before that Mr. Atkinson served as
assistant compliance officer of Anthem Securities from December 2001 until
October 2002 and Vice President from October 2002 until February 2004. Before
his employment with the managing general partner, Mr. Atkinson was a manager of
investor and broker/dealer relations with Viking Resources Corporation from 1996
until November 2001. Mr. Atkinson earned a Bachelor of Arts degree in Business
Management in 1995 from Walsh University in North Canton, Ohio. Mr. Atkinson
devotes approximately 25% of his professional time to the business and affairs
of the managing general partner and Atlas America, and the remainder of his
professional time to the business and affairs of Anthem Securities.

WINIFRED C. LONCAR, Director of Investor Services since February 2003. Ms.
Loncar previously held the position of manager of investor services from the
inception of the investor service department in 1990 to February 2003. Before
that she was executive secretary to the managing general partner. Ms. Loncar
received a Bachelor of Science degree in Business from Point Park University in
1998. Ms. Loncar devotes approximately 100% of her professional time to the
business and affairs of the managing general partner and Atlas America.

ATLAS AMERICA, INC., A DELAWARE COMPANY

As of August 24, 2006, the officers and directors for Atlas America include the
following:

NAME                   AGE   POSITION
----                   ---   --------
Edward E. Cohen         67   Chairman, Chief Executive Officer and President
Frank P. Carolas        47   Executive Vice President
Freddie M. Kotek        50   Executive Vice President
Jeffrey C. Simmons      47   Executive Vice President
Michael L. Staines      57   Executive Vice President and Secretary
Matthew A. Jones        44   Chief Financial Officer
Nancy J. McGurk         50   Senior Vice President and Chief Accounting Officer
Jonathan Z. Cohen       36   Vice Chairman
Carlton M. Arrendell    44   Director


                                       59

<PAGE>

NAME                   AGE   POSITION
----                   ---   --------
William R. Bagnell      43   Director
Donald W. Delson        55   Director
Nicholas DiNubile       54   Director
Dennis A. Holtz         66   Director
Harmon S. Spolan        70   Director

See "- Officers, Directors and Other Key Personnel," above, for biographical
information on certain of these individuals who are also officers of the
managing general partner. Biographical information on the other officers and
directors will be provided by the managing general partner on request.

The managing general partner and its affiliates under Atlas America employ more
than 205 persons.

ORGANIZATIONAL DIAGRAMS AND SECURITY OWNERSHIP OF BENEFICIAL OWNERS

Atlas America owns 100% of the common stock of AIC, LLC, which owns 100% of the
common stock of the managing general partner. The directors of AIC, LLC are
Jonathan Z. Cohen, Michael L. Staines, and Jeffrey C. Simmons. The biographies
of Messrs. Staines and Simmons are set forth above. Although Atlas Energy
Resources, LLC and Atlas Energy Management, Inc. have been formed as described
in "- Pro Forma Organizational Diagram (Subject to Change)," below, as of the
date of this private placement memorandum not all of the transfers have been
made that will result in the entities described under Atlas America other than
Atlas Pipeline Holdings, L.P. (AHD), and its subsidiaries, and Atlas Pipeline
Holdings GP, LLC becoming subsidiaries of Atlas Energy Resources, LLC on or
after completing its initial public offering as discussed in "- Managing General
Partner and Operator," above.

                         CURRENT ORGANIZATIONAL DIAGRAM

<TABLE>
<S>                <C>             <C>            <C>   <C>                  <C>             <C>       <C>           <C>
                                                ----------------------------------
                                                  Atlas America, Inc. (Delaware)
                                                (driller and operator in Ohio) (3)
                                                ----------------------------------
                                                                 |
                                                                 |
                                                                 |
         -------------------------------------------------------------------------------------------------------------------
        |                 |              |          |             |                 |            |          |               |
        |                 |              |          |             |                 |            |          |               |
        |                 |              |          |             |                 |            |          |               |
-----------------  --------------  -------------  ----  -------------------  --------------  --------  ------------  ------------
 Atlas Pipeline    Atlas Pipeline  Atlas Energy   AIC,  Atlas America, Inc.      Viking      Resource  Atlas Noble,       AED
 Holdings, L.P.     Holdings GP,     Management,  LLC      (Pennsylvania)    Resources, LLC   Energy,    LLC (2)     Investments,
       (2)            LLC, non-    Inc. (Manager  ----  (operating company)        (1)        LLC (1)                    Inc.
-----------------     economic       of Atlas       |   -------------------  --------------  --------  ------------  ------------
        |             general         Energy        |                                            |
        |             partner       Resources,      |--------------------------------------      |
        |           interest in         LLC         |                 |                   |       --------------------
        |          Atlas Pipeline  -------------    |                 |                   |              |           |
-----------------      Holdings,        -------------------  ------------------  ------------------  -------  -------------
 Atlas Pipeline        L.P.                Atlas Resources,     Atlas Energy,    Anthem Securities,  REI-NY,  Resource Well
   Partners GP,    --------------           LLC, managing       LLC, managing          Inc.,          LLC     Services, LLC
  LLC, general                           general partner of  general partner of     registered       -------  -------------
partner interest                           Atlas America          exploratory      broker/dealer
in Atlas Pipeline                          Series 27-2006        drilling           and dealer-
  Partners, L.P.                         L.P., driller and   partnerships and          manager
-----------------                            operator in         driller and
        |                                   Pennsylvania          operator
        |                               -------------------  ------------------  ------------------
        |
        |
-----------------
  Atlas Pipeline
  Partners, L.P.
-----------------
        |
        |
        |
        |
-----------------
 Atlas Pipeline
    Operating
  Partnership,
       L.P.
-----------------
</TABLE>


                                       60

<PAGE>

(1)  Viking Resources, Resource Energy, and Atlas Noble, LLC are also engaged in
     the oil and gas business. Atlas America manages their assets and employees
     including sharing common employees. Also, many of the officers and
     directors of the managing general partner serve as officers and directors
     of those entities.

(2)  On January 12, 2006, Atlas Pipeline Holdings, L.P., a wholly-owned
     subsidiary of Atlas America, filed a registration statement with the SEC
     for an initial public offering of 3.6 million of its common units, which
     represented an approximate 17.1% limited partner interest in the company.
     On July 26, 2006, Atlas Pipeline Holdings, L.P. issued 3.6 million common
     units, representing a 17.1% ownership interest, in the initial public
     offering at a price of $23 per unit, and the underwriters were granted a
     30-day option to purchase up to an additional 540,000 common units.
     Substantially all of the net proceeds from this offering, approximately $77
     million, have been paid to Atlas America. Atlas America continues to own
     approximately 82.9% of Atlas Pipeline Holdings GP, LLC, which gives Atlas
     America indirect general partner control over Atlas Pipeline Partners
     (APL).

(3)  See "- Managing General Partner and Operator," above, and "- Pro Forma
     Organizational Diagram (Subject to Change)," below, regarding Atlas
     America's new subsidiary, Atlas Energy Resources, LLC, which recently filed
     a registration statement with the SEC for an initial public offering of
     5,750,000 common units representing an approximate 17% limited partner
     interest in the company. After the offering, Atlas America will retain
     approximately 83% of the limited partner units and all of the net proceeds
     of the offering will be paid to Atlas America. This private placement
     memorandum does not constitute an offer to sell or a solicitation of an
     offer to buy any securities in Atlas Energy Resources, LLC.

              PRO FORMA ORGANIZATIONAL DIAGRAM (SUBJECT TO CHANGE)

The following pro forma organizational diagram is subject to change, because it
reflects certain transactions that Atlas America anticipates will happen in the
near future, but which have not yet happened as of the date of this prospectus.
The anticipated transactions set forth in the following diagram include, for
example, Atlas America's changing many of its subsidiaries to limited liability
subsidiaries of Atlas Energy Resources, LLC. The changes in the following
organizational diagram from the "- Current Organizational Diagram" set forth
above, relate to Atlas America's intention to transfer to Atlas Energy
Resources, LLC, substantially all of its natural gas and oil exploration and
production assets. Atlas America anticipates that all of these transactions will
be completed before or on the closing of Atlas Energy Resources, LLC's public
offering as described in "- Managing General Partner and Operator," above. This
prospectus does not constitute an offer to sell or a solicitation of an offer to
buy those securities.


                                       61

<PAGE>

<TABLE>
<S>                  <C>                   <C>                 <C>                             <C>           <C>
                            ------------------------
                               Atlas America, Inc.
                            (A Delaware corporation)
                            ------------------------
                                        |
        |-------------------------------------------------------------------------------------------------------------|
        |                    |                     |                        |                       |                 |
-------------------  --------------------  ------------------  ------------------------------  ------------  ------------------
  Atlas Pipeline        Atlas Pipeline        Atlas Energy     Atlas Energy Management, Inc.,       AED        Atlas America,
Holdings, L.P. (2)    Holdings GP, LLC,    Resources, LLC (1)      manager of Atlas Energy     Investments,         Inc.
-------------------  non-economic general    (Pennsylvania)          Resources, LLC (1)            Inc.      (Pennsylvania) (1)
        |            partner interest in   ------------------  ------------------------------  ------------  ------------------
        |               Atlas Pipeline
-------------------     Holdings, L.P.        |-------------------------------------------|
  Atlas Pipeline     --------------------     |            |             |                |
     Partners                              ---------  ------------  -----------   --------------
 GP, LLC, general                          AIC, LLC   Atlas Noble,   Resource         Viking
partner interest in                          (1)         LLC (1)    Energy, LLC   Resources, LLC
  Atlas Pipeline                           ---------  ------------      (1)             (1)
  Partners, L.P.                              |                      ------------  --------------
-------------------                           |    -----------------------  |
        |                                     |    Atlas Energy Ohio, LLC   |
        |                                     |---      (1) (Ohio)          |
-------------------                           |    ----------------------   |    ----------------
  Atlas Pipeline                              |                             |---  REI-NY, LLC (1)
  Partners, L.P.                              |    -----------------------  |    ----------------
-------------------                           |    Atlas Resources, LLC     |
        |                                     |---          (1)             |    -----------------
        |                                     |    -----------------------  |       Resource Well
-------------------                           |                             |--- Services, LLC (1)
  Atlas Pipeline                              |    -----------------------       -----------------
    Operating                                 |--- Anthem Securities, Inc.
 Partnership, L.P.                                 -----------------------
-------------------
</TABLE>

(1)  All of these companies would be engaged in the oil and gas exploration and
     production business. Atlas America would continue to manage their assets
     and employees including sharing common employees. Also, many of the
     officers and directors of the managing general partner would serve as
     officers and directors of those entities.

(2)  See footnote (2) to "- Current Organizational Diagram," above.

ATLAS ENERGY RESOURCES, LLC, A DELAWARE LIMITED LIABILITY COMPANY

As of July 28, 2006, the directors, nominees and executive officers for Atlas
Energy Resources, LLC include the following:

NAME                AGE   POSITION OR OFFICE
----                ---   ------------------
Edward E. Cohen      67   Chairman of the Board and Chief Executive Officer
Jonathan Z. Cohen    36   Vice Chairman of the Board
Richard D. Weber     43   President, Chief Operating Officer and Director
Matthew A. Jones     44   Chief Financial Officer and Director
Nancy J. McGurk      50   Chief Accounting Officer
Walter C. Jones      43   Director Nominee
Ellen F. Warren      50   Director Nominee
Bruce M. Wolf        58   Director Nominee

See "- Officers, Directors and Other Key Personnel," above, for biographical
information on Ms. McGurk, who also is an officer of the managing general
partner. Also, on May 9, 2006 Mr. Richard Weber was appointed President, Chief
Operating Officer and a director of Atlas Energy Resources, LLC. In conjunction
with Mr. Weber's appointment, Atlas America and Mr. Weber entered into an
employment agreement dated April 5, 2006. Mr. Weber served from June 1997 until
March 2006 as Managing Director and Group Head of the Energy Group of KeyBanc
Capital Markets, a division of KeyCorp, and its predecessor, McDonald & Company
Securities, Inc. As part of his duties, he oversaw the bank's activities with
oil and gas producers, pipeline companies and utilities. He has a particular
expertise in the Appalachian Basin, where he led over 40 transactions, including
the IPOs of Atlas America and Atlas Pipeline and the sale of Viking Resources
Corporation to Atlas America.

Biographical information on the other officers and directors of Atlas Energy
Resources, LLC will be provided by the managing general partner on request.


                                       62

<PAGE>

ATLAS ENERGY MANAGEMENT, INC., A DELAWARE COMPANY

As of July 28, 2006, the officers for Atlas Energy Management, LLC include the
following:

NAME                  AGE   POSITION OR OFFICE
----                  ---   ------------------
Edward E. Cohen        67   Chairman of the Board and Chief Executive Officer
Richard D. Weber       43   President, Chief Operating Officer and Director
Jeffrey C. Simmons     48   Senior Vice President
Frank P. Carolas       47   Senior Vice President
Matthew A. Jones       44   Chief Financial Officer
Nancy J. McGurk        50   Chief Accounting Officer
Donald R. Laughlin     58   Vice President - Drilling and Production
Michael G. Hartzell    51   Vice President - Land Administration
Lisa Washington        39   Chief Legal Officer and Secretary

See "- Officers, Directors and Other Key Personnel," above, for biographical
information on certain of these individuals who are also officers of the
managing general partner. Biographical information on the other officers and
directors will be provided by the managing general partner on request.

REMUNERATION OF OFFICERS AND DIRECTORS

No officer or director of the managing general partner will receive any direct
remuneration or other compensation from the partnerships. These persons will
receive compensation solely from affiliated companies of the managing general
partner.

CODE OF BUSINESS CONDUCT AND ETHICS

Because the partnerships do not directly employ any persons, the managing
general partner has determined that the partnerships will rely on a Code of
Business Conduct and Ethics adopted by Atlas America, Inc. that applies to the
principal executive officer, principal financial officer and principal
accounting officer of the managing general partner, as well as to persons
performing services for the managing general partner generally. You may obtain a
copy of this Code of Business Conduct and Ethics by a request to the managing
general partner at Atlas Resources, LLC, 311 Rouser Road, Moon Township,
Pennsylvania 15108.

TRANSACTIONS WITH MANAGEMENT AND AFFILIATES

The managing general partner depends on its indirect parent company, Atlas
America and its affiliates, for management and administrative functions and
financing for capital expenditures. The managing general partner currently pays
a management fee to Atlas America for management and administrative services,
which amounted to $45.7 million, $21.6 million, and $13.1 million for the years
ended September 30, 2005, 2004, and 2003, respectively. (See "Financial
Information Concerning the Managing General Partner and Atlas America Public
#16-2007(A) L.P.," including the indebtedness owed by the managing general
partner to Atlas America.)

The managing general partner and its officers, directors and affiliates have in
the past invested, and may in the future invest, in partnerships sponsored by
the managing general partner. They may also subscribe for units in the
partnerships as described in "Plan of Distribution."

                     MANAGEMENT'S DISCUSSION AND ANALYSIS OF
                  FINANCIAL CONDITION, RESULTS OF OPERATIONS,
                        LIQUIDITY AND CAPITAL RESOURCES

Both of the partnerships have been formed as limited partnerships under the
Delaware Revised Uniform Limited Partnership Act. The partnerships, however,
have not included any historical information in this prospectus since they have
no net worth, do not own any properties on which wells will be drilled, have no
third-party investors, and have not conducted any operations. (See
"Capitalization and Source of Funds and Use of Proceeds," "Proposed Activities,"
"Competition, Markets


                                       63

<PAGE>

and Regulation," and "Financial Information Concerning the Managing General
Partner and Atlas America Public #16-2007(A) L.P.")

Each partnership will depend on the proceeds of this offering and the managing
general partner's capital contributions to carry out its proposed activities.
Each partnership intends to use its subscription proceeds to pay the following:

     o    the intangible drilling costs of the partnership's wells;

     o    the investors' share of equipment costs of the partnership's wells;
          and

     o    the investors' share of any cost overruns of drilling and completing
          the partnership's wells.

The managing general partner believes that each partnership's liquidity
requirements will be satisfied from the following:

     o    subscription proceeds of this offering;

     o    the managing general partner's capital contributions;

     o    cash flow from future operations; and

     o    partnership borrowings, if necessary.

The managing general partner also anticipates that no additional funds will be
required for operating costs before a partnership begins receiving production
revenues from its wells.

Substantially all of the subscription proceeds of you and the other investors in
a partnership will be committed or expended after the offering of the
partnership closes. If a partnership requires additional funds for cost overruns
or additional development or remedial work after a well begins producing, then
these funds may be provided by:

     o    subscription proceeds, if available;

     o    drilling fewer wells, or acquiring a lesser working interest in one or
          more wells;

     o    borrowings from the managing general partner or its affiliates; or

     o    retaining partnership revenues.

There will be no borrowings from third-parties. The amount that may be borrowed
by a partnership from the managing general partner and its affiliates may not at
any time exceed 5% of the partnership's subscription proceeds from you and the
other investors and must be without recourse to you and the other investors. The
partnership's repayment of any borrowings would be from partnership production
revenues and would reduce or delay your cash distributions.

If the managing general partner loans money to a partnership, which it is not
required to do, then:

     o    the interest charged to the partnership must not exceed the managing
          general partner's interest cost or the interest that would be charged
          to the partnership without reference to the managing general partner's
          financial abilities or guarantees by unrelated lenders, on comparable
          loans for the same purpose; and

     o    the managing general partner may not receive points or other financing
          charges or fees, although the actual amount of the charges incurred
          from third-party lenders may be reimbursed to the managing general
          partner.


                                       64

<PAGE>

As of the date of this prospectus, Atlas America (the "borrower") has a $200
million revolving credit facility with a group of banks with Wachovia Bank, N.A.
as the administrative agent and issuing bank. The managing general partner and
various energy subsidiaries of Atlas America are guarantors of the credit
agreement. As of April 27, 2006, this facility had a borrowing base of $130
million. Borrowings under the facility are collateralized by substantially all
of the assets of Atlas America and the other guarantors, including the managing
general partner (collectively the "obligors"). These assets include the managing
general partner's interests in the partnerships, but do not include any
investor's interest in a partnership. A breach of the credit agreement by the
borrower is a default under the loan. The credit facility's term ends in April
2010. At May 9, 2006, the borrower had an outstanding balance of approximately
$54 million and also had a $6.5 million letter of credit issued under the
facility. Under the credit facility, the obligors are subject to substantial
restrictions and financial covenants and ratios. For example, the credit
facility restricts the ability of the obligors to obtain additional financing,
make investments, lease equipment, sell assets and engage in business
combinations. The failure to comply with any of the restrictions and covenants
under the credit facility could result in a default, which could cause all of
the existing indebtedness to be immediately due.

The managing general partner depends on its indirect parent company, Atlas
America and its affiliates, for management and administrative functions and
financing for capital expenditures. The managing general partner pays a
management fee to Atlas America for management and administrative services, as
described in "Management - Transactions with Management and Affiliates." See the
footnotes to the managing general partner's audited financial statements and the
footnotes to the managing general partner's unaudited financial statements for
more details concerning the credit facility and inter-company borrowings in
"Financial Information Concerning the Managing General Partner and Atlas America
Public #16-2007(A) L.P."

                              PROPOSED ACTIVITIES

OVERVIEW OF DRILLING ACTIVITIES

The managing general partner anticipates that the subscription proceeds of each
partnership will be used to drill primarily natural gas development wells, which
means a well drilled within the proved area of a natural gas or oil reservoir to
the depth of a stratigraphic horizon known to be productive. Stratigraphic means
a layer of rock which has characteristics that differentiate it from the rocks
above and below it. Stratigraphic horizon generally means that part of a
formation or layer of rock with sufficient porosity and permeability to form a
petroleum reservoir. Currently, the partnerships do not hold any interests in
any properties or prospects on which the wells will be drilled.

Although the majority of the wells to be drilled by each partnership will be
classified as natural gas wells, which may produce a small amount of oil, some
of the wells, such as wells drilled in McKean County, Pennsylvania, if any, may
be classified as oil or combination oil and natural gas wells.

Each partnership will be a separate business entity from the other partnership,
and you will be a partner only in the partnership in which you invest. You will
have no interest in the business, assets or tax benefits of the other
partnership unless you also invest in the other partnership. Thus, your
investment return will depend solely on the operations and success or lack of
success of the particular partnership in which you invest.

Each partnership generally will drill different wells, but they may own working
interests and participate in drilling and completing one or more of the same
wells. The number of wells to be drilled by a partnership cannot be determined
precisely before the funding of the partnership and is determined primarily by:

     o    the amount of subscription proceeds raised by the partnership;

     o    the geographical areas in which wells are drilled by the partnership;

     o    the partnership's percentage of working interest owned in the wells,
          which could range from 25% to 100%; and


                                       65

<PAGE>

     o    the cost of the partnership's wells, including any cost overruns for
          intangible drilling costs and equipment costs of the wells which are
          charged to you and the other investors under the partnership
          agreement.

For the estimated number of wells to be drilled at the minimum subscription
proceeds of $2 million and the maximum subscription proceeds of $200 million for
a partnership, see "Risk Factors - Risks Related to an Investment in a
Partnership - Spreading the Risks of Drilling Among a Number of Wells Will be
Reduced if Less than the Maximum Subscription Proceeds are Received and Fewer
Wells are Drilled."

Before the managing general partner selects a prospect on which a well will be
drilled by a partnership, it will review all available geologic and production
data for wells located in the vicinity of the proposed well including, but not
limited to:

     o    various well logs;

     o    completion reports;

     o    plugging reports; and

     o    production reports.

For example, production information from surrounding wells in the area is an
important indicator in evaluating the economic potential of a proposed well to
be drilled. It has been the managing general partner's experience that natural
gas production from wells drilled to the formations or the reservoirs in the
areas of operations discussed below in "- Primary Areas of Operations," is
reasonably consistent with nearby wells, although from time to time there can be
great differences in the natural gas volumes and performance of wells located on
contiguous prospects. However, production information is only one factor, and
the managing general partner may propose a well to be drilled by a partnership
because geologic trends in the immediate area, such as sand thickness,
porosities and water saturations, lead the managing general partner to believe
that the proposed well locations will be productive.

PRIMARY AREAS OF OPERATIONS

The managing general partner will not decide on all of the specific wells to be
drilled by a partnership until the offering of units in that partnership has
ended. However, the managing general partner intends that Atlas America Public
#16-2007(A) L.P. will drill the prospects described in "Appendix A - Information
Regarding Currently Proposed Prospects for Atlas America Public #16-2007(A)
L.P." These prospects represent the wells to be drilled if a portion of the
nonbinding targeted subscription proceeds for that partnership, as described in
"Terms of the Offering - Subscription to a Partnership," are received. If there
are material adverse events with respect to any of the currently proposed
prospects, the managing general partner will substitute a new prospect as
discussed below in "- Interests of Parties." Also, the managing general partner
has the sole discretion to sell up to and including all of the units in Atlas
America Public #16-2007(A) L.P., and it may and not offer and sell any units in
Atlas America Public #16-2007(B) L.P. In that event, the number of prospects
identified in "Appendix A - Information Regarding Currently Proposed Prospects
for Atlas America Public #16-2007(A) L.P." as a percentage of the total number
of prospects to be drilled by Atlas America Public #16-2007(A) L.P. would be
reduced. The managing general partner also anticipates that it will designate a
portion of the prospects in the partnership designated Atlas America Public
#16-2007(B) L.P., if units in that partnership are offered, by a supplement or
an amendment to the registration statement of which this prospectus is a part.

Because not all of the prospects for each partnership will be specified, you
will not be able to evaluate all of the prospects that will be drilled by your
partnership. However, by waiting as long as possible before selecting all of the
prospects to be drilled by a partnership, the managing general partner may
acquire additional information to help it select better prospects for the
partnership, and it may be able to include prospects that were not available
when this prospectus was written or even when the offering of units in the
partnership is closed.

The following discussion includes a general description of the areas where the
managing general partner anticipates partnership wells may be drilled. All of
the areas are situated in the Appalachian Basin, which is a mature producing
region


                                       66

<PAGE>

in the United States overlaying the states of New York, Pennsylvania, Ohio,
Tennessee, West Virginia, Maryland, Kentucky and Virginia. The Appalachian Basin
has well known geologic characteristics as described below, although with
respect to each area listed below, the geological aspects are continually being
evaluated by the managing general partner. Thus, each area discussed may
ultimately include other counties which are not set forth below. For purposes of
this prospectus, however, the counties listed below are generally descriptive of
the specific drilling area being discussed. With the exception of the north
central Tennessee area, the primary areas are situated in western Pennsylvania
as discussed below. The three primary areas for the partnerships' drilling
activities are:

     o    the Mississippian/Upper Devonian Sandstone reservoirs in Fayette,
          Greene and Westmoreland Counties, Pennsylvania;

     o    the Clinton/Medina geological formation which includes western
          Pennsylvania, primarily Crawford and Mercer Counties, Pennsylvania and
          also includes an area in eastern Ohio situated primarily in Stark,
          Mahoning, Trumbull and Portage Counties, Ohio; and

     o    the Mississippian (carbonates) and Devonian Shale reservoirs in
          Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee.

All of the primary areas described above have the following similarities:

     o    geological features such as structure and faulting generally are not
          factors used to find commercial production from a well drilled to this
          formation or these reservoirs and the governing factors appear to be
          sand or oolite (carbonate sand) quality in terms of net pay zone
          thickness, porosity, and the effectiveness of fracture stimulation in
          the well;

     o    a well drilled to this formation or these reservoirs usually requires
          hydraulic fracturing of the formation to stimulate productive
          capacity;

     o    generally, natural gas from a well drilled to this formation or these
          reservoirs is produced at rates which decline rapidly during the first
          few years of operations and, although the well can produce for many
          years, a proportionately larger amount of the well's production can be
          expected within the first several years; and

     o    it has been the managing general partner's experience that natural gas
          production from wells drilled to this formation or these reservoirs is
          reasonably consistent with nearby wells, although from time to time
          there can be great differences in the natural gas volumes and
          performance of wells on contiguous prospects. Thus, as drilling
          progresses, reserves from newly completed wells are reclassified from
          the proved undeveloped to the proved developed category and additional
          adjacent locations are added to proved undeveloped reserves.

The managing general partner anticipates that the majority of the subscription
proceeds of each partnership will be expended in the primary areas, although
some of the subscription proceeds of each partnership may be expended in the
secondary areas or in areas that are not currently known. Among the primary
areas, the managing general partner anticipates that each partnership will drill
more prospects in the Fayette County, Pennsylvania area than in the other areas.

MISSISSIPPIAN/UPPER DEVONIAN SANDSTONE RESERVOIRS, FAYETTE COUNTY, PENNSYLVANIA.
The Mississippian/Upper Devonian Sandstone reservoirs are discontinuous
lens-shaped accumulations found throughout most of the Appalachian Basin. These
reservoirs have porosities ranging from 5% to 20% with attendant permeabilities.
Porosity is the percentage of void space between sand grains that is available
for occupancy by either liquids or gases; and permeability is the property of
porous rock that allows fluids or gas to flow through it. See the geologic
evaluation prepared by United Energy Development Consultants, Inc., an
independent geological and engineering firm in "Appendix A - Information
Regarding Currently Proposed Prospectus for Atlas America Public #16-2007(A)
L.P.", for a discussion of the development of the Mississippian/Upper Devonian
Sandstone reservoirs in Fayette, Greene and Westmoreland Counties, Pennsylvania.


                                       67

<PAGE>

The wells in the Mississippian/Upper Devonian Sandstone reservoirs will be:

     o    situated on approximately 20 acres, subject to adjustment to take into
          account lease boundaries;

     o    drilled at least 1,000 feet from a producing well, although a
          partnership may drill a new well or re-enter an existing well that is
          closer than 1,000 feet to a plugged and abandoned well;

     o    drilled to approximately 1,900 to 6,000 feet in depth;

     o    classified as natural gas wells that may produce a small amount of
          oil; and

     o    primarily connected to the gathering system owned by Atlas Pipeline
          Partners and have their natural gas production primarily marketed to
          UGI Energy Services, Colonial Energy, ConocoPhillips Company and
          Equitable Gas Company as discussed below in "- Sale of Natural Gas and
          Oil Production."

CLINTON/MEDINA GEOLOGICAL FORMATION IN WESTERN PENNSYLVANIA. The Clinton/Medina
geological formation is a blanket sandstone found throughout most of the
northwestern edge of the Appalachian Basin. The Clinton/Medina geological
formation in Pennsylvania and Ohio is the same geological formation, although in
Pennsylvania it is often referred to as the Medina/Whirlpool geological
formation. For purposes of this prospectus, the term Clinton/Medina geological
formation is used for both Ohio and Pennsylvania. The Clinton/Medina geological
formation is described in petroleum industry terms as a "tight" sandstone with
porosity ranging from 6% to 12% and with very low natural permeability. Based on
the managing general partner's experience, it anticipates that all of the
natural gas wells drilled to the Clinton/Medina geological formation will be
completed and fraced in two different zones of the Clinton/Medina geological
feature. See the geologic evaluation and the model decline curve prepared by
United Energy Development Consultants, Inc. in "Appendix A - Information
Regarding Currently Proposed Prospects for Atlas America Public #16-2007(A)
L.P." for a discussion of the development of the Clinton/Medina Geological
Formation in western Pennsylvania and eastern Ohio.

The wells in the Clinton/Medina geological formation in western Pennsylvania and
eastern Ohio will be:

     o    primarily situated in Crawford, Mercer, Lawrence, Warren, and Venango
          Counties, Pennsylvania, and Stark, Mahoning, Trumbull and Portage
          Counties, Ohio;

     o    situated on approximately 50 acres, subject to adjustment to take into
          account lease boundaries;

     o    drilled at least 1,650 feet from each other in Pennsylvania, which is
          greater than the 660 feet minimum distance allowed by state law or
          local practice to protect against drainage from adjacent wells, and
          drilled at least 1,000 feet from each other in Ohio;

     o    drilled to approximately 5,000 to 6,300 feet in depth;

     o    classified as natural gas wells that may produce a small amount of
          oil, although the wells in eastern Ohio may be classified as oil
          wells; and

     o    primarily connected to the gathering system owned by Atlas Pipeline
          Partners and have their natural gas production primarily marketed to
          Hess Corporation as discussed below in "- Sale of Natural Gas and Oil
          Production."

Also, see "- Secondary Areas of Operations" below, for a discussion of the
Clinton/Medina geological formation in western New York and southern Ohio.

MISSISSIPPIAN CARBONATE AND DEVONIAN SHALE RESERVOIRS IN ANDERSON, CAMPBELL,
MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE. The Mississippian carbonate
reservoirs are discontinuous lens shaped accumulations found in the southern
Appalachian states of West Virginia, Virginia, Kentucky and Tennessee. These
reservoirs have porosities ranging from 6%


                                       68

<PAGE>

to 20% with attendant permeabilities. The Devonian shale is found throughout the
Appalachian Basin. When the shale is highly fractured it becomes a reservoir.
See the geologic evaluation prepared by United Energy Development Consultants,
Inc. in "Appendix A - Information Regarding Currently Proposed Prospects for
Atlas America Public #16-2007(A) L.P." for a discussion of the development of
the Mississippian carbonate and Devonian Shale reservoirs in Anderson, Campbell,
Morgan, Roane and Scott Counties, Tennessee.

The wells in the Mississippian carbonate and Devonian Shale reservoirs will be:

     o    situated on 40 acres;

     o    drilled 1,320 feet from each other unless topography dictates
          otherwise, however, in all cases no less than 700 feet;

     o    drilled to approximately 1,500 to 5,500 feet in depth;

     o    classified as natural gas wells that may produce a small amount of
          oil; and

     o    primarily connected to the gathering system owned by Knox Energy LLC,
          which is referred to as the Coalfield Pipeline, and have their natural
          gas production primarily marketed to Duke Energy as discussed below in
          "- Sale of Natural Gas and Oil Production."

The prospects in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee
were acquired from Knox Energy LLC as described below in "- Interests of
Parties" and Knox Energy may participate in drilling wells in this area with the
partnerships.

SECONDARY AREAS OF OPERATIONS

The managing general partner also has reserved the right to use a portion of the
subscription proceeds of each partnership to drill development wells in other
areas of the Appalachian Basin or elsewhere in the United States. The secondary
areas anticipated by the managing general partner, which are situated in the
Appalachian Basin, are discussed below.

UPPER DEVONIAN SANDSTONE RESERVOIRS, ARMSTRONG COUNTY, PENNSYLVANIA. The Upper
Devonian Sandstone reservoirs are discontinuous lens-shaped accumulations found
throughout most of the Appalachian Basin. These reservoirs have porosities
ranging from greater than 5% to 20% with attendant permeabilities. The prospects
in Armstrong and Indiana Counties, Pennsylvania will be acquired from U.S.
Energy Exploration Corporation as described below and U.S. Energy will
participate in drilling the wells in this area with the partnerships.

The wells in the Upper Devonian Sandstone reservoirs will be:

     o    situated on approximately 15 acres, subject to adjustment to take into
          account lease boundaries;

     o    drilled at least 1,000 feet from each other, although under
          Pennsylvania law in certain circumstances a variance can be obtained,
          and some of the wells the managing general partner has drilled to date
          in this general area have been drilled less than 1,000 feet apart, but
          even in those cases the wells were approximately 980 feet or more from
          each other;

     o    drilled to approximately 1,800 to 4,400 feet in depth;

     o    classified as natural gas wells which may produce a small amount of
          oil; and

     o    connected to a gathering system owned by U.S. Energy and have their
          natural gas production marketed by U.S. Energy as discussed below in
          "- Sale of Natural Gas and Oil Production."


                                       69

<PAGE>

The managing general partner anticipates the leases in Armstrong and Indiana
Counties, Pennsylvania will have a net revenue interest to a partnership of
84.375%. U.S. Energy, the originator of the leases, however, will retain a 25%
working interest in the wells and participate with the partnership in the costs
of drilling, completing, and operating the wells to the extent of its retained
working interest.

UPPER DEVONIAN SANDSTONE RESERVOIRS IN MCKEAN COUNTY, PENNSYLVANIA. See "- Upper
Devonian Sandstone Reservoirs, Armstrong County, Pennsylvania," above, for a
description of these reservoirs. Wells located in McKean County and drilled to
the Upper Devonian Sandstone reservoirs will be:

     o    situated on approximately 5 acres, subject to adjustments to take into
          account lease boundaries;

     o    drilled to approximately 2,000 to 2,500 feet in depth;

     o    classified as combination wells producing both natural gas and oil;

     o    drilled on leases with a net revenue interest of approximately 84.375%
          to 87.5%; and

     o    connected to the gathering systems owned by Atlas Pipeline Partners
          and M&M Royalty, LTD. and have their natural gas production primarily
          marketed to M&M Royalty, LTD. as discussed below in "- Sale of Natural
          Gas and Oil Production."

CLINTON/MEDINA GEOLOGICAL FORMATION IN WESTERN NEW YORK. Wells located in
western New York and drilled to the Clinton/Medina geological formation will be:

     o    primarily situated in Chautauqua County;

     o    situated on approximately 40 acres, subject to adjustment to take into
          account lease boundaries;

     o    drilled to approximately 3,800 to 4,000 feet in depth;

     o    drilled on leases with a net revenue interest of approximately 84.375%
          to 87.5%;

     o    classified as natural gas wells which may produce a small amount of
          oil; and

     o    connected to the gathering system owned by Atlas Pipeline Partners and
          have their natural gas production primarily marketed to Hess
          Corporation, commercial end users in the area, and/or Great Lakes
          Energy Partners, L.L.C. as discussed below in "- Sale of Natural Gas
          and Oil Production."

CLINTON/MEDINA GEOLOGICAL FORMATION IN SOUTHERN OHIO. Wells located in southern
Ohio and drilled to the Clinton/Medina geological formation will be:

     o    primarily situated in Noble, Washington, Guernsey, and Muskingum
          Counties;

     o    situated on approximately 40 acres, subject to adjustment to take into
          account lease boundaries;

     o    drilled at least 1,000 feet from each other;

     o    drilled to approximately 4,900 to 6,500 feet in depth;

     o    drilled on leases with a net revenue interest of approximately 82.5%
          to 87.5%;

     o    classified as either natural gas wells or oil wells; and


                                       70

<PAGE>

     o    primarily connected to the gathering system owned by Atlas Pipeline
          Partners (if classified as natural gas wells) and have their natural
          gas production marketed to Hess Corporation, although a portion of the
          natural gas production may be gathered and marketed by Triad Energy
          Corporation of West Virginia, Inc. as discussed below in "- Sale of
          Natural Gas and Oil Production."

Additionally, the managing general partner anticipates that the leases in
southern Ohio will have been originally acquired from a coal company and are
subject to a provision that the well must be abandoned if it hinders the
development of the coal. Thus, the managing general partner will not drill a
well on any lease subject to this provision unless it covers lands that were
previously mined. Although this does not totally eliminate the risk because the
leases may cover other coal deposits that might be mined during the life of a
well, the managing general partner believes that drilling wells on these
previously mined leases would be in the best interests of the partnerships.

ACQUISITION OF LEASES

The managing general partner will have the right, in its sole discretion, to
select the prospects which each partnership will drill. The managing general
partner intends that Atlas America Public #16-2007(A) L.P. will drill the
prospects described in "Appendix A - Information Regarding Currently Proposed
Prospects for Atlas America Public #16-2007(A) L.P." The managing general
partner also anticipates that it will designate a portion of the prospects in
Atlas America Public #16-2007(B) L.P., if units in that partnership are offered,
by means of a supplement or an amendment to the registration statement of which
this supplement is a part.

The leases covering each prospect on which one well will be drilled will be
acquired by a partnership from the managing general partner or its affiliates
and credited to the managing general partner as a part of its required capital
contribution to the partnership. Neither the managing general partner nor its
affiliates will receive any royalty or overriding royalty interest on any well.

The managing general partner anticipates that it will select the prospects for
each partnership, including any additional and/or substituted prospects, from
the following:

     o    leases in its and its affiliates' existing leasehold inventory;

     o    leases that are subsequently acquired by it or its affiliates; or

     o    leases owned by independent third-parties that may participate with
          the partnership in drilling wells.

The majority of the prospects acquired by a partnership will be in areas where
the managing general partner or its affiliates have previously conducted
drilling operations. The managing general partner believes that its and its
affiliates' leasehold inventory and leases acquired from third-parties will be
sufficient to provide all the development prospects to be drilled by the
partnerships if the targeted maximum subscription proceeds of $200 million are
received. In this regard, the managing general partner and its affiliates are
continually engaged in acquiring additional leasehold acreage in Pennsylvania,
Ohio, and other areas of the United States. As of August 15, 2006, the managing
general partner's and its affiliates' undeveloped leasehold acreage was as
follows:


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<PAGE>

                                 UNDEVELOPED LEASE ACREAGE
                                 -------------------------
                                      GROSS     NET (1)
                                     -------   --------
Kentucky .....................         9,060     4,530
Montana ......................         2,650     2,650
New York .....................        38,534    38,534
Ohio .........................        37,851    34,414
Pennsylvania .................       189,910   189,910
West Virginia ................        10,806     5,403
Wyoming ......................            80        80
                                     -------   -------
   Total .....................       288,891   275,521
                                     =======   =======

(1)  The net acreage as to which leases expire in fiscal 2007 are as follows:
     Ohio: 2007 - 1,538 acres and Pennsylvania: 2007 - 12,938 acres.

Most, if not all, of the prospects to be selected for the partnerships are
expected by the managing general partner to be single well proved undeveloped
prospects that are classified as developmental. Thus, only one well will be
drilled on each of those prospects and the number of prospects that the managing
general partner will assign to each partnership will be the same as the number
of wells that the partnership has the funds to drill. This also means that the
partnership, in all likelihood, will not farmout any acreage associated with
those prospects. However, the need for a farmout might arise, for example, if
during drilling or subsequently the managing general partner determines there
might be a productive horizon situated above (i.e. uphole) the target horizon,
but the partnership does not have the funds to complete the well in the horizon
or the completion of the horizon would be inconsistent with the partnership's
objectives. In this event, the managing general partner might decide to farmout
the activity for the partnership. Generally, a farmout is an agreement in which
the owner of the lease or existing well agrees to assign its interest in certain
acreage under the lease or the existing well to an assignee subject to the
assignee drilling one or more wells or completing or recompleting the existing
well in one or more horizons. The owner would retain some interest in the
assigned acreage or well. See "Conflicts of Interest - Conflicts Involving the
Acquisition of Leases" for the procedure for a farmout, and "Federal Income Tax
Consequences - Farmouts."

DEEP DRILLING RIGHTS RETAINED BY MANAGING GENERAL PARTNER. The lease assignments
to each partnership generally will be limited to a depth from the surface to the
deepest depth penetrated at the cessation of drilling operations. The managing
general partner will retain the deeper drilling rights, including ownership of
any coal bed methane production that might be obtained from the deeper
formations. Conversely, as between a partnership and the managing general
partner, the partnership will own any coal bed methane production that might be
obtained from the shallower formations that are not included in the deeper
drilling rights retained by the managing general partner.

The amount of the credit the managing general partner receives for the leases it
contributes to a partnership will not include any value allocable to the deeper
drilling rights retained by it. If the managing general partner undertakes any
activities with respect to the deeper formations in the future, then the
partnerships would not share in the profits from these activities, nor would the
partnerships pay any of the associated costs.

INTERESTS OF PARTIES

Generally, production and revenues from a well drilled by a partnership will be
net of the applicable landowner's royalty interest, which is typically 1/8th
(12.5%) of gross production, and any interest in favor of third-parties such as
an overriding royalty interest. Landowner's royalty interest generally means an
interest that is created in favor of the landowner when an oil and gas lease is
obtained; and overriding royalty interest generally means an interest that is
created in favor of someone other than the landowner. In either case, the owner
of the interest receives a specific percentage of the natural gas and oil
production free and clear of all costs of development, operation, or maintenance
of the well. This is compared with a working interest, which generally means an
interest in the lease under which the owner of the interest must pay


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<PAGE>

some portion of the cost of development, operation, or maintenance of the well.
Also, the leases will be subject to terms that are customary in the industry
such as free gas to the landowner-lessor for home heating requirements, etc.

The managing general partner anticipates that each partnership generally will
have a net revenue interest in its leases in its primary drilling areas as set
forth in the chart below. Net revenue interest generally means the percentage of
revenues the owner of an interest in a well is entitled to receive under the
lease. The following chart expresses the percentage of production revenues that
the managing general partner, the landowner, other third-parties, and you and
the other investors in a partnership will share in from the wells in two of the
three primary drilling areas. The third primary drilling area in Anderson,
Campbell, Morgan, Roane and Scott Counties, Tennessee is discussed following the
chart. The chart assumes that the partnership owns 100% of the working interest
in the well. If a partnership acquires a lesser percentage working interest in a
well, which may be the case in Anderson, Campbell, Morgan, Roane and Scott
Counties, Tennessee, then the partnership's net revenue interest in that well
will decrease proportionately.

The actual number, identity and percentage of working interests or other
interests in prospects to be acquired by the partnerships will depend on, among
other things:

     o    the amount of subscription proceeds received by a partnership;

     o    the latest geological and production data;

     o    potential title or spacing problems;

     o    availability and price of drilling services, tubular goods and
          services;

     o    approvals by federal and state departments or agencies;

     o    agreements with other working interest owners in the prospects;

     o    farmins and farmouts; and

     o    continuing review of other prospects that may be available.

PRIMARY AREAS.

CLINTON/MEDINA GEOLOGICAL FORMATION IN WESTERN PENNSYLVANIA AND
MISSISSIPPIAN/UPPER DEVONIAN SANDSTONE RESERVOIRS IN FAYETTE COUNTY,
PENNSYLVANIA.

<TABLE>
<CAPTION>
                                          PARTNERSHIP                      THIRD PARTY                87.5% PARTNERSHIP
ENTITY                                     INTEREST                     ROYALTY INTEREST           NET REVENUE INTEREST (2)
------                           ----------------------------   --------------------------------   ------------------------
<S>                              <C>                            <C>                                         <C>
Managing General Partner......   32% partnership interest (1)                                                28.0%
Investors.....................   68% partnership interest (1)                                                59.5%
Third Party...................                                  12.5% Landowner Royalty Interest             12.5%
                                                                                                            -----
                                                                                                            100.0%
                                                                                                            =====
</Table>

----------
(1)  These percentages are for illustration purposes only, and assume that the
     partnership has a 100% working interest and the managing general partner
     contributes its minimum required capital contribution of 25% to each
     partnership and the capital contributions from you and the other investors
     are 75%. The actual percentages are likely to be different because they
     will be based on the actual capital contributions of the managing general
     partner and you and the other investors. However, the managing general
     partner's total revenue share may not exceed 40% of partnership revenues
     regardless of the amount of its capital contributions.

(2)  The managing general partner anticipates that the majority of the wells in
     the Clinton/Medina Geological Formation in western Pennsylvania will have a
     net revenue interest of 84.375% which, using the assumptions set forth in
     footnote


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<PAGE>

     (1),  would  provide you and the other  investors in the  partnership  as a
     group 57.375% of that partnership's revenues from those wells.

MISSISSIPPIAN CARBONATE AND DEVONIAN SHALE RESERVOIRS IN ANDERSON, CAMPBELL,
MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE. Generally, the leases in north
central Tennessee will have a net revenue interest to a partnership ranging from
84.375% to 81.375%, assuming that a partnership has a 100% working interest.
However, the amount of the partnership's net revenue interest in some of the
prospects could be as low as 81.375% depending primarily on whether the
landowner royalty interest is 12.5% or 15.5%. The amount of the landowner
royalty depends, in turn, on whether the natural gas produced from those
prospects, if any, is sold at a price above or below $3.00 per mcf, and on
whether Knox Energy LLC and its affiliates, the originators of the leases,
participate as a working interest owner with a partnership in the leases
covering those prospects. Knox Energy and its affiliates may retain up to a 50%
working interest in the wells and participate with the partnership in the costs
of drilling, completing, and operating the wells to the extent of its retained
working interest. Also, if Knox Energy does not retain a working interest in a
well, then its overriding royalty interest will be 3.125%. However, if Knox
Energy retains a 50% working interest in a well, then its overriding royalty
interest of 3.125% will be reduced to 1.5625%. To the extent that Knox Energy
participates in a well as a working interest owner for less than a 50% working
interest, its overriding royalty interest will be prorated between 3.125% and
1.5625% depending on the percentage of its working interest. The investors' net
revenue interest in the above example would range from 57.375% to 55.335%, if
presented on a 100% working interest basis and the investors were receiving 68%
of the partnership revenues.

Pursuant to the acquisition terms of the agreement between the managing general
partner and its affiliates and Knox Energy and its affiliates, no well drilled
by the managing general partner and its affiliates in this area, which includes
the partnerships, may produce coalbed methane gas, and the managing general
partner or its affiliates must drill 300 commitment wells during the initial
three year term of the agreement with Knox Energy, which ends June 30, 2007, or
they will be in breach of the agreement.

SECONDARY AREAS

Although the managing general partner anticipates that each partnership will
have a net revenue interest ranging from 81% to 87.5% in its leases in the
secondary areas described above, assuming it owns 100% of the working interest,
there is no minimum net revenue interest that a partnership is required to own
before drilling a well in other areas of the United States. The leases in these
other areas may be subject to interests in favor of third-parties that are not
currently known such as overriding royalty interests, net profits interests,
carried interests, production payments, reversionary interests pursuant to
farmouts or non-consent elections under joint operating agreements, or other
retained or carried interests.

TITLE TO PROPERTIES

Title to all leases acquired by a partnership ultimately will be held in the
name of the partnership. However, to facilitate a partnership's acquisition of
the leases title to the leases may initially be held in the name of the managing
general partner, the operator, their affiliates, or any nominee designated by
the managing general partner. Title to each partnership's leases will be
transferred to the partnership and filed for record from time to time after the
wells are drilled and completed.

The managing general partner will take the steps it deems necessary to assure
that each partnership has acceptable title for its purposes. However, it is not
the practice in the natural gas and oil industry to warrant title or obtain
title insurance on leases and the managing general partner will provide neither
for the leases it assigns to a partnership. The managing general partner will
obtain a favorable formal title opinion for the leases before each well is
drilled, but will not obtain a division order title opinion after the well is
completed. The managing general partner may use its own judgment in waiving
title requirements and will not be liable for any failure of title of the leases
transferred to a partnership. Also, the partnerships may experience losses from
title defects excluded from, or not disclosed by, the formal title opinion that
is provided to the managing general partner before a well is drilled or that
would have been disclosed by a division order title opinion after the well is
drilled, if the partnership obtained division order title opinions, which it
will not do. Although past performance is no guarantee of future results, the
previous drilling partnerships sponsored by the managing general partner and its
affiliates have participated in drilling more than 3,220 wells in the
Appalachian Basin since 1985, and none of the wells have been lost because of
title failure. (See "Prior Activities.")


                                       74

<PAGE>

DRILLING AND COMPLETION ACTIVITIES; OPERATION OF PRODUCING WELLS

On receipt of the minimum subscription proceeds of a partnership, the managing
general partner on behalf of the partnership may break escrow, transfer the
escrowed funds to a partnership account, enter into the drilling and operating
agreement, which is attached to the partnership agreement as Exhibit II, with
itself or an affiliate of the managing general partner as operator, and begin
drilling the partnership's wells.

Under the drilling and operating agreement, the responsibility for drilling and
either completing or plugging partnership wells will be on the managing general
partner or an affiliate of the managing general partner as the operator and the
general drilling contractor. Under the drilling and operating agreement, each
partnership is required to prepay the investors' share of the drilling and
completion costs of its wells to the managing general partner as the general
drilling contractor and operator. If one or more of a partnership's wells will
be drilled in the calendar year after the year in which the advance payment is
made, the required advance payment allows the partnership to secure tax benefits
of prepaid intangible drilling costs based on a substantial business purpose for
the advance payment under the drilling and operating agreement. The managing
general partner as operator and general drilling contractor will begin drilling
all of the wells no later than March 30, 2008 for the partnerships. (See
"Federal Income Tax Consequences - Drilling Contracts.")

During drilling operations the managing general partner's duties as operator and
general drilling contractor will include:

     o    making  the  necessary   arrangements   for  drilling  and  completing
          partnership   wells   and   related   facilities   for  which  it  has
          responsibility under the drilling and operating agreement;

     o    managing  and  conducting  all field  operations  in  connection  with
          drilling, testing, and equipping the wells; and

     o    making the technical decisions required in drilling and completing the
          wells.

All partnership wells will be drilled to a sufficient depth to test thoroughly
the objective geological formation unless the managing general partner
determines in its sole discretion that the well shall be completed in a
formation uphole from the objective geological formation.

Under the drilling and operating agreement the managing general partner, as
operator and general drilling contractor, will complete each well if there is a
reasonable probability of obtaining commercial quantities of natural gas or oil.
However, based on its past experience, the managing general partner anticipates
that most of the development wells drilled by the partnerships in the primary
and secondary areas will have to be completed before the managing general
partner can determine the well's productivity. If the managing general partner,
as operator and general drilling contractor, determines that a well should not
be completed, then the well will be plugged and abandoned.

During producing operations the managing general partner's duties, as operator,
will include:

     o    managing  and  conducting  all field  operations  in  connection  with
          operating and producing the wells;

     o    making the technical decisions required in operating the wells; and

     o    maintaining the wells, equipment, and facilities in good working order
          during their useful life.

The managing general partner, as operator, will be reimbursed for its direct
expenses and will receive well supervision fees at competitive rates for
operating and maintaining the wells during producing operations as discussed in
"Compensation." As discussed in "Summary of Drilling and Operating Agreement,"
the drilling and operating agreement contains a number of other material
provisions which you are urged to review.

Certain wells may be drilled by a partnership with third-parties owning a
portion of the working interest in the wells. Any other working interest owner
in a well will have a separate agreement with the managing general partner for
drilling and


                                       75

<PAGE>

operating the well with differing terms and conditions from those contained in a
partnership's  drilling  and  operating  agreement.  (See  "Federal  Income  Tax
Consequences -- Drilling Contracts.")

SALE OF NATURAL GAS AND OIL PRODUCTION

POLICY OF TREATING ALL WELLS EQUALLY IN A GEOGRAPHIC AREA. All benefits and
liabilities from marketing and hedging arrangements or other relationships
affecting the property of the managing general partner or its affiliates and the
partnerships shall be fairly and equitably apportioned according to the
respective interests of each in the property. The managing general partner is
responsible for selling each partnership's natural gas and oil production, and
its policy is to treat all wells in a given geographic area equally. This
reduces certain potential conflicts of interest among the owners of the various
wells, including the partnerships sponsored by the managing general partner,
concerning to whom and at what price the natural gas and oil will be sold. For
example, the managing general partner calculates a weighted average selling
price for all of the natural gas sold in the geographic area and this is the
price which will be paid to each partnership in the geographic area for its
natural gas. For natural gas sold in western Pennsylvania during its previous
four fiscal years, the managing general partner received an average selling
price after deducting all expenses, including transportation expenses and after
the effects of hedging arrangements, of approximately:

     o    $3.34 per mcf, "mcf" means 1,000 cubic feet of natural gas, in 2002;

     o    $4.78 per mcf in 2003;

     o    $5.64 per mcf in 2004; and

     o    $6.72 per mcf in 2005.

If all of the natural gas produced in an area cannot be sold by the managing
general partner and its affiliates, including the partnerships, because of
limited gathering line or pipeline capacity, or limited demand for the natural
gas, which increases pipeline pressure, then the production that is sold will be
from those wells that have the greatest well pressure and are able to feed into
the pipeline, regardless of which partnerships own the wells. The proceeds from
these natural gas sales will be credited only to the partnerships whose wells
produced the natural gas sold.

GATHERING OF NATURAL GAS. Under the partnership agreement the managing general
partner will be responsible for gathering and transporting the natural gas
produced by the partnerships to interstate pipeline systems, local distribution
companies, and/or end-users in the area. For the majority of each partnership's
natural gas production, including natural gas in the primary areas, as discussed
below, the managing general partner anticipates that it will use the gathering
system owned by Atlas Pipeline Partners, L.P. (and Atlas Pipeline Operating
Partnership), which is a master limited partnership formed by a subsidiary of
Atlas America as managing general partner using Atlas America personnel who act
as its officers and employees. (See "Management - Organizational Diagrams and
Security Ownership of Beneficial Owners.") Atlas Pipeline Partners acquired the
natural gas gathering system and related facilities of Atlas America, Resource
Energy, and Viking Resources in February 2000. The gathering system consists of
more than 1,400 miles of intrastate pipelines located in western Pennsylvania,
eastern Ohio, and western New York.

If a partnership's natural gas is not transported through the Atlas Pipeline
Partners gathering system, it is because there is a third-party operator or the
gathering system has not been extended to the wells. In these cases, which
includes the McKean County area and the north central Tennessee area, as
described in "Compensation - Gathering Fees," the natural gas will be
transported through a third-party gathering system, and the partnership will pay
the managing general partner a competitive gathering fee, all or a portion of
which will be paid by it to the third-party. Also, in the north central
Tennessee area, the managing general partner and its affiliates may construct a
gathering system in the future for which they will receive gathering fees as
described in "Compensation - Gathering Fees."

As a part of the sale of the gathering system to Atlas Pipeline Partners in
February 2000, Atlas America and its affiliates, Resource Energy and Viking
Resources (the "Atlas entities"), made certain commitments that were intended to
maximize the use and expansion of the gathering system. Those commitments were
made pursuant to a master natural gas gathering


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<PAGE>

agreement and an omnibus agreement which were entered into at the time of sale
in February 2000. Both the master natural gas gathering agreement and the
omnibus agreement set forth continuing obligations of the Atlas entities that
have no specified term, except that they will terminate with respect to future
wells drilled by the Atlas entities if the general partner of Atlas Pipeline
Partners, L.P., Atlas Pipeline Partners GP, LLC (which is owned by Atlas
Pipeline Holdings, L.P., a limited partnership that recently completed a public
offering as described in "Management - Organizational Diagrams and Security
Ownership of Beneficial Owners") is removed without cause and without its
consent. However, under the master natural gas gathering agreement the Atlas
entities, including the partnerships in this case, have committed the natural
gas production from the wells they drill before removal of Atlas Pipeline
Partners GP, LLC without cause and without its consent, for the life of the
wells. Thus, the termination of the master natural gas gathering agreement under
the circumstance described above will only terminate the obligation of the Atlas
entities, including the partnerships, to transport their natural gas through
Atlas Pipeline Partners' gathering system with respect to wells drilled on or
after the termination of the agreement. Some of these commitments still affect
the partnerships. For example, under the master natural gas gathering agreement
the Atlas entities are required to pay a gathering fee to Atlas Pipeline
Partners equal to the greater of $0.35 per mcf or 16% of the gross sales price
for each mcf transported through Atlas Pipeline Partners' gathering system. If a
partnership pays a lesser amount, which is anticipated by the managing general
partner as described in "Compensation - Gathering Fees," then the Atlas entities
must pay the difference to Atlas Pipeline Partners. Also, if Atlas Pipeline
Partners determines that the continued operation of any part of the gathering
system is not economically justified, then it may elect to discontinue the
operation of that portion of the gathering system. If Atlas Pipeline Partners
makes this determination, then it must give the parties to the agreement the
right to purchase that part of the gathering system for $10.

Under the omnibus agreement, Atlas America is required to commit to Atlas
Pipeline Partners' gathering system all wells it drills and operates, including
those of the partnerships, that are within 2,500 feet of the Atlas Pipeline
Partners gathering system. In addition, the Atlas entities, including the
partnerships, must construct at their own cost, up to 2,500 feet of flowline as
necessary to connect their wells to Atlas Pipeline Partners' gathering system.
Also, Atlas Pipeline Partners must, at its own cost, extend its gathering system
to connect to any flowlines constructed by the Atlas entities, including the
partnerships, that are within 1,000 feet of its gathering system. With respect
to wells to be drilled by Atlas America and its affiliates, including the
partnerships, that will be more than 3,500 feet from Atlas Pipeline Partners'
gathering system, Atlas Pipeline Partners has various options, in its
discretion, to connect those wells to its gathering system at its own cost.
Also, Atlas America and its affiliates may not divest their ownership of Atlas
Pipeline Partners GP, LLC without also divesting their ownership of the entities
serving as managing general partner in all of their affiliated investment
partnerships, including the partnerships, to the same acquirer, except that
Atlas America is permitted to transfer its ownership interest in Atlas Pipeline
Partners GP, LLC to a wholly- or majority-owned direct or indirect subsidiary as
long as Atlas America continues to control that subsidiary. See "Management -
Organizational Diagram and Security Ownership of Beneficial Owners," regarding
the public offering in Atlas Pipeline Holdings, L.P., which owns Atlas Pipeline
Partners GP, LLC. Further, Atlas Pipeline Partners GP, LLC has pledged its
equity interests in Atlas Pipeline Partners as security for the revolving credit
facility of Atlas America discussed in "Management's Discussion and Analysis of
Financial Condition, Results of Operations, Liquidity and Capital Resources."

NATURAL GAS CONTRACTS. As set forth in "- Primary Areas of Operations," each
partnership has three primary areas where it will drill its wells, and the
managing general partner anticipates that there will be a different natural gas
purchaser or purchasers in each area. The managing general partner anticipates
that more prospects will be drilled in the Fayette County area, which is one of
the primary drilling areas, than in the other areas, and the natural gas
produced from the Fayette County area will be sold to UGI Energy Services,
ConocoPhillips Company, Equitable Gas Company and Colonial Energy pursuant to
contracts which end March 31, 2008, except with respect to Colonial Energy,
which ends March 31, 2009. The natural gas produced from north central
Tennessee, which is one of the three primary areas, will be sold to Duke Energy
pursuant to a contract which ends October 31, 2008. The managing general partner
anticipates that the remainder of the natural gas produced by the partnership
from wells drilled in the other primary area (Clinton/Medina in Western
Pennsylvania) and the secondary areas, other than Armstrong and McKean Counties,
Pennsylvania will be sold to Hess Corporation ("Hess") as discussed below.


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<PAGE>

The managing general partner and its affiliates previously entered into a
10-year agreement with First Energy Solutions Corporation, which is the
marketing affiliate of First Energy Corporation, a large regional electric
utility. This agreement was sold by First Energy Solutions Corporation to Hess
effective April 1, 2005. Subject to the exceptions set forth below, Hess has the
right to buy all of the natural gas produced and delivered by the managing
general partner and its affiliates, which includes each partnership and the
managing general partner's other partnerships, at certain delivery points with
the facilities of East Ohio Gas Company, National Fuel Gas Distribution,
Columbia of Ohio, and Peoples Natural Gas Company, which are local distribution
companies; and National Fuel Gas Supply, Columbia Gas Transmission Corporation
and Tennessee Gas Pipeline Company, which are interstate pipelines. This
contract, which ends April 1, 2009, is important to the managing general partner
and its affiliates because as of July 31, 2006 the managing general partner and
its affiliates, including its prior affiliated partnerships, were selling
approximately 40.9% of their natural gas production under the agreement with
Hess. However, as set forth above, each partnership will sell a much smaller
percentage of its natural gas to Hess because of certain exceptions to the
agreement, including natural gas sold through interconnects established after
the agreement, which includes the majority of the natural gas produced from
wells in the Fayette County, Pennsylvania area, and natural gas produced from
well(s) subject to an agreement under which a third-party was to arrange for the
gathering and sale of the natural gas such as natural gas produced from wells in
north central Tennessee, one of the primary drilling areas, or in Armstrong and
McKean Counties, Pennsylvania, which are both secondary drilling areas.

The pricing and delivery arrangements with all of the natural gas purchasers
described above are tied to the settlement of the New York Mercantile Exchange
Commission ("NYMEX") monthly futures contracts price, which is reported daily in
the Wall Street Journal and with an additional premium, which is referred to as
the basis, paid because of the location of the natural gas (the Appalachian
Basin) in relation to the natural gas market. The premium over quoted prices on
the NYMEX received by the managing general partner and its affiliates has ranged
between $0.51 to $1.07 per Mcf during the managing general partner's past three
fiscal years. These figures are based on the overall weighted average that the
managing general partner and its affiliates used in their annual reserve reports
for their past three fiscal years. Generally, the purchase agreements may be
suspended for force majeure, which generally means an Act of God.

Pricing for natural gas and oil has been volatile and uncertain for many years.
To limit the managing general partner's and its partnerships' exposure to
decreases in natural gas prices, the managing general partner and its
affiliates, Atlas America and/or Atlas Energy Resources, LLC use forward sales
transactions through its natural gas purchasers as discussed below and hedges
through contracts such as regulated NYMEX futures and options contracts and
non-regulated over-the-counter futures contracts with qualified counterparties.
The forward sales transactions require firm delivery of natural gas and,
therefore, are considered normal sales of natural gas, rather than hedges, for
accounting purposes. The futures contracts employed by the managing general
partner are commitments to purchase or sell natural gas at future dates and
generally cover one-month periods for up to 36 months in the future. To assure
that the financial instruments will be used solely for hedging price risks and
not for speculative purposes, the managing general partner has established a
committee to assure that all financial trading is done in compliance with the
managing general partner's hedging policies and procedures. The managing general
partner does not intend to contract for positions that it cannot offset with
actual production.

All of the natural gas purchasers described above and many third-party marketers
use NYMEX based financial instruments to hedge their pricing exposure, and they
make price hedging opportunities available to the managing general partner. The
forward sales transactions are similar to NYMEX based futures contracts, swaps
and options, but also require firm physical delivery of the natural gas. Because
of this, the managing general partner limits these arrangements to much smaller
quantities of natural gas than those projected to be available at any delivery
point. The price paid by the natural gas purchasers for certain volumes of
natural gas sold under these hedge agreements may be significantly different
from the underlying monthly spot market value. As of April 2, 2006, a portion of
the managing general partner's natural gas was subject to forward sales
transactions through March 31, 2007. After March 31, 2007, none of the managing
general partner's and its affiliates' natural gas is subject to forward sales
transactions and the managing general partner and its affiliates anticipate
using financial hedges as discussed below for all of its natural gas that is
hedged, although this may change from time to time.


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On October 27, 2005, the managing general partner and its affiliates implemented
financial hedges through its banking counter-party, Wachovia Bank, and as of
October 2, 2006, the managing general partner and its affiliates have hedged
approximately 51% of their natural gas production using fixed-for-floating
financial swaps for the period April 1, 2007 through December 31, 2009. The
managing general partner and its affiliates are also negotiating with other
banking counter-parties to implement its financial hedges.

The percentages of natural gas that is hedged through either financial hedges or
forward sales transactions or not hedged at all will change from time to time in
the discretion of Atlas America or Atlas Energy Resources, LLC. It is difficult
to project what portion of these hedges will be allocated to each partnership by
the managing general partner because of uncertainty about the quantity, timing,
and delivery locations of natural gas that may be produced by a partnership.
Although hedging provides the partnerships some protection against falling
prices, these activities also could reduce the potential benefits of price
increases and the partnerships could incur liability on the financial hedges.
For example, if a partnership's production is substantially less than expected,
the counterparties to the futures contracts fail to perform under the contracts
or there is a sudden, unexpected event materially impacting natural gas prices.
Subject to the managing general partner's and its affiliates' interest in their
natural gas contracts or pipelines and gathering systems, all benefits and
liabilities from marketing and hedging or other relationships affecting the
property of the managing general partner or its affiliates or the partnerships
must be fairly and equitably apportioned according to the interests of each in
the property.

MARKETING OF NATURAL GAS PRODUCTION FROM WELLS IN OTHER AREAS OF THE UNITED
STATES. The managing general partner expects that natural gas produced by the
partnership from wells drilled in areas of the Appalachian Basin other than
those described above will be primarily tied to the spot market price and
supplied to:

     o    gas marketers;

     o    local distribution companies;

     o    industrial or other end-users; and/or

     o    companies generating electricity.

CRUDE OIL. Crude oil produced from a partnership's wells will flow directly into
storage tanks where it will be picked up by the oil company, a common carrier,
or pipeline companies acting for the oil company which is purchasing the crude
oil. Unlike natural gas, crude oil does not present any transportation problem.
The managing general partner anticipates selling any oil produced by the wells
to regional oil refining companies at the prevailing spot market price for
Appalachian crude oil in spot sales. The managing general partner received an
average selling price for oil during its previous four fiscal years of
approximately $18.92 per barrel in 2002; $29.06 per barrel in 2003; $34.41 per
barrel in 2004; and $50.00 per barrel in 2005. During the term of the
partnerships it is anticipated that the price of oil will be uncertain and
volatile.

INSURANCE

Since 1972 the managing general partner and its affiliates, including its
partnerships, have been involved in drilling more than 5,300 wells, most of
which were developmental wells, in Ohio, Pennsylvania, and other areas of the
Appalachian Basin. They have made only one material insurance claim and as
discussed below, one which may evolve into a material claim. In February 2004,
one of the wells in another investment partnership incurred an uncontrolled flow
of natural gas and oil with a fire during drilling. These problems with the well
were subsequently controlled, but they resulted in the loss of a subcontractor's
drilling rig and third-party claims. As of April 19, 2005, the managing general
partner's insurance carrier had paid approximately $1.6 million to third-parties
for property damage claims and additional claims have been submitted which have
not yet been paid. The managing general partner's insurance company is exploring
all avenues for subrogation. In addition, in February 2006, there was a well
fire during the drilling of a well in Fayette County, Pennsylvania which
resulted in a claim against the managing general partner's insurance carrier in
an amount which has not been quantified. See "Actions to be Taken by Managing
General Partner to Reduce Risks of Additional Payments by Investor General
Partners - Insurance" for a discussion of the insurance coverage the managing
general partner intends to be available for a partnership's benefit.


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USE OF CONSULTANTS AND SUBCONTRACTORS

The partnership agreement authorizes the managing general partner to use the
services of independent outside consultants and subcontractors on behalf of the
partnerships. The services will normally be paid on a per diem or other cash fee
basis and will be charged to the partnership on whose behalf the costs were
incurred as either a direct cost or as a direct expense under the drilling and
operating agreement. These charges will be in addition to the costs of
subcontractor services provided by the managing general partner's affiliates,
which will be charged at competitive rates, and the oversight and administration
fee that will be paid to the managing general partner during drilling
operations, and the well supervision fees paid to the managing general partner
as operator as discussed in "Compensation."

                       COMPETITION, MARKETS AND REGULATION

NATURAL GAS REGULATION

Governmental agencies regulate the production and transportation of natural gas.
Generally, the regulatory agency in the state where a producing natural gas well
is located supervises production activities and the transportation of natural
gas sold into intrastate markets, and the Federal Energy Regulatory Commission
("FERC") regulates the interstate transportation of natural gas.

Natural gas prices have not been regulated since 1993, and the price of natural
gas is subject to the supply and demand for natural gas along with factors such
as the natural gas' BTU content and where the wells are located. Since 1985 FERC
has sought to promote greater competition in natural gas markets in the United
States. Traditionally, natural gas was sold by producers to interstate pipeline
companies that served as wholesalers and resold the natural gas to local
distribution companies for resale to end-users. FERC changed this market
structure by requiring interstate pipeline companies to transport natural gas
for third-parties. In 1992 FERC issued Order 636 and a series of related orders
that required pipeline companies to, among other things, separate their sales
services from their transportation services and provide an open access
transportation service that is comparable in quality for all natural gas
producers or suppliers. The premise behind FERC Order 636 was that the
interstate pipeline companies had an unfair advantage over other natural gas
producers or suppliers because they could bundle their sales and transportation
services together. FERC Order 636 is designed to ensure that no natural gas
seller has a competitive advantage over another natural gas seller because it
also provides transportation services.

In 2000 FERC issued Order 637 and subsequent orders to further enhance
competition by removing price ceilings on short-term capacity release
transactions. It also enacted other regulatory policies that are intended to
enhance competition in the natural gas market and increase the flexibility of
interstate natural gas transportation. FERC also has required pipeline companies
to develop electronic bulletin boards to provide standardized access to
information concerning capacity and prices.

CRUDE OIL REGULATION

Oil prices are not regulated, and the price is subject to the supply and demand
for oil, along with qualitative factors such as the gravity of the crude oil and
sulfur content differentials.

COMPETITION AND MARKETS

Many companies engage in natural gas and oil drilling operations in the
Appalachian Basin, where most or all of the wells in each partnership will be
located. According to the Energy Information Administration, the independent
statistical and analytical agency within the Department of Energy, in 2004 there
were 23 quadrillion BTU of natural gas consumed in the United States which
represented approximately 23% of the total energy used. The Appalachian Basin
accounted for approximately 5.7% of the total domestic natural gas production in
the United States in 2004 and represented approximately 12.5% of the total
number of wells drilled in the United States during 2004. Also, according to the
Natural Gas Annual 2004 Report, which is published by the Energy Information
Administration Office of Oil and Gas, as of December 31, 2004, the Appalachian
Basin's economically recoverable natural gas reserves represented approximately
8% of total domestic natural gas reserves.


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The natural gas and oil industry is highly competitive in all phases, including
acquiring suitable leases to drill and marketing natural gas and oil production
from the wells. Product availability and price are the principal means of
competing in selling natural gas and oil. Many of the partnerships' competitors
will have financial resources and staffs larger than those available to the
partnerships. This may enable them to identify and acquire desirable leases and
market their natural gas and oil production more effectively than the managing
general partner and the partnerships. While it is impossible to accurately
determine the partnerships' industry position, the managing general partner does
not consider that the partnerships' intended operations will be a significant
factor in the industry.

The natural gas and oil industry has from time to time experienced periods of
rapid cost increases. The increase in natural gas and oil prices over the last
several years also has increased the demand for drilling rigs and other related
equipment and the costs of drilling and completing natural gas and oil wells.
Additionally, the managing general partner and its affiliates have experienced
an increase in the cost of tubular steel used in drilling wells. Because each
partnership's wells will be drilled on a modified cost plus basis as described
in "Compensation - Drilling Contracts," these increased costs will increase the
partnerships' costs to drill and complete their wells. Also, the reduced
availability of drilling rigs and other related equipment may make it more
difficult to drill each partnership's wells in a timely manner or to comply with
the prepaid intangible drilling costs rules discussed in "Federal Income Tax
Consequences - Drilling Contracts." Further, over the term of each partnership
there may be fluctuating or increasing costs in doing business which directly
affect the managing general partner's ability to operate the partnership's wells
at acceptable price levels.

The natural gas and oil produced by your partnership's wells must be marketed in
order for you to receive revenues. During its fiscal years ending in 2005, 2004,
and 2003, the managing general partner did not experience any problems in
selling natural gas and oil, although the prices varied significantly during
those periods. As set forth above, natural gas and oil prices are not regulated,
but instead are subject to factors which are generally beyond the partnerships'
and the managing general partner's control such as the supply and demand for
natural gas and oil. For example, reduced natural gas demand and/or excess
natural gas supplies will result in lower prices. Other factors affecting the
price and/or marketing of natural gas and oil production, which are also beyond
the control of the managing general partner and the partnerships and cannot be
accurately predicted, are the following:

     o    the cost, proximity, availability, and capacity of pipelines and other
          transportation facilities;

     o    the price and availability of other energy sources such as coal,
          nuclear energy, solar and wind;

     o    the price and availability of alternative fuels, including when large
          consumers of natural gas are able to convert to alternative fuel use
          systems;

     o    local, state, and federal regulations regarding production,
          conservation, and transportation;

     o    overall domestic and global economic conditions;

     o    the impact of the U.S. dollar exchange rates on natural gas and oil
          prices;

     o    technological advances affecting energy consumption;

     o    domestic and foreign governmental relations, regulations and taxation;

     o    the impact of energy conservation efforts;

     o    the general level of supply and market demand for natural gas and oil
          on a regional, national and worldwide basis;

     o    weather conditions and fluctuating seasonal supply and demand for
          natural gas and oil because of various factors such as home heating
          requirements in the winter months, although seasonal anomalies such as
          mild


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          winters or hot summers sometimes lessen this fluctuation, and certain
          natural gas users with natural gas storage facilities purchase a
          portion of the natural gas they anticipate they will need for the
          winter during the summer, which also can lessen seasonal demand
          fluctuations;

     o    economic and political instability, including war or terrorist acts in
          natural gas and oil producing countries, including those of the Middle
          East and South America;

     o    the amount of domestic production of natural gas and oil; and

     o    the amount and price of imports of natural gas and oil from foreign
          sources, including liquid natural gas from Canada and other countries
          (which the managing general partner believes becomes economic when
          natural gas prices are at or above $3.50 per mcf), and the actions of
          the members of the Organization of Petroleum Exporting Countries
          ("OPEC"), which include production quotas for petroleum products from
          time to time with the intent of increasing, maintaining, or decreasing
          price levels.

For example, the North American Free Trade Agreement ("NAFTA") eliminated trade
and investment barriers in the United States, Canada, and Mexico. From time to
time since then there have been increased imports of Canadian natural gas into
the United States. Without a corresponding increase in demand in the United
States, the imported natural gas would have an adverse effect on both the price
and volume of natural gas sales from the partnerships' wells.

The managing general partner is unable to predict what effect the various
factors set forth above will have on the future price of the natural gas and oil
sold from the partnerships' wells. According to the Annual Energy Outlook 2006
with Projections to 2030 published by the Energy Information Administration
(EIA), total natural gas consumption is projected to increase from 22.34
trillion cubic feet in 2003 to 26.86 trillion cubic feet by 2030. Over that same
period, total natural gas supplies are projected to grow by 4.08 trillion cubic
feet, with domestic natural gas production expected to account for 45% of the
total growth in gas supply, and net imports projected to account for the
remainder. Notwithstanding, wellhead natural gas prices are projected to decline
in the early years of the forecast as a result of the following responses to the
current high prices:

     o    an increase in drilling levels;

     o    the coming online of new natural gas production; and

     o    the increase in liquid natural gas ("LNG") imports.

After 2011, however, natural gas prices are projected to increase in response to
the higher exploration and development costs associated with smaller and deeper
natural gas deposits in the remaining domestic natural gas resource base. Also,
the managing general partner believes there have been several developments which
may increase the demand for natural gas, but may or may not be offset by an
increase in the supply of natural gas, which the managing general partner is
unable to predict. For example, the Clean Air Act Amendments of 1990 contain
incentives for the future development of "clean alternative fuel," which
includes natural gas and liquefied petroleum gas for "clean-fuel vehicles."
Also, the accelerating deregulation of electricity transmission has caused a
convergence between the natural gas and electric industries. In 2004, according
to information from the Energy Information Administration, the breakout of
energy sources for the generation of electricity in the United States was as
follows:

     o    natural gas fired power plants were used to produce approximately 18%;

     o    coal-fired power plants were used to produce approximately 50%;

     o    nuclear power plants were used to produce approximately 20%; and

     o    large scale hydroelectric projects were used to produce approximately
          7%.


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In recent years, the electricity industry has increased its use of natural gas
because of increased competition and the enforcement of stringent environmental
regulations. For example, the Environmental Protection Agency has sought to
enforce environmental regulations which increase the cost of operating
coal-fired power plants. According to the Energy Information Administration, the
demand for natural gas by producers of electricity is expected to increase
through the decade. Also, the last nuclear power plant to come online in the
United States was in June 1996, although the existing nuclear power plants have
increased their capacity and the recent energy act includes tax credits for
constructing new nuclear power plants. Unless the price of natural gas increases
to a point where it becomes uneconomic as an energy source as compared to
alternate energy sources, the managing general partner believes that natural gas
is the preferred fuel for many producers of electricity since many electricity
producers have begun moving away from dirtier-burning fuels, such as coal and
oil because of environmental compliance requirements. In this regard, some of
the new natural gas fired power plants which are coming into service are not
designed to allow for switching to other fuels.

STATE REGULATIONS

Natural gas and oil operations are regulated in Pennsylvania by the Department
of Environmental Resources and in Tennessee by the Department of Environment and
Conservation. Pennsylvania, Tennessee and the other states where each
partnership's wells may be situated impose a comprehensive statutory and
regulatory scheme for natural gas and oil operations, including supervising the
production activities and the transportation of natural gas sold in intrastate
markets, which creates additional financial and operational burdens. Among other
things, these regulations involve:

     o    new well permit and well registration requirements, procedures, and
          fees;

     o    landowner notification requirements;

     o    certain bonding or other security measures;

     o    minimum well spacing requirements;

     o    restrictions on well locations and underground gas storage;

     o    certain well site restoration, groundwater protection, and safety
          measures;

     o    discharge permits for drilling operations;

     o    various reporting requirements; and

     o    well plugging standards and procedures.

These state regulatory agencies also have broad regulatory and enforcement
powers including those associated with pollution and environmental control laws,
which are discussed below.

ENVIRONMENTAL REGULATION

Each partnership's drilling and producing operations will be subject to various
federal, state, and local laws covering the discharge of materials into the
environment, or otherwise relating to the protection of the environment. The
Environmental Protection Agency and state and local agencies will require the
partnerships to obtain permits and take other measures with respect to:

     o    the discharge of pollutants into navigable waters;

     o    disposal of wastewater; and

     o    air pollutant emissions.


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If these requirements or permits are violated there can be substantial civil and
criminal penalties that will increase if there was willful negligence or
misconduct. In addition, the partnerships may be subject to fines, penalties and
unlimited liability for cleanup costs under various federal laws such as the
Federal Clean Water Act, the Clean Air Act, the Resource Conservation and
Recovery Act, the Oil Pollution Act of 1990, the Toxic Substance Control Act and
the Comprehensive Environmental Response, Compensation and Liability Act of 1980
for oil and/or hazardous substance contamination or other pollution caused by a
partnership's drilling activities or its wells and its production activities.

Each partnership and its investor general partners may incur environmental costs
and liabilities due to the nature of the partnership's business and substances
from the partnership's wells as described "Risk Factors." For example, an
accidental release from one of a partnership's wells could subject the
partnership to substantial liabilities arising from environmental cleanup and
restoration costs, claims made by neighboring landowners and other third-parties
for personal injury and property damage, and fines or penalties for related
violations of environmental laws or regulations. Moreover, the possibility
exists that stricter laws, regulations or enforcement policies may be enacted or
adopted in the future which could significantly increase a partnership's
compliance costs and the cost of any remediation that may become necessary.

Also, a partnership's liability can extend to pollution costs that occurred on
the leases before they were acquired by the partnership. Although the managing
general partner will not transfer any lease to a partnership if it has actual
knowledge that there is an existing potential environmental liability on the
lease, there will not be an independent environmental audit of the leases before
they are transferred to a partnership. Thus, there is a risk that the leases
will have potential environmental liability even before drilling begins.

A partnership's required compliance with these environmental laws and
regulations may cause delays or increase the cost of the partnership's drilling
and producing activities. Because these laws and regulations are frequently
changed, the managing general partner is unable to predict the ultimate costs of
complying with present and future environmental laws and regulations. Also, the
managing general partner is unable to obtain insurance to protect against many
environmental claims, including remediation costs.

PROPOSED REGULATION

From time to time there are a number of proposals considered in Congress and in
the legislatures and agencies of various states that if enacted would
significantly and adversely affect the natural gas and oil industry and the
partnerships. The proposals involve, among other things:

     o    limiting the disposal of waste water from wells or the emission of
          greenhouse gases, which could substantially increase a partnership's
          operating costs and make the partnership's wells uneconomical to
          produce;

     o    changes in the federal income tax benefits for drilling natural gas
          and oil wells as discussed in "Federal Income Tax Consequences"; and

     o    tax credits and other incentives for the creation or expansion of
          alternative energy sources to natural gas and oil.

Also, Congress could re-enact price controls or additional taxes on natural gas
and oil in the future. However, it is impossible to accurately predict what
proposals, if any, will be enacted and their subsequent effect on a
partnership's activities.

                       PARTICIPATION IN COSTS AND REVENUES

IN GENERAL

The partnership agreement provides for the sharing of partnership costs and
revenues among the managing general partner and you and the other investors. A
tabular summary of the following discussion appears below. Each partnership will
be a separate business entity from the other partnerships, and you will be a
partner only in the partnership in which you invest. You will have no interest
in the business, assets, or tax benefits of the other partnership unless you
also invest in the other


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partnership. Thus, your investment return will depend solely on the operations
and success or lack of success of the particular partnership in which you
invest.

COSTS

1.   ORGANIZATION AND OFFERING COSTS. Organization and offering costs will be
     charged 100% to the managing general partner. However, the managing general
     partner will not receive any credit towards its required capital
     contribution or its revenue share for any organization and offering costs
     charged to it in excess of 15% of a partnership's subscription proceeds.

     o    Organization and offering costs generally means all costs of
          organizing and selling the offering and includes the dealer-manager
          fee, sales commissions and the up to .5% reimbursement for bona fide
          due diligence expenses.

          The managing general partner will pay a portion of a partnership's
          organization and offering costs to itself, its affiliates and
          independent third-parties and it will contribute the remainder to the
          partnership in the form of services related to organizing this
          offering. The managing general partner will receive a credit for these
          payments and services towards its required capital contribution in
          each partnership. The managing general partner's credit for its
          contribution of services for organization costs will be determined
          based on generally accepted accounting principles. The definition of
          organization and offering costs is set forth in the partnership
          agreement.

2.   LEASE COSTS. Each partnership's leases will be contributed to it by the
     managing general partner. The managing general partner will be credited
     with a capital contribution for each lease valued at:

     o    its cost; or

     o    fair market value if the managing general partner has reason to
          believe that cost is materially more than fair market value.

          The cost of the leases includes a portion of the managing general
          partner's reasonable, necessary and actual expenses for geological,
          geophysical, engineering, drafting, accounting, legal and other like
          services allocated to the leases in conformity with generally accepted
          accounting principles and industry standards. Also, the managing
          general partner has averaged the cost of all of its leases to arrive
          at the average lease cost per prospect set forth in "Compensation,"
          which the managing general partner believes is less than fair market
          value.

3.   INTANGIBLE DRILLING COSTS. Ninety percent of the subscription proceeds of
     you and the other investors in a partnership will be used to pay 100% of
     the intangible drilling costs incurred by that partnership in drilling and
     completing its wells.

     o    Intangible drilling costs generally means those costs of drilling and
          completing a well that are currently deductible, as compared with
          lease costs, which must be recovered through the depletion allowance,
          and equipment costs, which must be recovered through depreciation
          deductions.

     Although subscription proceeds of a partnership may be used to pay the
     costs of drilling different wells depending on when the subscriptions are
     received, 90% of the subscription proceeds of you and the other investors
     will be used to pay intangible drilling costs regardless of when you
     subscribe. Also, even if the IRS successfully challenged the managing
     general partner's characterization of a portion of these costs as
     deductible intangible drilling costs, and instead recharacterized the costs
     as some other item that may not be currently deductible, such as equipment
     costs and/or lease acquisition costs, this recharacterization by the IRS
     would have no effect on the allocation and payment of the costs by you and
     the other investors as intangible drilling costs under the partnership
     agreement.


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     The allocation of each partnership's costs of drilling and completing its
     wells between intangible drilling costs, as defined in the partnership
     agreement, and equipment costs, as defined as "tangible costs" in the
     partnership agreement, will be made by the managing general partner, in its
     sole discretion, when the wells are drilled.

4.   EQUIPMENT COSTS. Ten percent of the subscription proceeds of you and the
     other investors in a partnership will be used to pay a portion of the
     equipment costs incurred by that partnership. All equipment costs of that
     partnership's wells that exceed 10% of the subscription proceeds of you and
     the other investors in the partnership will be charged to the managing
     general partner.

     o    Equipment costs generally means the costs of drilling and completing a
          well that are not currently deductible and are not lease costs.

5.   OPERATING COSTS, DIRECT COSTS, ADMINISTRATIVE COSTS AND ALL OTHER COSTS.
     Operating costs, direct costs, administrative costs, and all other
     partnership costs of your partnership not specifically charged under the
     partnership agreement will be charged between the managing general partner
     and you and the other investors in the partnership in the same ratio as the
     related production revenues are being credited.

     o    These costs generally include all costs of partnership administration
          and producing and maintaining the partnership's wells.

     Each well in a partnership will have a different productive life and when a
     well becomes uneconomic to produce, it will be plugged and abandoned. The
     costs of plugging and abandoning a well (other than those incurred in
     connection with drilling a nonproductive well) are shared between the
     managing general partner and you and the other investors in the same
     percentage as the related production revenues are being shared. For
     example, if the investors are receiving 68% of the partnership revenues and
     the managing general partner is receiving 32% of the partnership revenues,
     then the cost of plugging and abandoning the wells will be shared in the
     same percentages. Typically, the managing general partner will apply the
     salvage value of the equipment towards this obligation. The salvage value
     of the equipment will be shared between you and the other investors and the
     managing general partner based on the total amount of the actual equipment
     costs paid by each. Since the managing general partner in each partnership
     will have paid a majority of the partnership's total equipment costs, as
     compared to the total amount of the partnership's equipment costs paid by
     you and the other investors, it will also receive a majority of the salvage
     value of the equipment. See "Compensation - Drilling Contracts," for a
     discussion of the managing general partner's estimated equipment costs for
     an average partnership well in the primary drilling areas.

     To cover any shortfall that you and the other investors might incur between
     your share of the salvage value of the equipment in a well and your share
     of the plugging and abandoning costs of the well, the managing general
     partner has the right, beginning one year after each partnership well
     begins producing, to retain up to $200 per month of the partnership
     revenues in partnership reserves to cover future plugging and abandonment
     costs of the well. This $200 also includes the managing general partner's
     share of revenues, which will be used exclusively for the managing general
     partner's share of the plugging and abandonment costs of the well. To the
     extent any portion of those reserves ultimately is not required for the
     plugging and abandonment costs of the well, then it will be returned to the
     general operating revenues of the partnership.

6.   THE MANAGING GENERAL PARTNER'S REQUIRED CAPITAL CONTRIBUTION. The managing
     general partner's aggregate capital contributions to each partnership must
     not be less than 25% of all capital contributions to that partnership. This
     includes such items as the managing general partner's:

     o    credit for the cost of the leases it contributes to the partnership,
          or the fair market value of the leases if the managing general partner
          has a reason to believe that cost is materially more than fair market
          value;


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     o    credit for the partnership's organization and offering costs paid or
          incurred by the managing general partner, including the costs of
          services contributed by the managing general partner to the
          partnership as organization costs; and

     o    share of the partnership's equipment costs paid by the managing
          general partner to itself as operator under the drilling and operating
          agreement.

The managing general partner's capital contributions must be paid or made at the
time the costs are required to be paid by the partnership, but in any event not
later than the end of the year immediately following the year in which the
partnership had its final closing.

REVENUES

Each partnership's production revenues from all of its wells will be commingled.
Thus, regardless of when you subscribe to a partnership you will share in the
production revenues from all of the partnership wells in that partnership on the
same basis as the other investors in the partnership in proportion to your
number of units.

1.   PROCEEDS FROM THE SALE OF LEASES. If a partnership well is sold, a portion
     of the sales proceeds will be allocated to the partners in the same
     proportion as their share of the adjusted tax basis of the property. In
     addition, proceeds will be allocated to the managing general partner to the
     extent of the pre-contribution appreciation in value of the property, if
     any. Any excess will be credited as provided in 4, below.

2.   INTEREST PROCEEDS. Interest income earned on your subscription proceeds
     before your partnership's final closing will be credited to your account
     and paid to you not later than the partnership's first cash distributions
     from operations. After your partnership's final closing and until the
     subscription proceeds are invested in your partnership's operations, any
     interest income from temporary investments will be allocated pro rata to
     you and the other investors providing the subscription proceeds. All other
     interest income, including interest earned on the deposit of production
     revenues, will be credited as provided in 4, below.

3.   EQUIPMENT PROCEEDS. Proceeds from the sale or other disposition of
     equipment will be credited to the parties charged with the costs of the
     equipment in the ratio in which the costs were charged.

4.   PRODUCTION REVENUES. Subject to the managing general partner's
     subordination obligation as described below, the managing general partner
     and you and the other investors in a partnership will share in all of that
     partnership's other revenues, including production revenues, in the same
     percentage as their respective capital contribution bears to the
     partnership's total capital contributions, except that the managing general
     partner will receive an additional 7% of that partnership's revenues.

     However, the managing general partner's total revenue share may not exceed
     40% of that partnership's revenues regardless of the amount of its capital
     contributions. For example, if the managing general partner contributes the
     minimum of 25% of the partnership's total capital contributions and the
     investors contribute 75% of the partnership's total capital contributions,
     then the managing general partner will receive 32% of the partnership
     revenues and the investors will receive 68% of the partnership revenues. On
     the other hand, if the managing general partner contributes 35% of the
     partnership's total capital contributions and the investors contribute 65%
     of the partnership's total capital contributions, then the managing general
     partner will receive 40% of the partnership revenues, not 42%, because its
     revenue share cannot exceed 40% of partnership revenues, and the investors
     will receive 60% of partnership revenues.

SUBORDINATION OF PORTION OF MANAGING GENERAL PARTNER'S NET REVENUE SHARE

Each partnership is structured to provide you and the other investors with cash
distributions equal to a minimum of 10% of capital, based on a subscription
price of $10,000 per unit, regardless of the actual subscription price you paid
for your units, in each of the first five 12-month periods beginning with that
partnership's first cash distributions from operations. To help achieve this
investment feature, the managing general


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partner will subordinate up to 50% of its share, as managing general partner, of
partnership net production revenues, which will be up to between 16% and 20% of
the total partnership net production revenues, depending on the amount of its
capital contributions, during this subordination period.

     o    Partnership net production revenues means gross revenues after
          deduction of the related operating costs, direct costs, administrative
          costs, and all other costs not specifically allocated.

Each partnership's 60-month subordination period will begin with that
partnership's first cash distribution from operations to you and the other
investors. Subordination distributions will be determined by debiting or
crediting current period partnership revenues to the managing general partner as
may be necessary to provide the distributions to you and the other investors. At
any time during the subordination period the managing general partner is
entitled to an additional share of partnership revenues to recoup previous
subordination distributions to the extent your cash distributions from that
partnership exceed the 10% return of capital described above. The specific
formula for determining subordination distributions is set forth in Section
5.01(b)(4)(a) of the partnership agreement.

The managing general partner anticipates that you will benefit from the
subordination if the price of natural gas and oil received by the partnership
and/or the results of the partnership's drilling activities, such as the volume
of natural gas and oil produced from the partnership's wells, are unable to
provide the required return of capital. However, if the wells produce small
natural gas and oil volumes or natural gas and oil prices decrease, then even
with subordination your cash flow may be very small and you may not receive the
10% return of capital for each of the first five years beginning with the
partnership's first cash distribution from operations.

As of September 15, 2006, the managing general partner was not subordinating any
of its partnership net production revenues in the 16 limited partnerships that
currently have the subordination feature in effect. Since 1993 the managing
general partner has had the same or a similar subordination feature in 34 of its
partnerships and from time to time it has subordinated its partnership net
production revenues in 16 of those partnerships. The managing general partner is
entitled to recoup those subordination distributions during the respective
subordination period of those previous partnerships to the extent cash
distributions of those previous partnerships to their respective investors would
exceed the specified return to the investors.

EXAMPLE OF NET REVENUE SHARING DURING A SUBORDINATION PERIOD.

<TABLE>
<CAPTION>
                                                                                                         NET REVENUES TO
                                                                           MAXIMUM AMOUNT OF             MANAGING GENERAL
                                                                            MANAGING GENERAL         PARTNER AND INVESTORS IF
                                   PERCENTAGE OF       PERCENTAGE OF       PARTNER'S SHARE OF            MAXIMUM AMOUNT OF
                                    PARTNERSHIP       PARTNERSHIP NET       PARTNERSHIP NET         MANAGING GENERAL PARTNER'S
                                      CAPITAL         REVENUES WITHOUT    REVENUES AVAILABLE         SHARE OF PARTNERSHIP NET
ENTITY                           CONTRIBUTIONS (1)   SUBORDINATION (1)   FOR SUBORDINATION (2)   REVENUES IS SUBORDINATED (1)(2)
------                           -----------------   -----------------   ---------------------   -------------------------------
<S>                                     <C>                 <C>                   <C>                          <C>
Managing General Partner......          25%                 32%                   16%                          16%
Investors ....................          75%                 68%                                                84%
</TABLE>

----------
(1)  These percentages are for illustration purposes only and assume the
     managing general partner's minimum required capital contribution of 25% to
     each partnership and capital contributions of 75% from you and the other
     investors. The actual percentages are likely to be different because they
     will be based on the actual capital contributions of the managing general
     partner and you and the other investors. However, the managing general
     partner's total revenue share may not exceed 40% of partnership revenues
     regardless of the amount of its capital contribution.

(2)  Each partnership is structured to provide you and the other investors with
     cash distributions equal to a minimum of 10% of capital, based on a
     subscription price of $10,000 per unit, regardless of the actual
     subscription price you paid for your units, in each of the first five
     12-month periods beginning with the partnership's first cash distributions
     from operations. To help achieve this investment feature of a 10% return of
     capital for each of the first five 12-month periods, the managing general
     partner will subordinate up to 50% of its share of partnership net
     production revenues, which will be up to between 16% and 20% of the total
     partnership net production revenues, depending on the amount of its capital
     contributions, during this subordination period.


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<PAGE>

EXAMPLE OF NET REVENUE SHARING AFTER THE END OF A SUBORDINATION PERIOD.

<TABLE>
<CAPTION>
                                                                                           NET REVENUES TO MANAGING
                                                                       MAXIMUM AMOUNT OF      GENERAL PARTNER AND
                                                                       MANAGING GENERAL     INVESTORS WHEN NONE OF
                                PERCENTAGE OF       PERCENTAGE OF     PARTNER'S SHARE OF       MANAGING GENERAL
                                 PARTNERSHIP       PARTNERSHIP NET      PARTNERSHIP NET       PARTNER'S SHARE OF
                                   CAPITAL         REVENUES WITHOUT   REVENUES AVAILABLE   PARTNERSHIP NET REVENUES
ENTITY                        CONTRIBUTIONS (1)   SUBORDINATION (1)    FOR SUBORDINATION      IS SUBORDINATED (1)
---------------------------   -----------------   -----------------   ------------------   ------------------------
<S>                                  <C>                 <C>                  <C>                     <C>
Managing General Partner...          25%                 32%                  0%                      32%
Investors..................          75%                 68%                                          68%
</TABLE>

----------
(1)  These percentages are for illustration purposes only and assume the
     managing general partner's minimum required capital contribution of 25% to
     each partnership and capital contributions of 75% from you and the other
     investors. The actual percentages are likely to be different because they
     will be based on the actual capital contributions of the managing general
     partner and you and the other investors. However, the managing general
     partner's total revenue share may not exceed 40% of partnership revenues
     regardless of the amount of its capital contribution.

TABLE OF PARTICIPATION IN COSTS AND REVENUES

The following table sets forth certain partnership costs and revenues charged
and credited between the managing general partner and you and the other
investors in each partnership, after deducting from the partnership's gross
revenues, the landowner royalties and any other lease burdens.

                                                       MANAGING
                                                        GENERAL
                                                        PARTNER   INVESTORS
                                                       --------   ---------
PARTNERSHIP COSTS
Organization and offering costs ....................        100%          0%
Lease costs ........................................        100%          0%
Intangible drilling costs (1) ......................          0%        100%
Equipment costs ....................................         (2)         (2)
Operating costs, administrative costs, direct costs,
   and all other costs .............................         (3)         (3)

PARTNERSHIP REVENUES
Interest income ....................................         (4)         (4)
Equipment proceeds .................................         (2)         (2)
All other revenues including production revenues ...      (5)(6)      (5)(6)

PARTICIPATION IN DEDUCTIONS AND CREDITS
Intangible drilling costs ..........................          0%        100%
Depreciation .......................................         (2)         (2)
Percentage depletion allowance .....................   (5)(6)(7)   (5)(6)(7)
Marginal well production credits ...................   (5)(6)(7)   (5)(6)(7)

----------
(1)  Ninety percent of the subscription proceeds of you and the other investors
     in a partnership will be used to pay 100% of the intangible drilling costs
     incurred by that partnership in drilling and completing its wells.

(2)  Ten percent of the subscription proceeds of you and the other investors in
     a partnership will be used to pay a portion of the equipment costs incurred
     by that partnership in drilling and completing its wells. All equipment
     costs in excess of 10% of that partnership's subscription proceeds will be
     paid by the managing general partner. Thus, the managing general partner
     will pay the majority of each partnership's equipment costs. Equipment
     proceeds, if any, will be credited in the same percentage in which the
     equipment costs were charged. Thus, the managing general partner will
     receive the majority of any equipment proceeds.


                                       89

<PAGE>

(3)  These costs, which also include plugging and abandonment costs of the wells
     after the wells have been drilled, produced, and depleted, will be charged
     to the parties in the same ratio as the related production revenues are
     being credited.

(4)  Interest earned on your subscription proceeds before a partnership's final
     closing will be credited to your account and paid to you not later than the
     partnership's first cash distributions from operations. After the
     partnership's final closing and until the partnership's subscription
     proceeds are invested in its operations, any interest income from temporary
     investments will be allocated pro rata to the investors providing the
     subscription proceeds. All other interest income in the partnership,
     including interest earned on the deposit of operating revenues, will be
     credited as production revenues are credited.

(5)  In each partnership the managing general partner and you and the other
     investors will share in all of the partnership's other revenues in the same
     percentage that their respective capital contributions bear to the
     partnership's total capital contributions, except that the managing general
     partner will receive an additional 7% of the partnership revenues. However,
     the managing general partner's total revenue share in a partnership may not
     exceed 40% of partnership revenues.

(6)  If a portion of the managing general partner's partnership net production
     revenues is subordinated, then the actual allocation of partnership
     revenues between the managing general partner and you and the other
     investors will vary from the allocation described in (5) above.

(7)  The percentage depletion allowances and any marginal well production
     credits will be credited between the managing general partner and you and
     the other investors in the same percentages as the production revenues are
     being credited.

ALLOCATION AND ADJUSTMENT AMONG INVESTORS

The investors' share as a group of each partnership's revenues, gains, income,
costs, marginal well production credits, expenses, losses, and other charges and
liabilities generally will be charged and credited among you and the other
investors in that partnership in accordance with the ratio that your respective
number of units bears to the number of units held by all investors as a group in
that partnership, based on a subscription price of $10,000 per unit regardless
of the actual subscription price you paid for your units. These allocations will
take into account any investor general partner's status as a defaulting investor
general partner. Certain investors, however, will pay a discounted subscription
price for their units as described in "Plan of Distribution." Thus, intangible
drilling costs and the investors' share of the equipment costs of drilling and
completing the partnership's wells will be charged among you and the other
investors in a partnership as set forth above, except that these allocations
(i.e., intangible drilling costs and equipment costs) will be based on the
respective subscription amount paid by you and the other investors for your
respective units as set forth on your respective subscription agreements, rather
than a subscription price of $10,000 per unit for all of the units.

DISTRIBUTIONS

The managing general partner will review each partnership's accounts at least
monthly to determine whether cash distributions are appropriate and the amount
to be distributed, if any, taking into account its subordination obligation
discussed above in "- Subordination of Portion of Managing General Partner's Net
Revenue Share." Your partnership will distribute funds to you and the other
investors that the managing general partner, in its sole discretion, does not
believe are necessary for the partnership to retain. Distributions may be
reduced or deferred to the extent partnership revenues are used for any of the
following:

     o    repayment of partnership borrowings;

     o    cost overruns;

     o    remedial work to improve a well's producing capability;

     o    compensation and fees to the managing general partner as described in
          "Risk Factors - Risks Related to an Investment In a Partnership -
          Compensation and Fees to the Managing General Partner Regardless of
          Success of a Partnership's Activities Will Reduce Cash Distributions";


                                       90

<PAGE>

     o    direct costs and general and administrative expenses of the
          partnership;

     o    reserves, including a reserve for the estimated costs of eventually
          plugging and abandoning the wells; or

     o    indemnification of the managing general partner and its affiliates by
          the partnership for losses or liabilities incurred in connection with
          the partnership's activities.

Also, funds will not be advanced or borrowed by a partnership for the purpose of
making distributions to you and the other investors if the amount advanced or
borrowed would exceed the partnership's accrued and received revenues for the
previous four quarters, less paid and accrued operating costs with respect to
the revenues. Any cash distributions from a partnership to the managing general
partner will be made only in conjunction with distributions to you and the other
investors in that partnership and only out of funds properly allocated to the
managing general partner's account.

LIQUIDATION

Each partnership will continue for 50 years unless it is terminated earlier by a
final terminating event as described below, or an event which causes the
dissolution of a limited partnership under the Delaware Revised Uniform Limited
Partnership Act. However, if a partnership terminates on an event which causes a
dissolution of the partnership under state law and it is not a final terminating
event, then a successor limited partnership will automatically be formed. Thus,
only on a final terminating event will a partnership be liquidated. A final
terminating event is any of the following:

     o    the election to terminate the partnership by the managing general
          partner or the affirmative vote of investors whose units equal a
          majority of the total units;

     o    the termination of the partnership under Section 708(b)(1)(A) of the
          Internal Revenue Code because no part of its business is being carried
          on; or

     o    the partnership ceases to be a going concern.

On the partnership's liquidation you will receive your interest in the
partnership to which you subscribed. Generally, your interest in the partnership
means an undivided interest in the partnership's assets, after payments to the
partnership's creditors, in the ratio that your positive capital account bears
to the positive capital accounts of all of the partners in the partnership
(including the managing general partner) until all of the capital accounts have
been reduced to zero. Thereafter, your interest in the remaining partnership
assets will equal your interest in the related partnership revenues.

Any in-kind property distributions to you from the partnership in which you
invest must be made to a liquidating trust or similar entity, unless you
affirmatively consent to receive an in-kind property distribution after being
told the risks associated with the direct ownership of the property or unless
there are alternative arrangements in place which assure that you will not be
responsible for the operation or disposition of the partnership's properties. If
the managing general partner has not received your written consent to a proposed
in-kind property distribution within 30 days after it is mailed, then it will be
presumed that you have not consented. The managing general partner may then sell
the asset at the best price reasonably obtainable from an independent
third-party, or to itself or its affiliates at fair market value as determined
by an independent expert selected by the managing general partner. Also, if the
partnership is liquidated the managing general partner will be repaid any debts
owed to it by the partnership before there are any payments to you and the other
investors in that partnership.

                              CONFLICTS OF INTEREST

IN GENERAL

Conflicts of interest are inherent in natural gas and oil partnerships involving
non-industry investors because the transactions are entered into without arms'
length negotiation. Your interests and those of the managing general partner and
its affiliates may be inconsistent in some respects or in certain instances, and
the managing general partner's actions may not be the most advantageous to you.
The following discussion describes certain possible conflicts of interest that
may arise for the


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<PAGE>

managing general partner and its affiliates in the course of each partnership.
For some of the conflicts of interest, but not all, there are certain
limitations on the managing general partner that are designed to reduce, but
will not eliminate, the conflicts. Other than these limitations the managing
general partner has no procedures to resolve a conflict of interest and under
the terms of the partnership agreement the managing general partner may resolve
the conflict of interest in its sole discretion and best interest.

Further, the managing general partner depends on its indirect parent company,
Atlas America and its affiliates, for management and administrative functions
and financing for capital expenditures. Neither the partnership agreement nor
any other agreement requires Atlas America to pursue a future business strategy
that favors the partnerships. Atlas America's directors and officers have a
fiduciary duty to make decisions in the best interests of the stockholders of
Atlas America. Because the managing general partner is allowed to take into
account the interests of parties other than the partnerships, such as Atlas
America and Atlas Energy Resources, LLC, in resolving partnership conflicts of
interest, this has the effect of limiting its fiduciary duty to the
partnerships.

The following discussion is materially complete; however, other transactions or
dealings may arise in the future that could result in conflicts of interest for
the managing general partner and its affiliates.

CONFLICTS REGARDING TRANSACTIONS WITH THE MANAGING GENERAL PARTNER AND ITS
AFFILIATES

Although the managing general partner believes that the compensation and
reimbursement that it and its affiliates will receive in connection with each
partnership are reasonable, the compensation has been determined solely by the
managing general partner and did not result from negotiations with any
unaffiliated third-party dealing at arms' length. The managing general partner
and its affiliates will receive compensation and reimbursement from each
partnership for their services in drilling, completing, and operating that
partnership's wells under the drilling and operating agreement and will receive
the other fees described in "Compensation" regardless of the success of that
partnership's wells. The managing general partner and its affiliates providing
the services or equipment can be expected to profit from the transactions, and
it is usually in the managing general partner's best interest to enter into
contracts with itself and its affiliates, rather than unaffiliated third-parties
even if the contract terms, skill, and experience, offered by the unaffiliated
third-parties are comparable.

When the managing general partner or any affiliate provides services or
equipment to a partnership the partnership agreement provides that their fees
must be competitive with the fees charged by unaffiliated third-parties in the
same geographic area engaged in similar businesses. Also, before the managing
general partner or any affiliate may receive competitive fees for providing
services or equipment to a partnership they must be engaged, independently of
the partnership and as an ordinary and ongoing business, in rendering the
services or selling or leasing the equipment and supplies to a substantial
extent to other persons in the natural gas and oil industry in addition to the
partnerships in which the managing general partner or an affiliate has an
interest. If the managing general partner or the affiliate is not engaged in
such a business, then the compensation must be the lesser of its cost or the
competitive rate that could be obtained in the area.

Any services not otherwise described in this prospectus or the partnership
agreement for which the managing general partner or an affiliate is to be
compensated by a partnership must be:

     o    set forth in a written contract that describes the services to be
          rendered and the compensation to be paid; and

     o    cancelable without penalty on 60 days written notice by investors
          whose units equal a majority of the total units.

The compensation paid by the partnership to the managing general partner or its
affiliates for additional services to the partnership under these contracts, if
any, will be reported to you in your partnership's annual and semiannual
reports, and a copy of the contract will be provided to you on request.

There is also a conflict of interest concerning the purchase price if the
managing general partner or an affiliate purchases a property from a
partnership, which they may do in certain limited circumstances as described in
"- Conflicts Involving the


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<PAGE>

Acquisition of Leases - (6) Limitations on Sale of Undeveloped and Developed
Leases to the Managing General Partner," below.

CONFLICT REGARDING THE DRILLING AND OPERATING AGREEMENT

The managing general partner anticipates that all of the wells to be drilled by
each partnership will be drilled and operated under the drilling and operating
agreement. This creates a continuing conflict of interest because the managing
general partner must monitor and enforce, on behalf of each partnership, its own
compliance, as operator with the drilling and operating agreement and as
managing general partner with the partnership agreement, and the compliance of
its affiliate, Atlas Pipeline Partners, with the gas gathering agreement.

CONFLICTS REGARDING SHARING OF COSTS AND REVENUES

The managing general partner will receive a percentage of partnership revenues
that is greater than the percentage of partnership costs that it pays. This
sharing arrangement may create a conflict of interest between the managing
general partner and you and the other investors in a partnership concerning the
determination of which wells will be drilled by the partnership based on the
risk and profit potential associated with the wells.

In addition, the allocation of all of the intangible drilling costs to you and
the other investors and the majority of the equipment costs to the managing
general partner creates a conflict of interest between the managing general
partner and you and the other investors concerning whether to complete a well.
For example, the completion of a marginally productive well might prove
beneficial to you and the other investors, but not to the managing general
partner. When a completion decision is made, you and the other investors will
have already paid the majority of your costs so you will want to pay your share
of the additional costs to complete the well (i.e., 10% of the additional
equipment costs to complete the well) if there is a reasonable opportunity to
recoup your share of the completion costs plus any portion of the costs of the
well paid by you before the completion attempt.

On the other hand, the managing general partner will have paid only a portion of
its costs before this time, and it will want to pay its additional equipment
costs to complete the well only if it is reasonably certain of recouping its
share of the completion costs and making a profit. However, based on its past
experience the managing general partner anticipates that most of the wells in
the primary areas will have to be completed before it can determine the well's
productivity, which would eliminate this potential conflict of interest. In any
event, the managing general partner will not cause any well to be plugged and
abandoned without a completion attempt unless it makes the decision in
accordance with generally accepted oil and gas field practices in the geographic
area of the well location.

CONFLICTS REGARDING TAX MATTERS PARTNER

The managing general partner will serve as each partnership's tax matters
partner and represent the partnership before the IRS. The managing general
partner will have broad authority to act on behalf of you and the other
investors in the partnership in any administrative or judicial proceeding
involving the IRS, and this authority may involve conflicts of interest. For
example, potential conflicts include:

     o    whether or not to expend partnership funds to contest a proposed
          adjustment by the IRS, if any, that would decrease:

          o    the amount of a partnership's deduction for intangible drilling
               costs, which is allocated 100% to you and the other investors in
               the partnership; or

          o    the amount of the managing general partner's depreciation
               deductions, or the credit to its capital account for contributing
               the leases to a partnership which would also decrease the
               managing general partner's liquidation interest in the
               partnership; or

     o    the amount charged to a partnership by the managing general partner as
          reimbursement for expenses incurred by the managing general partner in
          its role as the tax matters partner.


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<PAGE>

CONFLICTS REGARDING OTHER ACTIVITIES OF THE MANAGING GENERAL PARTNER, THE
OPERATOR AND THEIR AFFILIATES

The managing general partner will be required to devote to each partnership the
time and attention that it considers necessary for the proper management of the
partnership's activities. However, the managing general partner has sponsored
and continues to manage other natural gas and oil drilling partnerships, which
may be concurrent, and it will engage in unrelated business activities, either
for its own account or on behalf of other partnerships, joint ventures,
corporations, or other entities in which it has an interest. This creates a
continuing conflict of interest in allocating management time, services, and
other activities among the partnerships in this program and the managing general
partner's other activities.

The managing general partner will determine the allocation of its management
time, services, and other functions on an as-needed basis consistent with its
fiduciary duties among the partnerships in this program and its other
activities. However, the managing general partner depends on its indirect parent
company, Atlas America and its affiliates, for management and administrative
functions and financing for capital expenditures as described in "Management -
Transactions with Management and Affiliates." Thus, the competition for the time
and services of the managing general partner and its affiliates could result in
insufficient attention to the management and operation of the partnerships.

Subject to its fiduciary duties, the managing general partner will not be
restricted from participating in other businesses or activities, even if these
other businesses or activities compete with a partnership's activities and
operate in the same areas as a partnership. However, the managing general
partner and its affiliates may pursue business opportunities that are consistent
with a partnership's investment objectives for their own account only after they
have determined that the opportunity either:

     o    cannot be pursued by the partnership because of insufficient funds; or

     o    it is not appropriate for the partnership under the existing
          circumstances.

CONFLICTS INVOLVING THE ACQUISITION OF LEASES

The managing general partner will select, in its sole discretion, the wells to
be drilled by each partnership. Conflicts of interest may arise concerning which
wells will be drilled by each partnership in this program and which wells will
be drilled by the managing general partner's and its affiliates' other
affiliated partnerships or third-party programs in which they serve as
driller/operator. It may be in the managing general partner's or its affiliates'
advantage to have a partnership in this program bear the costs and risks of
drilling a particular well rather than another affiliate. These potential
conflicts of interest will be increased if the managing general partner
organizes and allocates wells to more than one partnership at a time. To lessen
this conflict of interest the managing general partner generally takes a similar
interest in the other partnerships when it serves as managing general partner
and/or driller/operator of the other partnerships. Also, as discussed in
"Proposed Activities," the managing general partner has a drilling commitment
with Knox Energy for the drilling of 300 wells, which creates a conflict of
interest in deciding whether the managing general partner will select wells for
each partnership to drill in the areas that will help the managing general
partner satisfy this drilling commitment.

When the managing general partner must provide prospects to two or more
partnerships at the same time it will attempt to treat each partnership fairly
on a basis consistent with:

     o    the funds available to the partnerships; and

     o    the time limitations on the investment of funds for the partnerships.

The partnership agreement gives the managing general partner the authority to
cause each partnership in this program to acquire undivided interests in natural
gas and oil properties, and to participate with other parties, including other
drilling programs previously or subsequently conducted by the managing general
partner or its affiliates, in the conduct of its drilling operations on those
properties. If conflicts between the interest of a partnership in this program
and other drilling partnerships do arise, then the managing general partner may
be unable to resolve those conflicts to the maximum advantage of a partnership
in this program because the managing general partner must deal fairly with the
investors in all of its drilling partnerships.


                                       94

<PAGE>

In addition, subject to the restrictions set forth below, the managing general
partner decides which prospects and what interest in the prospects to transfer
to a partnership. This will result in a subsequent partnership sponsored by the
managing general partner benefiting from knowledge gained through a prior
partnership's drilling experience in an area and acquiring a prospect adjacent
to the prior partnership's prospect. In this regard, as drilling progresses,
reserves from newly completed wells are reclassified from the proved undeveloped
to the proved developed category and additional adjacent locations are added to
proved undeveloped reserves.

No procedures, other than the guidelines set forth below and in "- Procedures to
Reduce Conflicts of Interest," have been established by the managing general
partner to resolve any conflicts that may arise. The partnership agreement
provides that the managing general partner and its affiliates will abide by the
guidelines set forth below. However, with respect to (2), (3), (4), (5), (7) and
(9) there is an exception in the partnership agreement for another program in
which the interest of the managing general partner is substantially similar to
or less than its interest in the partnerships.

(1)  TRANSFERS AT COST. All leases will be acquired by each partnership from the
     managing general partner and credited towards its required capital
     contribution to the partnership at the cost of the lease, unless the
     managing general partner has a reason to believe that cost is materially
     more than the fair market value of the property. If the managing general
     partner believes that cost is materially more than fair market value, then
     the managing general partner's credit for the contribution must be at a
     price not in excess of the fair market value. (See "Participation in Costs
     and Revenues - Costs - Lease Costs.")

          o    A determination of fair market value must be supported by an
               appraisal from an independent expert and maintained in the
               partnership's records for at least six years.

(2)  EQUAL PROPORTIONATE INTEREST. When the managing general partner sells or
     transfers an oil and gas interest to a partnership, it must, at the same
     time, sell or transfer to the partnership an equal proportionate interest
     in all of its other property in the same prospect.

          o    The term "prospect" generally means an area which is believed to
               contain commercially productive quantities of natural gas or oil.

     However, a prospect will be limited to the drilling or spacing unit on
     which one well will be drilled if the following two conditions are met:

          o    the well is being drilled to a geological feature which contains
               proved reserves as defined below; and

          o    the drilling or spacing unit protects against drainage.

     The managing general partner believes that for a prospect located in the
     primary drilling areas as described in "Proposed Activities - Primary Areas
     of Operations," a prospect will consist of the drilling and spacing unit
     because it will meet the test in the preceding sentence.

          o    Proved reserves, generally, are the estimated quantities of
               natural gas and oil which have been demonstrated to be
               recoverable in future years with reasonable certainty under
               existing economic and operating conditions. Proved reserves
               include proved undeveloped reserves which generally are reserves
               expected to be recovered from existing wells where a relatively
               major expenditure is required for recompletion or from new wells
               on undrilled acreage. Reserves on undrilled acreage will be
               limited to those drilling units offsetting productive units that
               are reasonably certain of production when drilled. Proved
               Reserves for other undrilled units can be claimed only where it
               can be demonstrated with certainty that there is continuity of
               production from the existing productive formation.


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<PAGE>

     In the primary areas the managing general partner anticipates that the
     drilling of these wells by each partnership may provide the managing
     general partner with offset sites by allowing it to determine, at the
     partnership's expense, the value of adjacent acreage in which the
     partnership would not have any interest. The managing general partner owns
     acreage throughout the primary areas where each partnership's wells will be
     situated. To lessen this conflict of interest, for five years the managing
     general partner may not drill any well:

          o    to the Clinton/Medina geologic formation, if the well would be
               within 1,650 feet of an existing partnership well in Pennsylvania
               or within 1,000 feet of an existing partnership well in Ohio; or

          o    to the Mississippian/Upper Devonian Sandstone reservoirs in
               Fayette, Greene and Westmoreland Counties, Pennsylvania, if the
               well would be within at least 1,000 feet from a producing well,
               although a partnership may drill a new well or re-enter an
               existing well that is closer than 1,000 feet to a plugged and
               abandoned well.

     If a partnership abandons its interest in a well, then the restrictions
     described above will continue for one year following the abandonment. There
     are no similar prohibitions for a partnership's other primary drilling
     area, although the managing general partner believes that none of the
     prospects transferred to a partnership will result in drainage from the
     surrounding wells.

(3)  SUBSEQUENTLY ENLARGING PROSPECT. In areas where the prospect is not limited
     to the drilling or spacing unit and the area constituting a partnership's
     prospect is subsequently enlarged based on geological information, which is
     later acquired, then there is the following special provision:

          o    if the prospect is enlarged to cover any area where the managing
               general partner owns a separate property interest and the
               partnership activities were material in establishing the
               existence of proved undeveloped reserves which are attributable
               to the separate property interest, then the separate property
               interest or a portion thereof must be sold to the partnership in
               accordance with (1), (2) and (4).

(4)  TRANSFER OF LESS THAN THE MANAGING GENERAL PARTNER'S AND ITS AFFILIATES'
     ENTIRE INTEREST. If the managing general partner sells or transfers to a
     partnership less than all of its ownership in any prospect, then it must
     comply with the following conditions:

          o    the retained interest must be a proportionate working interest;

          o    the managing general partner's obligations and the partnership's
               obligations must be substantially the same after the sale of the
               interest by the managing general partner or its affiliates; and

          o    the managing general partner's revenue interest must not exceed
               the amount proportionate to its retained working interest.

     For example, if the managing general partner transfers 50% of its working
     interest in a prospect to a partnership and retains a 50% working interest,
     then the partnership will not pay any of the costs associated with the
     managing general partner's retained working interest as a part of the
     transfer. This limitation does not prevent the managing general partner and
     its affiliates from subsequently dealing with their retained working
     interest as they may choose with unaffiliated parties or affiliated
     partnerships. For example, the managing general partner may sell its
     retained working interest to a third-party for a profit.

(5)  LIMITATIONS ON ACTIVITIES OF THE MANAGING GENERAL PARTNER AND ITS
     AFFILIATES ON LEASES ACQUIRED BY A PARTNERSHIP. For a five year period
     after the final closing of a partnership, if the managing general partner
     proposes to acquire an interest from an unaffiliated person in a prospect
     in which the partnership owns an interest or in a


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     prospect in which the partnership's interest has been terminated without
     compensation within one year before the proposed acquisition, then the
     following conditions apply:

          o    if the managing general partner does not currently own property
               in the prospect separately from the partnership, then the
               managing general partner may not buy an interest in the prospect;
               and

          o    if the managing general partner currently owns a proportionate
               interest in the prospect separately from the partnership, then
               the interest to be acquired must be divided in the same
               proportion between the managing general partner and the
               partnership as the other property in the prospect. However, if
               the partnership does not have the cash or financing to buy the
               additional interest, then the managing general partner is also
               prohibited from buying the additional interest.

(6)  LIMITATIONS ON SALE OF UNDEVELOPED AND DEVELOPED LEASES TO THE MANAGING
     GENERAL PARTNER. The managing general partner and its affiliates, other
     than an affiliated partnership as set forth in (7) below, may not purchase
     undeveloped leases or receive a farmout from a partnership other than at
     the higher of cost or fair market value. Farmouts to the managing general
     partner and its affiliates also must comply with the conditions set forth
     in (9) below.

     The managing general partner and its affiliates, other than an affiliated
     income program, may not purchase any producing natural gas or oil property
     from a partnership unless:

          o    the sale is in connection with the liquidation of the
               partnership; or

          o    the managing general partner's well supervision fees under the
               drilling and operating agreement for the well have exceeded the
               net revenues of the well, determined without regard to the
               managing general partner's well supervision fees for the well,
               for a period of at least three consecutive months.

     In both cases, the sale must be at fair market value supported by an
     appraisal of an independent expert selected by the managing general
     partner. The appraisal of the property must be maintained in the
     partnership's records for at least six years.

(7)  TRANSFER OF LEASES BETWEEN AFFILIATED LIMITED PARTNERSHIPS. The transfer of
     an undeveloped lease from a partnership to an affiliated drilling limited
     partnership must be made at fair market value if the undeveloped lease has
     been held by the partnership for more than two years. Otherwise, the
     transfer may be made at cost if the managing general partner deems it to be
     in the best interest of the partnership.

     An affiliated income program may purchase a producing natural gas and oil
     property from a partnership at any time at:

          o    fair market value as supported by an appraisal from an
               independent expert if the property has been held by the
               partnership for more than six months or there have been
               significant expenditures made in connection with the property; or

          o    cost as adjusted for intervening operations if the managing
               general partner deems it to be in the best interest of the
               partnership.

     However, these prohibitions do not apply to joint ventures or farmouts
     among affiliated partnerships, provided that:

          o    the respective obligations and revenue sharing of all parties to
               the transaction are substantially the same; and


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          o    the compensation arrangement or any other interest or right of
               either the managing general partner or its affiliates is the same
               in each affiliated partnership or if different, the aggregate
               compensation of the managing general partner or the affiliate is
               reduced to reflect the lower compensation arrangement.

(8)  LEASES WILL BE ACQUIRED ONLY FOR STATED PURPOSE OF THE PARTNERSHIP. Each
     partnership must acquire only leases that are reasonably expected to meet
     the stated purposes of the partnership. Also, no leases may be acquired for
     the purpose of a subsequent sale, farmout or other disposition unless the
     acquisition is made after a well has been drilled to a depth sufficient to
     indicate that the acquisition would be in the partnership's best interest.

(9)  FARMOUT. The managing general partner may not assign the working interest
     in a prospect to a partnership for the purpose of a subsequent farmout,
     sale or other disposition, nor may the managing general partner enter into
     a farmout to avoid paying its share of the costs related to drilling a well
     on an undeveloped lease. However, the managing general partner's decision
     with respect to making a farmout and the terms of a farmout from a
     partnership involve conflicts of interest since the managing general
     partner may benefit from cost savings and reduction of its risk.

     The partnership may farmout an undeveloped lease or well activity to the
     managing general partner, its affiliates or an unaffiliated third-party
     only if the managing general partner, exercising the standard of a prudent
     operator, determines that:

          o    the partnership lacks the funds to complete the oil and gas
               operations on the lease or well and cannot obtain suitable
               financing;

          o    drilling on the lease or the intended well activity would
               concentrate excessive funds in one location, creating undue risks
               to the partnership;

          o    the leases or well activity have been downgraded by events
               occurring after assignment to the partnership so that development
               of the leases or well activity would not be desirable; or

          o    the best interests of the partnership would be served.

     If the partnership farmouts a lease or well activity, the managing general
     partner must retain on behalf of the partnership the economic interests and
     concessions as a reasonably prudent oil and gas operator would or could
     retain under the circumstances prevailing at the time, consistent with
     industry practices. However, if the farmout is made to the managing general
     partner or its affiliates there is a conflict of interest since the
     managing general partner will represent both the partnership and itself or
     an affiliate. Although the conflict of interest may be resolved to the
     managing general partner's benefit, the managing general partner must still
     retain on behalf of the partnership the economic interests and concessions
     as a reasonably prudent oil and gas operator would or could retain under
     the circumstances prevailing at the time, consistent with industry
     practices.

CONFLICTS REGARDING ORDER OF PIPELINE CONSTRUCTION AND GATHERING FEES

There are conflicts between you and the managing general partner and its
affiliates, because the managing general partner must monitor and enforce on
behalf of the partnerships the compliance of its affiliate, Atlas Pipeline
Partners, with the gas gathering agreement. Also, the managing general partner
may choose well locations for the partnerships that are situated near Atlas
Pipeline Partners' gathering system which would benefit the managing general
partner's indirect parent company, Atlas America, by providing more gathering
fees to Atlas Pipeline Partners, even if there are other well locations
available in the same area or other areas which offer the partnerships a greater
potential return. (See "Management - Organizational Diagrams and Security
Ownership of Beneficial Owners.") However, the managing general partner believes
this conflict of interest is substantially reduced because the managing general
partner expects to make the largest single capital contribution in each
partnership as explained in "Capitalization and Source of Funds and Use of
Proceeds."


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In addition, Atlas America or an affiliate will operate the Atlas Pipeline
Partners gathering system. Thus, the expansion of the Atlas Pipeline Partners
gathering system will be within the control of the managing general partner's
affiliate, which the managing general partner believes will attempt to expand
the Atlas Pipeline Partners gathering system to those areas with the greatest
number of wells with the greatest potential reserves. However, Atlas Pipeline
Holdings, L.P., a wholly-owned subsidiary of Atlas America, recently completed
an initial public offering of a minority interest in its units and, as a public
company, may be more susceptible to a change of control. (See "Risk Factors -
Risks Related to the Partnerships' Oil and Gas Operations - Adverse Events in
Marketing a Partnership's Natural Gas Could Reduce Partnership Distributions.")

Further, certain of the managing general partner's affiliates, including Atlas
America, are obligated through their agreement with Atlas Pipeline Partners to
pay the difference between the amount a partnership pays for gathering fees to
the managing general partner as set forth in "Compensation - Gathering Fees,"
and the greater of $.35 per mcf or 16% of the gross sales price for the natural
gas. This creates a conflict of interest between the managing general partner
and a partnership because the managing general partner has an economic incentive
to increase the amount of gathering fees paid by the partnership so as to reduce
the amount paid by Atlas America to Atlas Pipeline Partners, but any increase
cannot exceed a competitive rate. Further, if Atlas Pipeline Partners GP, LLC
were removed as general partner of Atlas Pipeline Partners without cause and
without its consent, this could create further pressure to increase the amount
of gathering fees required to be paid by a partnership for natural gas
transported through Atlas Pipeline Partners' gathering system. This could happen
because Atlas Pipeline Partners GP, LLC would no longer receive revenues from
Atlas Pipeline Partners, but Atlas America and its affiliates would still be
obligated to pay the difference between the amount of gathering fees set forth
in the master natural gas gathering agreement, as described above, and the
amount of gathering fees paid by a partnership, other than with respect to new
wells drilled by the partnership after the removal of Atlas Pipeline Partners
GP, LLC as general partner of Atlas Pipeline Partners, if any. Thus, the
managing general partner and its affiliates would have a further economic
incentive to increase the gathering fees. Any increase in the gathering fees
that a partnership pays would reduce your cash distributions from the
partnership. However, the gathering fees paid to the managing general partner
may not exceed competitive rates.

CONFLICTS BETWEEN INVESTORS AND THE MANAGING GENERAL PARTNER AS AN INVESTOR

The managing general partner, its officers, directors, and its affiliates may
subscribe for units in each partnership and the subscription price of their
units will be reduced by 10% as described in "Plan of Distribution." Even though
they pay a reduced price for their units, these investors generally will:

     o    share in the partnership's costs, revenues, and distributions on the
          same basis as the other investors as described in "Participation in
          Costs and Revenues"; and

     o    have the same voting rights, except as discussed below.

Any subscription for units by the managing general partner, its officers,
directors, or affiliates in the partnership in which you invest will dilute the
voting rights of you and the other investors and there may be a conflict with
respect to certain matters. The managing general partner and its officers,
directors and affiliates, however, are prohibited from voting with respect to
certain matters as described in "Summary of Partnership Agreement - Voting
Rights."

LACK OF INDEPENDENT UNDERWRITER AND DUE DILIGENCE INVESTIGATION

The terms of this offering, the partnership agreement, and the drilling and
operating agreement were determined by the managing general partner without
arms' length negotiations. You and the other investors have not been separately
represented by legal counsel, who might have negotiated more favorable terms for
you and the other investors in this offering and the agreements.

Also, there was not an extensive in-depth "due diligence" investigation of the
existing and proposed business activities of the partnerships and the managing
general partner that would be provided by independent underwriters. Although
Anthem Securities, which is affiliated with the managing general partner, serves
as dealer-manager of this offering and will receive reimbursement of bona fide
due diligence expenses for certain due diligence investigations conducted by the
selling agents, all of which will be reallowed by Anthem Securities to the
selling agents, its due diligence examination concerning this


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offering cannot be considered to be independent or as comprehensive as a due
diligence examination that would have been conducted by an independent
underwriter.

CONFLICTS CONCERNING LEGAL COUNSEL

The managing general partner anticipates that its legal counsel will also serve
as legal counsel to each partnership and that this dual representation will
continue in the future. However, if a future dispute arises between the managing
general partner and you and the other investors in a partnership, then the
managing general partner will cause you and the other investors to retain
separate counsel. Also, if counsel advises the managing general partner that
counsel reasonably believes its representation of a partnership will be
adversely affected by its responsibilities to the managing general partner, then
the managing general partner will cause you and the other investors in a
partnership to retain separate counsel.

CONFLICTS REGARDING PRESENTMENT FEATURE

You and the other investors in a partnership have the right to present your
units in the partnership to the managing general partner for purchase beginning
with the fifth calendar year after the end of the calendar year in which your
partnership closes. This creates the following conflicts of interest between you
and the managing general partner.

     o    The managing general partner may suspend the presentment feature if it
          does not have the necessary cash flow or it cannot borrow funds for
          this purpose on terms which it deems reasonable. Both of these
          determinations are subjective and will be made in the managing general
          partner's sole discretion.

     o    The managing general partner will also determine the purchase price
          based on a reserve report that it prepares and is reviewed by an
          independent expert that it chooses. The formula for arriving at the
          purchase price has many subjective determinations that are within the
          discretion of the managing general partner.

CONFLICTS REGARDING MANAGING GENERAL PARTNER WITHDRAWING OR ASSIGNING AN
INTEREST

A conflict of interest is created with you and the other investors by the
managing general partner's right to do any of the following:

     o    mortgage its managing general partner interest in each partnership;

     o    withdraw an interest in each partnership's wells equal to or less than
          its revenue interest to be used as collateral for a loan to the
          managing general partner; or

     o    assign, subject to the managing general partner's subordination
          obligation, its managing general partner interest in each partnership
          to its affiliates which also may mortgage the interests as collateral
          for their loans, if any.

If the managing general partner assigned a portion or all, of its managing
general partner interest in a partnership to an affiliate, the amount of
partnership net production revenues available to the managing general partner or
an affiliated assignee for their respective subordination obligations to you and
the other investors could be reduced or eliminated if there was a default under
a loan to the managing general partner or the affiliated assignee. Also, under
certain circumstances, if the managing general partner or an affiliated assignee
if a portion or all, of the managing general partner's managing general partner
interest in a partnership was assigned by the managing general partner to an
affiliate as discussed above, made a subordination distribution to you and the
other investors after a default to its lenders, then the lenders may be able to
recoup that subordination distribution from you and the other investors.

PROCEDURES TO REDUCE CONFLICTS OF INTEREST

In addition to the procedures set forth in "- Conflicts Involving the
Acquisition of Leases," the managing general partner and its affiliates will
comply with the following procedures in the partnership agreement to reduce some
of the conflicts of interest with you and the other investors. The managing
general partner does not have any other conflict of interest resolution
procedures. Thus, conflicts of interest between the managing general partner and
you and the other investors may


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not necessarily be resolved in your best interests. However, the managing
general partner believes that its significant capital contribution to each
partnership will reduce the conflicts of interest.

(1)  FAIR AND REASONABLE. The managing general partner may not sell, transfer,
     or convey any property to, or purchase any property from, a partnership
     except pursuant to transactions that are fair and reasonable; nor take any
     action with respect to the assets or property of a partnership which does
     not primarily benefit the partnership.

(2)  NO COMPENSATING BALANCES. The managing general partner may not use a
     partnership's funds as a compensating balance for its own benefit. Thus, a
     partnership's funds may not be used to satisfy any deposit requirements
     imposed by a bank or other financial institution on the managing general
     partner for its own corporate purposes.

(3)  FUTURE PRODUCTION. The managing general partner may not commit the future
     production of a partnership well exclusively for the managing general
     partner's own benefit.

(4)  DISCLOSURE. Any agreement or arrangement that binds a partnership must be
     fully disclosed in this prospectus.

(5)  NO LOANS FROM A PARTNERSHIP. A partnership may not loan money to the
     managing general partner.

(6)  NO REBATES. The managing general partner may not participate in any
     business arrangements which would circumvent these guidelines including
     receiving rebates or give-ups.

(7)  SALE OF ASSETS. The sale of all or substantially all of the assets of a
     partnership may only be made with the consent of investors whose units
     equal a majority of the total units.

(8)  PARTICIPATION IN OTHER PARTNERSHIPS. If a partnership participates in other
     partnerships or joint ventures, then the terms of the arrangements must not
     circumvent any of the requirements contained in the partnership agreement,
     including the following:

     o    there may be no duplication or increase in organization and offering
          expenses, the managing general partner's compensation, partnership
          expenses, or other fees and costs;

     o    there may be no substantive change in the fiduciary and contractual
          relationship between the managing general partner and you and the
          other investors; and

     o    there may be no diminishment in your voting rights.

(9)  INVESTMENTS. A partnership's funds may not be invested in the securities of
     another person except in the following instances:

     o    investments in working interests made in the ordinary course of the
          partnership's business;

     o    temporary investments in income producing short-term highly liquid
          investments, in which there is appropriate safety of principal, such
          as U.S. Treasury Bills;

     o    multi-tier arrangements meeting the requirements of (8) above;

     o    investments involving less than 5% of the total subscription proceeds
          of the partnership that are a necessary and incidental part of a
          property acquisition transaction; and

     o    investments in entities established solely to limit the partnership's
          liabilities associated with the ownership or operation of property or
          equipment, provided that duplicative fees and expenses are prohibited.


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(10) SAFEKEEPING OF FUNDS. The managing general partner may not employ, or
     permit another to employ, the funds or assets of a partnership in any
     manner except for the exclusive benefit of the partnership. The managing
     general partner has a fiduciary responsibility for the safekeeping and use
     of all funds and assets of each partnership whether or not in the managing
     general partner's possession or control.

(11) ADVANCE PAYMENTS. Advance payments by each partnership to the managing
     general partner and its affiliates are prohibited except when advance
     payments are required to secure the tax benefits of prepaid intangible
     drilling costs and for a business purpose.

POLICY REGARDING ROLL-UPS

It is possible at some indeterminate time in the future that each partnership
may become involved in a roll-up. In general, a roll-up means a transaction
involving the acquisition, merger, conversion, or consolidation of a partnership
with or into another partnership, corporation or other entity, and the issuance
of securities by the roll-up entity to you and the other investors. A roll-up
will also include any change in the rights, preferences, and privileges of you
and the other investors in the partnership. These changes could include the
following:

     o    increasing the compensation of the managing general partner;

     o    amending your voting rights;

     o    listing the units on a national securities exchange or on NASDAQ;

     o    changing the partnership's fundamental investment objectives; or

     o    materially altering the partnership's duration.

If a roll-up should occur in the future, the partnership agreement provides
various policies which include the following:

     o    an independent expert must appraise all partnership assets as
          discussed in Section 4.03(d)(16)(a) of the partnership agreement, and
          you must receive a summary of the appraisal in connection with a
          proposed roll-up;

     o    if you vote "no" on the roll-up proposal, then you will be offered a
          choice of:

          o    accepting the securities of the roll-up entity; or

          o    one of the following:

               o    remaining a partner in the partnership and preserving your
                    units in the partnership on the same terms and conditions as
                    existed previously; or

               o    receiving cash in an amount equal to your pro-rata share of
                    the appraised value of the partnership's net assets; and

     o    the partnership will not participate in a proposed roll-up:

          o    unless approved by investors whose units equal 66% of the total
               units;

          o    which would result in the diminishment of your voting rights
               under the roll-up entity's chartering agreement;

          o    which includes provisions which would operate to materially
               impede or frustrate the accumulation of shares by you of the
               securities of the roll-up entity;


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          o    in which your right of access to the records of the roll-up
               entity would be less than those provided by the partnership
               agreement; or

          o    in which any of the transaction costs would be borne by the
               partnership if the proposed roll-up is not approved by investors
               whose units equal 66% of the total units.

            FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER

IN GENERAL

The managing general partner will manage your partnership and its assets. In
conducting your partnership's affairs the managing general partner is
accountable to you as a fiduciary, which under Delaware law generally means that
the managing general partner must exercise due care and deal fairly with you and
the other investors. Neither the partnership agreement nor any other agreement
between the managing general partner and each partnership may contractually
limit any fiduciary duty owed to you and the other investors by the managing
general partner under applicable law except as set forth in Sections 4.01, 4.02,
4.03, 4.04, 4.05, and 4.06 of the partnership agreement. See "Conflicts of
Interest - In General" regarding the managing general partner's dependence on
its indirect parent company, Atlas America and its affiliates, for management
and administrative functions and financing for capital expenditures and
"Management - Organizational Diagrams and Security Ownership of Beneficial
Owners - Pro Forma Organizational Diagram (Subject to Change)" regarding Atlas
Energy Resources, LLC. In this regard, the partnership agreement does permit the
managing general partner and its affiliates to:

     o    have business interests or activities that may conflict with the
          partnerships if they determine that the business opportunity either:

          o    cannot be pursued by the partnership because of insufficient
               funds; or

          o    it is not appropriate for the partnership under the existing
               circumstances;

     o    devote only so much of their time as is necessary to manage the
          affairs of each partnership, as determined by the managing general
          partner in its sole discretion;

     o    conduct business with the partnerships in a capacity other than as
          managing general partner or sponsor as described in Sections 4.01,
          4.02, 4.03, 4.04, 4.05 and 4.06 of the partnership agreement;

     o    manage multiple programs simultaneously; and

     o    be indemnified and held harmless as described below in "- Limitations
          on Managing General Partner Liability as Fiduciary."

The fiduciary duty owed by the managing general partner to the partnership is
analogous to the fiduciary duty owed by directors to a corporation and its
stockholders, which is commonly referred to as the "business judgment rule."
This rule provides that directors are not liable for mistakes made in the good
faith exercise of honest business judgment or for losses incurred in the good
faith performance of their duties when performed with such care as an ordinarily
prudent person would use.

If the managing general partner breaches its fiduciary responsibilities, then
you are entitled to an accounting and the recovery of any economic loss caused
by the breach. The Delaware Revised Uniform Limited Partnership Act provides
that a limited partner may institute legal action (a "derivative" action) on a
partnership's behalf to recover damages from a third-party when the managing
general partner refuses to institute the action or where an effort to cause the
managing general partner to do so is not likely to succeed. In addition, the
statutory or case law may permit a limited partner to institute legal action on
behalf of himself and all other similarly situated limited partners (a "class
action") to recover damages from the managing general partner for violations of
its fiduciary duties to the limited partners. This is a rapidly expanding and
changing area of the law, and if you have questions concerning the managing
general partner's duties you are urged to consult your own counsel.


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LIMITATIONS ON MANAGING GENERAL PARTNER LIABILITY AS FIDUCIARY

Under the terms of the partnership agreement the managing general partner, the
operator, and their affiliates have limited their liability to each partnership
and to you and the other investors for any loss suffered by your partnership or
you and the other investors in the partnership which arises out of any action or
inaction on their part if:

     o    they determined in good faith that the course of conduct was in the
          best interest of the partnership;

     o    they were acting on behalf of, or performing services for, the
          partnership; and

     o    their course of conduct did not constitute negligence or misconduct.

In addition, the partnership agreement provides for indemnification of the
managing general partner, the operator, and their affiliates by each partnership
against any losses, judgments, liabilities, expenses, and amounts paid in
settlement of any claims sustained by them in connection with that partnership
provided that they meet the standards set forth above. However, there is a more
restrictive standard for indemnification for losses arising from or out of an
alleged violation of federal or state securities laws. Also, to the extent that
any indemnification provision in the partnership agreement purports to include
indemnification for liabilities arising under the Securities Act of 1933, as
amended, you should be aware that in the SEC's opinion this indemnification
provision would be contrary to public policy and therefore unenforceable.

Payments to the managing general partner or its affiliates arising from the
indemnification or agreement to hold harmless provisions of the partnership
agreement are recoverable only out of the partnership's tangible net assets,
which include its revenues and any insurance proceeds from the types of
insurance for which the managing general partner, the operator and their
affiliates may be indemnified under the partnership agreement. Still, the use of
partnership funds or assets to indemnify the managing general partner, the
operator, or an affiliate would reduce amounts available for partnership
operations or for distribution to you and the other investors.

A partnership may not pay the cost of the portion of any insurance that insures
the managing general partner, the operator, or an affiliate against any
liability for which they cannot be indemnified. However, a partnership's funds
can be advanced to them for legal expenses and other costs incurred in any legal
action for which indemnification is being sought if the partnership has adequate
funds available and certain conditions in the partnership agreement are met.

The effect of the foregoing provisions and the business judgment rule may be to
limit your recourse against the managing general partner.

                         FEDERAL INCOME TAX CONSEQUENCES

INTRODUCTION

Because no advance ruling on any federal tax issue of an investment in a
partnership will be requested from the IRS, the IRS could disagree with the tax
position taken by the partnerships. However, the managing general partner has
obtained a tax opinion letter from Kunzman & Bollinger, Inc., special counsel
for this offering, with respect to the material and any significant federal
income tax issues involving an investment in a partnership by a "typical
investor" as that term is defined in "- Managing General Partner's
Representations," below. You are urged to read the entire tax opinion letter,
which has been filed as Exhibit 8 to the registration statement of which this
prospectus is a part. (See "Additional Information," for information on how to
obtain a copy of special counsel's tax opinion letter.)

Although special counsel's tax opinions express what it believes a court would
probably conclude if presented with the applicable federal tax issues, special
counsel's tax opinions are only predictions, and are not guarantees, of the
outcome of the particular tax issues being addressed. The IRS could challenge
special counsel's tax opinions, and the challenge could be sustained in the
courts if litigated and cause adverse tax consequences to you and your
partnership's other investors. Special counsel's tax opinions are based in part
on representations and statements made by the managing general partner in the
tax opinion letter and in this prospectus, including forward looking statements
relating to the partnership and its proposed activities. (See "Forward Looking
Statements and Associated Risks.")


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DISCLOSURES IN TAX OPINION LETTER

The following disclosures are made in special counsel's tax opinion letter.

     o    THE TAX OPINION LETTER WAS WRITTEN TO SUPPORT THE PROMOTION OR
          MARKETING OF UNITS IN THE PARTNERSHIPS TO POTENTIAL INVESTORS, AND
          SPECIAL COUNSEL TO THE PARTNERSHIPS HAS HELPED THE MANAGING GENERAL
          PARTNER ORGANIZE AND DOCUMENT THE OFFERING OF UNITS IN THE
          PARTNERSHIPS.

     o    THE TAX OPINION LETTER IS NOT CONFIDENTIAL. THERE ARE NO LIMITATIONS
          ON THE DISCLOSURE BY ANY POTENTIAL INVESTOR IN A PARTNERSHIP TO ANY
          OTHER PERSON OF THE TAX TREATMENT OR TAX STRUCTURE OF THE
          PARTNERSHIPS.

     o    INVESTORS IN A PARTNERSHIP HAVE NO CONTRACTUAL PROTECTION AGAINST THE
          POSSIBILITY THAT A PORTION OR ALL OF THEIR INTENDED TAX BENEFITS FROM
          AN INVESTMENT IN THE PARTNERSHIP ULTIMATELY ARE NOT SUSTAINED IF
          CHALLENGED BY THE IRS. (SEE "RISK FACTORS - TAX RISKS - YOUR TAX
          BENEFITS FROM AN INVESTMENT IN A PARTNERSHIP ARE NOT CONTRACTUALLY
          PROTECTED.")

     o    EACH POTENTIAL INVESTOR IN A PARTNERSHIP IS URGED TO SEEK ADVICE BASED
          ON HIS PARTICULAR CIRCUMSTANCES FROM AN INDEPENDENT TAX ADVISOR WITH
          RESPECT TO THE FEDERAL TAX CONSEQUENCES TO HIM OF AN INVESTMENT IN A
          PARTNERSHIP.

SPECIAL COUNSEL'S ASSUMPTIONS

Set forth below is a synopsis of the principal assumptions made by special
counsel in giving its federal income tax opinions.

     o    You will not borrow money to buy units in a partnership from any other
          investor in the partnership.

     o    You will be personally liable to repay any money you borrow to buy
          units in a partnership.

     o    You will not protect yourself through nonrecourse financing,
          guarantees, stop loss agreements or other similar arrangements from
          losing the money you invest in a partnership.

MANAGING GENERAL PARTNER'S REPRESENTATIONS

In giving its opinions, special counsel relied in part on representations from
the managing general partner set forth in the tax opinion letter, including the
principal representations summarized below.

     o    A "typical investor" in each partnership will be a natural person who
          purchases units in this offering and is a U.S. citizen.

     o    The investor general partner units in each partnership will be
          converted by the managing general partner to limited partner units
          after all of the wells in that partnership have been drilled and
          completed. (See "Actions to be Taken by Managing General Partner to
          Reduce Risks of Additional Payments by Investor General Partners."

     o    Each partnership will elect to currently deduct all of the intangible
          drilling costs of all of its wells.

     o    The managing general partner anticipates that all of each
          partnership's subscription proceeds will be expended in 2007, and you
          will include your share of your partnership's deduction for intangible
          drilling costs on your individual federal income tax return for 2007,
          subject to your right to elect to capitalize and amortize over a
          60-month period a portion or all of your share of your partnership's
          deduction for intangible drilling costs.


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     o    Each partnership may have its final closing as late in the year as
          December 31, 2007. Thus, depending primarily on when its subscription
          proceeds are received, each partnership may prepay in 2007 most, if
          not all, of its intangible drilling costs for wells the drilling of
          which will not begin until 2008.

     o    Each partnership will have a calendar year taxable year.

     o    The managing general partner anticipates that most, if not all, of
          each partnership's natural gas and oil production from its productive
          wells will be marginal production that will qualify for the
          potentially higher rates of percentage depletion and potentially
          available marginal well production credits depending primarily on the
          applicable reference prices for natural gas and oil, which may vary
          from year to year.

     o    The principal purpose of each partnership is to locate, produce and
          market natural gas and oil on a profitable basis to its investors,
          apart from tax benefits, as discussed in this prospectus.

     o    Each partnership's total abandonment losses under Section 165 of the
          Code, which could include, for example, abandonment losses incurred by
          a partnership for wells drilled which are nonproductive (i.e. a "dry
          hole"), and abandonment losses incurred by a partnership for
          productive wells which have been operated until their commercial
          natural gas and oil reserves have been depleted, will be less than $2
          million, in the aggregate, in any taxable year of each partnership and
          less than $4 million, in the aggregate, during each partnership's
          first six taxable years.

Additional details, assumptions of special counsel, representations of the
managing general partner, and other matters affecting special counsel's opinions
are contained in special counsel's tax opinion letter. You are urged to read the
entire tax opinion letter, which is attached as Exhibit 8 to the Registration
Statement of which this prospectus is a part, to assist your understanding of
the federal tax benefits and risks of an investment in a partnership.

SPECIAL COUNSEL'S OPINIONS

Taxpayers bear the burden of proof to support claimed deductions and tax
credits, and special counsel's tax opinions are not binding on the IRS or the
courts. Special counsel's tax opinions with respect to an investment in a
partnership by a typical investor, who is sometimes referred to in special
counsel's opinions as a "Participant," "Investor General Partner" or "Limited
Partner," are set forth below.

     (1)  PARTNERSHIP CLASSIFICATION. Each Partnership will be classified as a
          partnership for federal income tax purposes, and not as a corporation.

     (2)  LIMITATIONS ON PASSIVE ACTIVITY LOSSES AND CREDITS. The passive
          activity limitations on losses and credits under Section 469 of the
          Code will apply to:

          o    the initial Limited Partners in a Partnership; and

          o    will not apply to the Investor General Partners in a Partnership
               until after their Investor General Partner Units are converted to
               Limited Partner Units.

     (3)  NOT A PUBLICLY TRADED PARTNERSHIP. Neither Partnership will be treated
          as a publicly traded partnership under the Code.

     (4)  BUSINESS EXPENSES. Business expenses, including payments for personal
          services actually rendered in the taxable year in which accrued by a
          Partnership, which are reasonable, ordinary and necessary and do not
          include amounts for items such as Lease acquisition costs, Tangible
          Costs, Organization and Offering Costs and other items that are
          required to be capitalized under the Code, are currently deductible by
          each Partnership.


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     o    POTENTIAL LIMITATIONS ON DEDUCTIONS. A Participant's ability in any
          taxable year to use his share of these deductions of the Partnership
          in which he invests on his individual federal income tax returns may
          be reduced, eliminated or deferred by the following limitations:

          o    the Participant's personal tax situation, such as the amount of
               his regular taxable income, alternative minimum taxable income,
               losses, itemized deductions, personal exemptions, etc., which are
               not related to his investment in a Partnership;

          o    the amount of the Participant's adjusted basis in his Units at
               the end of the Partnership's taxable year;

          o    the amount of the Participant's "at risk" amount in the
               Partnership in which he invests at the end of the Partnership's
               taxable year; and

          o    the passive activity limitations on losses, and credits, if any,
               of the Partnership in which they invest in the case of Limited
               Partners (including Investor General Partners after their Units
               are converted to Limited Partner Units) who are natural persons
               or are entities that also are subject to the passive activity
               limitations on losses and credits under Section 469 of the Code.

(5)  INTANGIBLE DRILLING COSTS. Although each Partnership will elect to deduct
     currently all of its Intangible Drilling Costs, each Participant in a
     Partnership may still elect to capitalize and deduct all or part of his
     share of his Partnership's Intangible Drilling Costs (which do not include
     drilling and completion costs of a re-entry well that are not related to
     deepening the well, if any) ratably over a 60-month period. Subject to the
     foregoing, Intangible Drilling Costs paid by a Partnership under the terms
     of bona fide drilling contracts for the Partnership's wells will be
     deductible by Participants in that Partnership who elect to currently
     deduct their share of their Partnership's Intangible Drilling Costs in the
     taxable year in which the payments are made and the drilling services are
     rendered.

     A Participant's ability in any taxable year to use his share of these
     Partnership deductions on his personal federal income tax returns may be
     reduced, eliminated or deferred by the "Potential Limitations on
     Deductions" set forth in opinion (4) above.

(6)  PREPAID INTANGIBLE DRILLING COSTS. Subject to each Participant's election
     to capitalize and amortize a portion or all of his share of his
     Partnership's Intangible Drilling Costs as set forth in opinion (5) above,
     any prepayments of Intangible Drilling Costs by a Partnership in 2007 for
     wells the drilling of which will begin after December 31, 2007, but on or
     before March 30, 2008, will be deductible by the Participants in 2007.

     A Participant's ability in any taxable year to use his share of these
     Partnership deductions on his personal federal income tax returns may be
     reduced, eliminated or deferred by the "Potential Limitations on
     Deductions" set forth in opinion (4) above.

(7)  DEPLETION ALLOWANCE. The greater of the cost depletion allowance or the
     percentage depletion allowance will be available to qualified Participants
     as a current deduction against their share of their Partnership's gross
     income from the sale of natural gas and oil production in each taxable
     year, subject to the following restrictions:

     o    a Participant's cost depletion allowance cannot exceed his adjusted
          tax basis in the natural gas or oil property to which it relates; and

     o    a Participant's percentage depletion allowance:


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          o    may not exceed 100% of his taxable income from each natural gas
               and oil property before the deduction for depletion; and

          o    is limited to 65% of his taxable income for the year computed
               without regard to percentage depletion, net operating loss
               carry-backs and capital loss carry-backs and, in the case of a
               Participant that is a trust, any distributions to its
               beneficiaries.

(8)  MACRS. Each Partnership's reasonable Tangible Costs for equipment placed in
     its productive wells that cannot be deducted immediately will be eligible
     for cost recovery deductions under the Modified Accelerated Cost Recovery
     System ("MACRS") over a seven year "cost recovery period" on a well-by-well
     basis, beginning in the taxable year each well is drilled, completed and
     made capable of production, i.e. placed in service.

     A Participant's ability in any taxable year to use his share of these
     Partnership deductions on his personal federal income tax returns may be
     reduced, eliminated or deferred by the "Potential Limitations on
     Deductions" set forth in opinion (4), above.

(9)  TAX BASIS OF UNITS. Each Participant's initial adjusted tax basis in his
     Units will be the amount of money that he paid for his Units.

(10) AT RISK LIMITATION ON LOSSES. Each Participant's initial "at risk" amount
     in the Partnership in which he invests will be the amount of money that he
     paid for his Units.

(11) ALLOCATIONS. The allocations of income, gain, loss, deduction, and credit,
     or items thereof, and distributions set forth in the Partnership Agreement
     for each Partnership, including the allocations of basis and amount
     realized with respect to a Partnership's natural gas and oil properties,
     will govern each Participant's allocable share of those items to the extent
     the allocations do not cause or increase a deficit balance in his Capital
     Account in the Partnership in which he invests.

(12) SUBSCRIPTION. No gain or loss will be recognized by the Participants on
     payment of their subscriptions to the Partnership in which they invest.

(13) PROFIT MOTIVE, IRS ANTI-ABUSE RULE AND POTENTIALLY RELEVANT JUDICIAL
     DOCTRINES. The Partnerships will possess the requisite profit motive under
     Section 183 of the Code. Also, the IRS anti-abuse rule in Treas. Reg.
     Section 1.701-2 and potentially relevant judicial doctrines will not have a
     material adverse effect on the tax consequences of an investment in a
     Partnership by a Participant as described in our opinions.

(14) REPORTABLE TRANSACTIONS. Neither Partnership is, nor should be in the
     future, a reportable transactions under Section 6707A(c) of the Code.

(15) OVERALL CONCLUSION. Special counsel's overall conclusion is that the
     federal tax treatment of a typical Participant's investment in a
     Partnership as set forth in its opinions above is the proper federal tax
     treatment and will be upheld on the merits if challenged by the IRS and
     litigated. Special counsel's evaluation of the federal income tax laws and
     the expected activities of the Partnerships as represented to it by the
     Managing General Partner in the tax opinion letter and as described in the
     Prospectus causes it to believe that the deduction by a typical Participant
     of all, or substantially all, of his allocable share of his Partnership's
     Intangible Drilling Costs in 2007 (even if the drilling of most or all of
     his Partnership's wells begins after December 31, 2007, but on or before
     March 30, 2008), as set forth in opinions (5) and (6) above, is the
     principal tax benefit offered by each Partnership to its potential
     Participants and also is the proper federal tax treatment, subject to each
     Participant's election to capitalize and amortize a portion or all of his
     share of his Partnership's deduction for Intangible Drilling Costs as
     discussed in "- Alternative Minimum Tax" in "Discussion of Federal Income
     Tax Consequences," below.


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          A Participant's ability in any taxable year to use his share of these
          Partnership deductions on his personal federal income tax returns may
          be reduced, eliminated or deferred by the "Potential Limitations on
          Deductions" set forth in opinion (4), above.

          The discussion in the Prospectus under the caption "FEDERAL INCOME TAX
          CONSEQUENCES," insofar as it contains statements of federal income tax
          law, is correct in all material respects.

                  DISCUSSION OF FEDERAL INCOME TAX CONSEQUENCES

INTRODUCTION

Special counsel's tax opinions are limited to those set forth above. The
following is a discussion of all material federal income tax issues or
consequences, and any significant federal tax issues, related to the purchase,
ownership and disposition of a partnership's units that will apply to typical
investors in each partnership. Except as otherwise noted below, however,
different tax consequences from those discussed below may apply to foreign
persons, corporations, partnerships, trusts and other prospective investors that
are not treated as typical investors for federal income tax purposes. Also, the
proper treatment of a partnership's tax attributes by a typical investor on his
individual federal income tax returns may vary from that of another typical
investor. This is because the practical utility of the tax aspects of any
investment depends largely on each investor's particular income tax position in
the year in which items of income, gain, loss, deduction, or credit, if any, are
properly taken into account in computing his federal income tax liability. In
addition, the IRS may challenge the deductions, and credits, if any, claimed by
a partnership or you and the other investors in a partnership, or the taxable
year in which the deductions, and credits, if any, are claimed, and it is
possible that the challenge would be upheld if litigated. Accordingly, you are
urged to seek advice based on your particular circumstances from an independent
tax advisor in evaluating the potential tax consequences to you of an investment
in a partnership.

PARTNERSHIP CLASSIFICATION

For federal income tax purposes a partnership is not a taxable entity. Thus, the
partners, rather than the partnership, receive and report any deductions and tax
credits, if any, as well as the income, from a partnership's operations. Each
partnership has been formed as a limited partnership under the Delaware Revised
Uniform Limited Partnership Act, which describes each partnership as a
"partnership." Thus, each partnership automatically will be classified as a
partnership for federal tax purposes since the managing general partner has
represented that neither partnership will elect to be taxed as a corporation.
Treas. Reg. Section 301.7701-2.

The managing general partner anticipates that all of the subscription proceeds
of each partnership will be expended in 2007, and the related income, if any,
and deductions, including the deduction for intangible drilling costs, will be
reflected on their respective investors' federal income tax returns for 2007,
subject to each investor's right to elect to capitalize and amortize over a
60-month period a portion or all of the investor's share of his partnership's
deduction for intangible drilling costs. See "Capitalization and Source of Funds
and Use of Proceeds" and "Participation in Costs and Revenues" and "- Intangible
Drilling Costs," "- Drilling Contracts," "- Depletion Allowance" and "-
Depreciation and Cost Recovery Deduction" and "- Alternative Minimum Tax,"
below.).

LIMITATIONS ON PASSIVE ACTIVITY LOSSES AND CREDITS

Under the passive activity rules of Section 469 of the Code, all income of a
taxpayer who is subject to the rules is categorized as:

     o    income from passive activities, such as limited partners' interests in
          a business;

     o    active income, such as salary, bonuses, etc.; or

     o    portfolio income, such as gain, interest, dividends and royalties
          unless earned in the ordinary course of a trade or business, and gain
          not derived in the ordinary course of a trade or business on the sale
          of property that generates portfolio income or is held for investment.


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Losses generated by passive activities can offset only passive income and cannot
be applied against active income or portfolio income. Similar rules apply with
respect to tax credits. (See "- Marginal Well Production Credits," below.)
Suspended passive losses and passive credits that an investor cannot use in his
current tax year may be carried forward indefinitely, but not back, and used to
offset future years' passive activity income, or offset passive activity regular
federal income tax liability (in the case of passive activity credits).

The passive activity rules apply to:

     o    individuals, estates, and trusts;

     o    closely held C corporations which under Sections 469(j)(1),
          465(a)(1)(B) and 542(a)(2) of the Code are regular corporations with
          five or fewer individuals who own directly or indirectly more than 50%
          in value of the outstanding stock at any time during the last half of
          the taxable year (for this purpose, U.S. trusts forming part of a
          stock bonus, pension or profit-sharing plan of an employer for the
          exclusive benefit of its employees or their beneficiaries that
          constitutes a "qualified trust" under Section 401(a) of the Code,
          trusts forming part of a plan providing for the payment of
          supplemental employee unemployment compensation benefits that meet the
          requirements of Section 501(c)(17) of the Code, domestic or foreign
          "private foundations" described in Section 501(c)(3) of the Code, and
          a portion of a trust permanently set aside or to be used exclusively
          for the charitable purposes described in Section 642(c) of the Code or
          a corresponding provision of a prior income tax law, are considered to
          be individuals); and

     o    personal service corporations, which under Sections 469(j)(2), 269A(b)
          and 318(a)(2)(C) of the Code are corporations the principal activity
          of which is the performance of personal services and those services
          are substantially performed by employee-owners. For this purpose, the
          term "employee-owners" includes any employee who owns, on any day
          during the taxable year, any of the outstanding stock of the personal
          service corporation, and an employee is considered to own:

          o    the employee's proportionate share of any stock of the personal
               service corporation owned, directly or indirectly, by or for a
               partnership or estate in which the employee is a partner or
               beneficiary;

          o    the employee's proportionate share of any stock of the personal
               service corporation owned, directly or indirectly, by or for a
               trust (other than an employee's trust that is a qualified
               pension, profit-sharing, or stock bonus plan and is exempt from
               the tax) if the employee is a beneficiary;

          o    all of the stock of the personal service corporation owned,
               directly or indirectly, by or for any portion of a trust of that
               the employee is considered the owner under the Code; and

          o    if any stock in a corporation is owned, directly or indirectly,
               for or by the employee, the employee's portionate share of the
               stock of the personal service corporation owned, directly or
               indirectly, by or for that corporation.

          Provided, however, that a corporation will not be treated as a
          personal service corporation for purposes of Section 469 of the Code
          unless more than 10% of the stock (by value) in the corporation is
          held by employee-owners (as described above). I.R.C. Section
          469(j)(2)(B).

However, if a closely held C corporation, other than a personal service
corporation in which employee-owners own more than 10% (by value) of the stock,
has net active income (i.e., taxable income determined without regard to any
income or loss from a passive activity and without regard to any item of
portfolio income, expense (including interest expense), or gain or loss) for a
taxable year, its passive loss for that taxable year can be applied against its
net active income for that taxable year. Similar rules apply to its passive
credits, if any. I.R.C. Section 469(e)(2).


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Passive activities include any trade or business in which the taxpayer does not
materially participate on a regular, continuous, and substantial basis. Under
the partnership agreement, limited partners will not have material participation
in the partnership in which they invest. Thus, if you are subject to the passive
activity rules as described above and you invest in a partnership as a limited
partner, your investment in the partnership will be subject to the passive
activity limitations on losses and credits. (See "Risk Factors - Tax Risks -
Limited Partners Need Passive Income to Use Their Deduction for Intangible
Drilling Costs.")

Investor general partners also will not materially participate in the
partnership in which they invest. However, because each partnership will own
only "working interests," as defined by the Code, in its wells, and investor
general partners will not have limited liability under the Delaware Revised
Uniform Limited Partnership Act until they are converted to limited partners,
their deductions and any credits from their partnership will not be treated as
passive deductions or credits under the Code before the conversion, unless they
invest in a partnership through an entity which limits their liability. For
example, if an individual invests in a partnership indirectly as an investor
general partner by using an entity that limits his personal liability under
state law to purchase his units, such as a limited partnership in which he is
not a general partner, a limited liability company or an S corporation, he will
be subject to the passive activity limitations on deductions and credits the
same as if he had invested in the partnership as a limited partner. (See "-
Conversion from Investor General Partner to Limited Partner" and "- Marginal
Well Production Credits," below.)

As compared with limitations on liability under state law as discussed above,
contractual limitations on the liability of investor general partners under the
partnership agreement, such as insurance, limited indemnification by the
managing general partner, etc. will not cause investor general partners to be
subject to the passive activity limitations on losses and credits. Investor
general partners, however, may be subject to an additional limitation on their
deduction of investment interest expense as a result of their non-passive
deduction of intangible drilling costs. (See "- Limitations on Deduction of
Investment Interest," below.)

A Limited Partner's "at risk" amount is reduced by losses allowed under Section
465 of the Code even if the losses are suspended by the passive activity
limitations. (See "- 'At Risk' Limitation on Losses," below.) Similarly, a
Limited Partner's basis is reduced by deductions even if the deductions are
suspended under the passive activity limitations. (See "- Tax Basis of Units,"
below.)

Suspended passive losses and passive credits that cannot be used by a taxpayer
in his current tax year may be carried forward indefinitely, but not back, and
can be used to offset passive income in future years or, in the case of passive
credits, can be used to offset regular federal income tax liability attributable
to passive income in future years. I.R.C. Section 469(b). A suspended passive
loss, but not a suspended passive credit, is allowed in full when a taxpayer's
entire interest in a passive activity is sold to an unrelated third-party in a
fully taxable transaction, and in part on the taxable disposition of
substantially all of a taxpayer's interest in a passive activity if the
suspended passive loss as well as current gross income and deductions of the
passive activity can be allocated to the part disposed of with reasonable
certainty. I.R.C. Section 469(g)(1). In an installment sale of a taxpayer's
entire interest in a passive activity, passive losses become available in the
same ratio that gain recognized each year bears to the total gain on the sale.
I.R.C. Section 469(g)(3). (See "Transferability of Units - Restrictions on
Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership
Agreement.")

Any suspended passive losses remaining at a taxpayer's death are allowed as
deductions on the decedent's final return, subject to a reduction to the extent
the amount of the suspended passive losses is greater than the excess of the
basis of the property in the hands of the transferee over the property's
adjusted basis immediately before the decedent's death. I.R.C. Section
469(g)(2). If a taxpayer makes a gift of his entire interest in a passive
activity, the basis in the property of the person receiving the gift is
increased by any suspended passive losses and no deductions are allowed. If the
interest is later sold at a loss, the basis in the property of the person
receiving the gift is limited to the fair market value of the property on the
date the gift was made. I.R.C. Section 469(j)(6).


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PUBLICLY TRADED PARTNERSHIP RULES

Net losses and most net credits of a partner from a publicly traded partnership
are suspended and carried forward to be netted against income or regular federal
income tax liability, respectively, from that publicly traded partnership only.
In addition, net losses from other passive activities may not be used to offset
net passive income from a publicly traded partnership. I.R.C. Sections 469(k)(2)
and 7704. A publicly traded partnership is a partnership in which interests in
the partnership are traded on an established securities market or are readily
tradable on either a secondary market or the substantial equivalent of a
secondary market. However, in special counsel's opinion neither of the
partnerships will be treated as a publicly traded partnership under the Code.
This opinion is based primarily on the substantial restrictions in the
partnership agreement on the ability of you and the other investors to transfer
your units in your partnership. (See "Transferability of Units - Restrictions on
Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership
Agreement.") Also, the managing general partner has represented that the
partnerships' respective units will be not traded on an established securities
market.

CONVERSION FROM INVESTOR GENERAL PARTNER TO LIMITED PARTNER

If you invest in a partnership as an investor general partner, then your share
of the partnership's deduction for intangible drilling costs in 2007 will not be
subject to the passive activity limitations on losses and credits. This is
because the investor general partner units in each partnership will not be
converted to limited partner units under Section 6.01(b)(1) of the partnership
agreement until after all of the wells in that partnership have been drilled and
completed. (See "Actions to be Taken by Managing General Partner to Reduce Risks
of Additional Payments by Investor General Partners," and "- Drilling
Contracts," below.) After the investor general partner units have been converted
to limited partner units, each former investor general partner will have limited
liability as a limited partner under the Delaware Revised Uniform Limited
Partnership Act after the date of the conversion.

Concurrently, the former investor general partner will become subject to the
passive activity limitations on losses and credits as a limited partner.
However, the former investor general partner previously will have received a
non-passive loss as an investor general partner in 2007 as a result of his share
of his partnership's deduction for intangible drilling costs. Therefore, the
Code requires that his net income from the partnership's wells after his
conversion to a limited partner must continue to be characterized as non-passive
income that cannot be offset with passive losses. For a discussion of the effect
of this rule on an investor general partner's tax credits, if any, from his
partnership, see "- Marginal Well Production Credits," below. The conversion of
the investor general partner units into limited partner units should not have
any other adverse tax consequences on an investor general partner unless his
share, if any, of any partnership liabilities is reduced as a result of the
conversion. This is because a reduction in a partner's share of liabilities is
treated as a constructive distribution of cash to the partner, which reduces the
partner's basis in his partnership units and is taxable to the partner to the
extent it exceeds his basis in his units. (See "- Tax Basis of Units," below.)

TAXABLE YEAR AND METHOD OF ACCOUNTING

Each partnership will adopt a calendar year taxable year and will use the
accrual method of accounting for federal income tax purposes.

TAXABLE YEAR. Each partnership will have a calendar year taxable year. I.R.C.
Sections 706(a) and (b). The taxable year of the partnership in which you invest
is important to you because your share of the partnership's deductions, tax
credits, if any, income and other items of tax significance must be taken into
account on your personal federal income tax return for your taxable year within
or with which the partnership's taxable year ends.

METHOD OF ACCOUNTING. Each partnership will use the accrual method of accounting
for federal income tax purposes. I.R.C. Section 448(a). Under the accrual method
of accounting, income is taken into account for the year in which all events
have occurred that fix the right to receive it and the amount is determinable
with reasonable accuracy, rather than the time of receipt. Consequently, you and
the other investors in the partnership in which you invest may have income tax
liability resulting from the partnership's accrual of income in one tax year
even though it does not receive the income in cash until the next tax year.
Expenses are deducted for the year in which all events have occurred that
determine the fact of the liability, the amount is determinable with reasonable
accuracy and the economic performance test is satisfied. Under Section 461(h) of
the Code, if the


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liability of the taxpayer arises out of the providing of services or property to
the taxpayer by another person, economic performance occurs as the services or
property, respectively, are provided. If the liability of the taxpayer arises
out of the use of the property by the taxpayer, economic performance occurs as
the property is used.

A special rule in the Code, however, provides that there is economic performance
in the current taxable year with respect to amounts paid in that taxable year
for intangible drilling costs of drilling and completing a natural gas or oil
well so long as the drilling of the well begins before the close of the 90th day
after the close of the taxable year in which the payments were made. I.R.C.
Section 461(i). (See "- Drilling Contracts," below, for a discussion of the
federal income tax treatment of any prepaid intangible drilling costs by the
partnerships.)

BUSINESS EXPENSES

Ordinary and necessary business expenses, including reasonable compensation for
personal services actually rendered, are deductible in the year incurred. In
this regard, the managing general partner has represented that the amounts
payable by each partnership to it and its affiliates under the partnership
agreement and the drilling and operating agreement are reasonable and
competitive amounts that ordinarily would be paid for similar services in
similar transactions between persons having no affiliation and dealing with each
other "at arms" length in the proposed areas of the partnerships' operations.
(See Treas. Reg. Section 1.162-7(b)(3) and "Compensation" and "- Drilling
Contracts," below.) The fees paid to the managing general partner and its
affiliates by the partnerships will not be currently deductible, however, to the
extent it is determined by the IRS or the courts that they are:

     o    in excess of reasonable compensation;

     o    properly characterized as organization or syndication fees or other
          capital costs, such as lease acquisition costs or equipment costs
          (i.e., "Tangible Costs"); or

     o    not "ordinary and necessary" business expenses.

In the event of an IRS audit of a partnership, payments to the managing general
partner and its affiliates by the partnership would be scrutinized by the IRS to
a greater extent than payments to an unrelated party.

Your ability in any taxable year to use your share of these partnership
deductions on your personal federal income tax returns may be reduced,
eliminated or deferred by the "Potential Limitations on Deductions" set forth in
special counsel's opinion (4) in "Special Counsel's Opinions," above.

Although the partnerships will engage in the production of natural gas and oil
from wells drilled in the United States, the partnerships will not qualify for
the "U.S. production activities deduction." This is because the deduction cannot
exceed 50% of the IRS Form W-2 wages paid by a taxpayer for a tax year, and the
partnerships will not pay any Form W-2 wages since they will not have any
employees. Instead, the partnerships will rely on the managing general partner
and its affiliates to manage them and their respective businesses. (See
"Management.")

INTANGIBLE DRILLING COSTS

You may elect to deduct your share of your partnership's intangible drilling
costs, which include items that do not have salvage value, such as labor, fuel,
repairs, supplies and hauling necessary to the drilling of a well and preparing
it for the production of natural gas or oil, in the taxable year in which your
partnership's wells are drilled and completed. I.R.C. Section 263(c), Treas.
Reg. Section 1.612-4(a). For a discussion of the deduction of intangible
drilling costs that are prepaid by your partnership in 2007 for wells the
drilling of which will not begin until 2008, if any, see "- Drilling Contracts,"
below.

Your share of your partnership's gain (if a partnership well is sold at a gain),
or your gain (if your units are sold at a gain), will be treated as ordinary
income, rather than capital gain, to the extent of the previous deductions for
intangible drilling costs you have claimed, but not for the deductions for
operating expenses related to a re-entry well, if any. (See "- Sale of the
Properties" and "- Disposition of Units," below.) Also, productive-well
intangible drilling costs may subject you to an


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alternative minimum tax in excess of regular tax unless you elect to deduct all
or part of these costs ratably over a 60 month period. (See "- Alternative
Minimum Tax," below.)

Under the partnership agreement, 90% of the subscription proceeds received by
each partnership from its respective investors will be used to pay 100% of the
partnership's intangible drilling costs of drilling and completing its wells.
(See "Application of Proceeds" and "Participation in Costs and Revenues.") The
IRS could challenge the characterization of a portion of these costs as
currently deductible intangible drilling costs and recharacterize the costs as
some other item that may not be currently deductible, such as lease acquisition
expenses, equipment costs or syndication fees. However, this would have no
effect on the allocation and payment of the intangible drilling costs by you and
the other investors under the partnership agreement.

Also, if a partnership re-enters an existing well as described in "Proposed
Activities - Primary Areas of Operations - Mississippian/Upper Devonian
Sandstone Reservoirs, Fayette County, Pennsylvania," the costs of deepening the
well and completing it to deeper reservoirs, if any, other than equipment costs
and lease acquisition costs, will be treated under the Code as intangible
drilling costs. The remaining intangible drilling costs of drilling and
completing a re-entry well that are not related to deepening the well, if any,
however, will be treated under the Code as operating expenses that should be
expensed in the taxable year they are incurred for federal income tax purposes.
Any intangible drilling costs of a re-entry well that are treated as operating
expenses for federal income tax purposes, however, will not be characterized as
operating costs, instead of intangible drilling costs, for purposes of
allocating the payment of the costs between the managing general partner, on the
one hand, and you and the other investors, on the other hand. In addition, under
the Code costs related to a re-entry well that are characterized as operating
costs under the Code cannot be amortized as intangible drilling costs over a
60-month period as described in "- Alternative Minimum Tax," below, even though
they may be characterized as intangible drilling costs for purposes of the
partnership agreement as discussed above. (See "Participation in Costs and
Revenues.")

In the case of corporations, other than S corporations, which are "integrated
oil companies," the amount allowable as a deduction for intangible drilling
costs in any taxable year is reduced by 30%. I.R.C. Section 291(b)(1).
Integrated oil companies are:

     o    those taxpayers who directly or through a related person engage in the
          retail sale of natural gas and oil and whose gross receipts for the
          taxable year from those activities exceed $5 million; or

     o    those taxpayers and related persons who have average daily refinery
          runs in excess of 75,000 barrels for the taxable year. I.R.C.
          Section 291(b)(4).

Amounts of an integrated oil company's intangible drilling costs that are
disallowed as a current deduction under Section 291 of the Code are allowable,
however, as a deduction ratably over the 60-month period beginning with the
month in which the costs are paid or incurred. Neither partnership will be an
integrated oil company.

Your ability in any taxable year to use your share of these partnership
deductions on your personal federal income tax returns may be reduced,
eliminated or deferred by the "Potential Limitations on Deductions" set forth in
special counsel's opinion (4) in "Special Counsel's Opinions," above.

You are urged to seek advice based on your particular circumstances from an
independent tax advisor concerning the tax benefits to you of your share of the
deduction for intangible drilling costs of the partnership in which you invest.

DRILLING CONTRACTS

Each partnership will enter into the drilling and operating agreement with the
managing general partner to drill and complete the partnership's wells for an
amount equal to the sum of the following items: (i) the cost of permits,
supplies, materials, equipment, and all other items used in the drilling and
completion of a well provided by third-parties, or if the foregoing items are
provided by affiliates of the managing general partner, then those items will be
charged at competitive rates; (ii) fees for third-party services; (iii) fees for
services provided by the managing general partner's affiliates, which will be
charged at competitive rates; (iv) an administration and oversight fee of
$15,000 per well, which will be charged to you and the other investors as part
of each well's intangible drilling costs and the portion of equipment costs paid
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investors; and (v) a mark-up in an amount equal to 15% of the sum of (i), (ii),
(iii) and (iv), above, for the managing general partner's services as general
drilling contractor. The managing general partner anticipates that, on average
over all of the wells that are drilled and completed by each partnership,
assuming a 100% working interest in each well, its mark-up of 15% will be
approximately $42,254 per well with respect to the intangible drilling costs and
the portion of equipment costs paid by you and the other investors in your
partnership as described in "Compensation - Drilling Contracts." However, the
actual cost of drilling and completing the wells may be more or less than the
amounts estimated by the managing general partner, due primarily to the
uncertain nature of drilling operations. Therefore, the managing general
partner's 15% mark-up discussed above also could be more or less than the dollar
amount estimated by the managing general partner as set forth above. The
managing general partner believes that the compensation payable to it and its
affiliates under the drilling and operating agreement is competitive in the
proposed areas of operation. Nevertheless, the amount of fees and profit
realized by the managing general partner under the drilling and operating
agreement could be challenged by the IRS as being unreasonable and disallowed as
a deductible intangible drilling cost.

Depending primarily on when their respective subscription proceeds are received,
the managing general partner anticipates that each partnership may prepay in
2007 most, if not all, of its intangible drilling costs for wells the drilling
of which will begin in 2008. In Keller v. Commissioner, 79 T.C. 7 (1982), aff'd
725 F.2d 1173 (8th Cir. 1984), the Tax Court applied a two-part test for the
current deductibility of prepaid intangible drilling and development costs. The
test is:

     o    the expenditure must be a payment rather than a refundable deposit;
          and

     o    the deduction must not result in a material distortion of income
          taking into substantial consideration the business purpose aspects of
          the transaction.

The drilling partnership in Keller entered into footage and daywork drilling
contracts that permitted it to terminate the contracts at any time, without a
default by the driller, and receive a return of the prepaid amounts less amounts
earned by the driller. The Tax Court found that the right to receive, by
unilateral action, a refund of the prepayments on the footage and daywork
drilling contracts rendered the prepayments deposits instead of payments.
Therefore, the prepayments were held to be nondeductible in the year they were
paid to the extent they had not been earned by the driller. The Tax Court
further found that the drilling partnership failed to show a convincing business
purpose for the prepayments under the footage and daywork drilling contracts.

The drilling partnership in Keller also entered into turnkey drilling contracts
that permitted it to stop work under the contract at any time and apply the
unearned balance of the prepaid amounts to another well to be drilled on a
turnkey basis. The Tax Court found that these prepayments constituted "payments"
and not nondeductible deposits, despite the right of substitution. Further, the
Tax Court noted that the turnkey drilling contracts obligated "the driller to
drill to the contract depth for a stated price regardless of the time, materials
or expenses required to drill the well," thereby locking in prices and shifting
the risks of drilling from the drilling partnership to the driller. Since the
drilling partnership, a cash basis taxpayer, received the benefit of the turnkey
obligation in the year of prepayment, the Tax Court found that the amounts
prepaid on turnkey drilling contracts clearly reflected income and were
deductible in the year of prepayment.

In Leonard T. Ruth, TC Memo 1983-586, a drilling program entered into nine
separate turnkey contracts with a general contractor, the parent corporation of
the drilling program's corporate general partner, to drill nine program wells.
Each contract identified the prospect to be drilled, stated the turnkey price,
and required the full price to be paid in 1974. The program paid the full
turnkey price to the general contractor on December 31, 1974; the receipt of
which was found by the court to be significant in the general contractor's
financial planning. The program had no right to receive a refund of any of the
payments. The actual drilling of the nine wells was subcontracted by the general
contractor to independent contractors who were paid by the general contractor in
accordance with their individual contracts. The drilling of all of the wells
began in 1975 and all of the wells were completed in 1975. The amount paid by
the general contractor to the independent driller for its work on the nine wells
was approximately $365,000 less than the amount prepaid by the program to the
general contractor. The program claimed a deduction for intangible drilling and
development costs in 1974. The IRS challenged the timing of the deduction,
contending that there was no business purpose for the payments in 1974, that the
turnkey arrangements were merely "contracts of convenience" designed to create a
tax deduction in 1974, and that the turnkey


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contracts constituted assets having a life beyond the taxable year and that to
allow a deduction for their entire costs in 1974 distorted income. The Tax
Court, relying on Keller, held that the program could deduct the full amount of
the payments in 1974. The court found that the program entered into turnkey
contracts, paid a premium to secure the turnkey obligations, and thereby locked
in the drilling price and shifted the risks of drilling to the general
contractor. Further, the court found that by signing and paying the turnkey
obligation, the program got its bargained-for benefit in 1974, therefore the
deduction of the payments in 1974 clearly reflected income.

Each partnership will attempt to comply with the guidelines set forth in Keller
with respect to any prepaid intangible drilling costs. In this regard, the
drilling and operating agreement will require each partnership to prepay in 2007
all of the partnership's share of the estimated intangible drilling costs, and
all of the investors' share of your partnership's share of the estimated
equipment costs, for drilling and completing specified wells for that
partnership, the drilling of which may begin in 2008. These prepayments of
intangible drilling costs should not result in a loss of a current deduction for
the intangible drilling costs in 2007 if:

     o    the guidelines set forth in Keller are complied with;

     o    there is a legitimate business purpose for the required prepayment;

     o    the drilling of the prepaid wells begins on or before March 30, 2008;

     o    the contract is not merely a sham to control the timing of the
          deduction; and

     o    there is an enforceable contract of economic substance.

In this regard, the drilling and operating agreement will require each
partnership to prepay the managing general partner's estimate of the intangible
drilling costs and the investor's share of the equipment costs to drill and
complete the wells specified in the drilling and operating agreement in order to
enable the operator to:

     o    begin site preparation for the wells;

     o    obtain suitable subcontractors at the then current prices; and

     o    insure the availability of equipment and materials.

Under the drilling and operating agreement excess prepaid intangible drilling
costs, if any, will not be refundable to a partnership, but instead will be
applied only to intangible drilling cost overruns, if any, on the other
specified wells being drilled or completed by the partnership or to intangible
drilling costs to be incurred by the partnership in drilling and completing
substitute wells. Under Keller, a provision for substitute wells should not
result in the prepayments being characterized as refundable deposits.

The likelihood that prepayments of intangible drilling costs will be challenged
by the IRS on the grounds that there is no business purpose for the prepayments
is increased if prepayments are not required with respect to 100% of the working
interest in the well. In this regard, the managing general partner anticipates
that less than 100% of the working interest will be acquired by each partnership
in one or more of its wells, and prepayments of intangible drilling costs will
not be required of the other owners of working interests in those wells. In the
view of special counsel, however, a legitimate business purpose for the required
prepayments of intangible drilling costs by the partnerships may exist under the
guidelines set forth in Keller, even though prepayments are not required by the
drilling contractor with respect to a portion of the working interest in the
wells.

In addition, a current deduction for prepaid intangible drilling costs is
available only if the drilling of the wells begins before the close of the 90th
day after the close of the taxable year in which the prepayment was made. See
the discussion of Section 461(i) of the Code in "- Method of Accounting," above.
Therefore, under the drilling and operating agreement, the managing


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general partner, serving as operator and general drilling contractor, must begin
drilling the wells that are prepaid by the partnership in 2007, if any, no later
than March 30, 2008, which is before the close of the 90th day after the close
of the 2007 calendar taxable year of each partnership in which a partnership's
intangible drilling costs are prepaid. However, the drilling of any partnership
well may be delayed due to circumstances beyond the control of the managing
general partner and the drilling subcontractors. These circumstances include,
for example:

     o    the unavailability of drilling rigs;

     o    decisions of third-party operators to delay drilling the wells;

     o    poor weather conditions;

     o    inability to obtain drilling permits or access right to the drilling
          site; or

     o    title problems;

and the managing general partner will have no liability under the partnership
agreement or the drilling and operating agreement to either partnership or their
respective investors if these types of events (i.e., "force majeure") delay
beginning the drilling of any partnership prepaid well beyond the 90 day limit
imposed by Section 461(i) of the Code (i.e., March 30, 2008).

If the drilling of a prepaid partnership well does not begin within the 90 day
time constraint imposed by Section 461(i) of the Code (i.e., March 30, 2008),
deductions claimed by you and the other investors in that partnership for
prepaid intangible drilling costs for the well in 2007, would not be lost, but
those deductions would be deferred to 2008 when the well is actually drilled.

Your ability in any taxable year to use your share of these partnership
deductions on your personal federal income tax returns may be reduced,
eliminated or deferred by the "Potential Limitations on Deductions" set forth in
special counsel's opinion (4) in "Special Counsel's Opinions," above.

DEPLETION ALLOWANCE

Proceeds from the sale of each partnership's natural gas and oil production will
constitute ordinary income. A portion of that income will not be taxable under
the depletion allowance, which permits the deduction from gross income for
federal income tax purposes of either the percentage depletion allowance or the
cost depletion allowance, whichever is greater. I.R.C. Sections 611, 613 and
613A. Your share of your partnership's gain (if a partnership well is sold at a
gain), or your gain (if you sell your units at a gain), will be treated as
ordinary income rather than capital gain to the extent of your previous
deductions for depletion that reduced your adjusted basis in the property or
your units. (See "- Sale of the Properties" and "- Disposition of Units,"
below.)

Cost depletion for any year is determined by dividing the adjusted tax basis for
the property by the total units of natural gas or oil expected to be recoverable
from the property and then multiplying the resultant quotient by the number of
units actually sold during the year. Cost depletion cannot exceed the adjusted
tax basis of the property to which it relates.

Percentage depletion is available to taxpayers other than "integrated oil
companies," as that term is defined in "- Intangible Drilling Costs," above,
which does not include the partnerships. Your percentage depletion allowance is
based on your share of your partnership's gross production income from its
natural gas and oil properties. Under Section 613A(c) of the Code, percentage
depletion is available with respect to 6 million cubic feet of average daily
production of domestic natural gas or 1,000 barrels of average daily production
of domestic crude oil. However, taxpayers who have both natural gas and oil
production may allocate the production limitation between the production.

The rate of percentage depletion is 15%. However, percentage depletion for
marginal production increases 1%, up to a maximum increase of 10%, for each
whole dollar that the domestic wellhead price of crude oil for the immediately
preceding year is less than $20 per barrel without adjustment for inflation.
I.R.C. Section 613A(c)(6). The term "marginal production" includes natural gas
and oil produced from a domestic stripper well property, which is defined in
Section 613A(c)(6)(E) of the Code


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as any property that produces a daily average of 15 or less equivalent barrels
of oil, which is equivalent to 90 mcf of natural gas, per producing well on the
property in the calendar year. In this regard, the managing general partner has
represented that most, if not all, of the natural gas and oil production from
each partnership's productive wells will be marginal production under this
definition in the Code. Therefore, most, if not all, of each partnership's gross
income from the sale of its natural gas and oil production will qualify for
these potentially higher rates of percentage depletion. The rate of percentage
depletion for marginal production in 2007 is 15%. This rate may fluctuate from
year to year depending on the price of oil, but will not be less than the
statutory rate of 15% nor more than 25%.

Also, percentage depletion:

     o    may not exceed 100% of the taxable income from each natural gas and
          oil property before the deduction for depletion, (this limitation was
          suspended in 2005 with respect to marginal properties, which the
          managing general partner has represented will include most, if not
          all, of each partnership's wells, but as of the date of this
          prospectus this limitation had not been suspended for 2007 and it may
          never be suspended for 2007 or subsequent taxable years); and

     o    is limited to 65% of the taxpayer's taxable income for the year
          computed without regard to percentage depletion, net operating loss
          carry-backs and capital loss carry-backs and, in the case of an
          investor that is a trust, any distributions to its beneficiaries. Any
          disallowed percentage depletion deductions under this limitation may
          be carried forward to the next taxable year.

The availability in any taxable year of the percentage depletion allowance must
be computed separately by you and not by your partnership or for investors in
your partnership as a whole. You are urged to seek advice based on your
particular circumstances from an independent tax advisor with respect to the
availability of the percentage depletion allowance to you.

DEPRECIATION AND COST RECOVERY DEDUCTIONS

Ten percent of each partnership's subscription proceeds from you and the other
investors will be used to pay equipment costs (i.e. "Tangible Costs"), and the
managing general partner will pay all of the partnership's remaining equipment
costs of drilling and completing its wells. The related depreciation deductions,
i.e., cost recovery deductions under the modified accelerated cost recovery
system ("MACRS"), will be allocated under the partnership agreement between the
managing general partner, on the one hand, and you and the other investors in
each partnership, on the other hand, in proportion to the actual amount of the
partnership's equipment costs paid by each.

A partnership's reasonable Tangible Costs for equipment placed in its wells that
cannot be deducted immediately will be recovered through depreciation deductions
over a seven year cost recovery period, using the 200% declining balance method
with a switch to straight-line to maximize the deduction, beginning in the
taxable year in which each well is drilled, completed and made capable of
production, (i.e., "placed in service") by the partnership. I.R.C. Section
168(c). In this regard, the managing general partner anticipates that each
partnership will have all of its wells drilled, completed and placed in service
for the production of natural gas or oil approximately eight to 12 months after
that partnership's final closing. In the case of a short partnership tax year,
the MACRS deduction will be prorated on a 12-month basis. No distinction is made
between new and used property and salvage value is disregarded. Under Section
168(d)(1) of the Code, all property assigned to the 7-year class is treated as
placed in service, or disposed of, in the middle of the year, unless more than
40% of the total cost of all equipment in a partnership's wells placed in
service during the year is placed in service during the last three months of the
year. If that happens, then under Section 168(d)(3) of the Code the depreciation
for the full year will be multiplied by a fraction based on the quarter the
equipment is placed in service: 87.5% for the first quarter, 62.5% for the
second, 37.5% for the third, and 12.5% for the fourth. All of these cost
recovery deductions claimed by a partnership and you and the other investors in
that partnership are subject to recapture as ordinary income rather than capital
gain on the sale or other taxable disposition of the property by the partnership
or your units by you. (See "- Sale of the Properties" and "- Disposition of
Units," below.) Depreciation for alternative minimum tax purposes is computed
using the 150% declining balance method switching to straight-line, for most
personal property. This will result in adjustments in computing the alternative
minimum taxable income of you and the other investors in a partnership in
taxable years in which the partnership claims depreciation deductions. (See "-
Alternative Minimum Tax," below.)


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Your ability in any taxable year to use your share of these partnership
deductions on your personal federal income tax returns may be reduced,
eliminated or deferred by the "Potential Limitations on Deductions" set forth in
special counsel's opinion (4) in "Special Counsel's Opinions," above.

MARGINAL WELL PRODUCTION CREDITS

There is a marginal well production credit of 50(cent) per mcf of qualified
natural gas production and $3 per barrel of qualified oil production for
purposes of the regular federal income tax. A tax credit, unlike a tax
deduction, reduces tax liability on a dollar-for-dollar basis. This credit is
part of the general business credit under Section 38 of the Code, but under
current law this credit cannot be used against the alternative minimum tax. (See
"- Alternative Minimum Tax," below.) Natural gas and oil production that
qualifies as marginal production under the percentage depletion rules of Section
613A(c)(6) of the Code as discussed above in "- Depletion Allowance," which the
managing general partner has represented will include most, if not all, of the
natural gas and oil production from each partnership's productive wells, is also
qualified marginal production for purposes of this credit. Also, the credit will
be reduced proportionately if the reference prices for the previous calendar
year are between $1.67 and $2.00 per mcf for natural gas and $15 and $18 per
barrel for oil. In this regard, the managing general partner anticipates that
neither of the partnership's natural gas and oil production in 2007, if any,
will qualify for this credit, because as of the date of this prospectus the
prices for natural gas and oil in 2006 were substantially above the $2.00 per
mcf of natural gas and $18.00 per barrel of oil prices where the credit phases
out completely.

Based on the prices for natural gas and oil in recent years compared with the
prices at which the credit phases out completely, it may appear unlikely that
either partnership's natural gas and oil production will ever qualify for this
credit. (See "Proposed Activities - Sale of Natural Gas Production - Policy of
Treating All Wells Equally in a Geographic Area.") However, prices for natural
gas and oil are volatile and could decrease in the future. (See "Risk Factors -
Risks Related To The Partnerships' Oil and Gas Operations - Partnership
Distributions May be Reduced if There is a Decrease in the Price of Natural Gas
and Oil.") Thus, it is possible that the partnerships' production of natural gas
or oil in one or more taxable years after 2007 could qualify for the marginal
well production credit, depending primarily on the applicable reference prices
for natural gas and oil in the future. However, depending primarily on market
prices for natural gas and oil, which are volatile, each partnership's
production of natural gas and oil may not qualify for marginal well production
credits for many years, if ever.

To the extent that your share of your partnership's marginal well production
credits, if any, exceeds your regular federal income tax owed on your share of
the partnership's taxable income, the excess credits, if any, can be used by you
to offset any other regular federal income taxes owed by you, on a
dollar-for-dollar basis, subject to the passive activity limitations if you
invest in a partnership as a limited partner. (See "- Limitations on Passive
Activity Losses and Credits," above.) Also, if you invest in a partnership as an
investor general partner, your share of your partnership's marginal well
production credits, if any, will be an active credit that may offset your
regular federal income tax liability on any type of income. However, after you
are converted to a limited partner in the partnership in which you invest, your
share of the partnership's marginal well production credits, if any, will be
active credits only to the extent of your regular federal income tax liability
that is allocable to your share of any net income of the partnership from the
sale of its natural gas and oil production, since your share of that net income
must continue to be treated by you as non-passive income even after you have
been converted to a limited partner. (See "- Conversion from Investor General
Partner to Limited Partner," above.) Any credits allocable to you as a converted
investor general partner in excess of that amount, as well as all of the
marginal well production credits allocable to those investors who originally
invest in the partnership as limited partners, will be passive credits that
under current law can reduce only your regular income tax liability attributable
to net passive income from the partnership in which you invest or your other
passive activities, if any, other than publicly traded partnership passive
activities.

LEASE ACQUISITION COSTS AND ABANDONMENT

Lease acquisition costs, together with the related cost depletion deduction, and
any amortization deductions for geological and geophysical expenses incurred by
the managing general partner after August 8, 2005, with respect to a
partnership's prospects and any abandonment loss for lease acquisition costs,
are allocated under the partnership agreement 100% to the managing general
partner, which will contribute the leases to each partnership as a part of its
capital contribution.


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TAX BASIS OF UNITS

Your share of your partnership's losses is allowable only to the extent of the
adjusted basis of your units at the end of your partnership's taxable year.
I.R.C. Section 704(d). The adjusted basis of your units will be adjusted, but
not below zero, for any gain or loss to you from a sale or other taxable
disposition by your partnership of a natural gas or oil property, and will be
increased by your:

     o    cash subscription payment;

     o    share of partnership income; and

     o    share, if any, of partnership debt.

The adjusted basis of your units will be reduced by your:

     o    share of partnership losses;

     o    share of partnership expenditures that are not deductible in computing
          its taxable income and are not properly chargeable to capital account;

     o    depletion deductions, but not below zero;

     o    cash distributions from the partnership; and

     o    any reduction in your share of your partnership's debt, if any. I.R.C.
          Sections 705, 722 and 742.

The reduction in your share of partnership liabilities, if any, is considered a
cash distribution to you. Although you will not be personally liable on any
partnership loans, if you invest in a partnership as an investor general partner
you will be liable for other obligations of the partnership. (See "Risk Factors
- Risks Related to an Investment In a Partnership - If You Choose to Invest as a
General Partner, Then You Have Greater Risk Than a Limited Partner.") Should
cash distributions to you from your partnership exceed the tax basis of your
units immediately before the distributions, taxable gain would result to you to
the extent of the excess. (See "- Distributions From a Partnership," below.)

"AT RISK" LIMITATION ON LOSSES

You may use your share of your partnership's losses to offset income from other
sources, to the extent that your use of those losses is not limited by the
adjusted tax basis of your units or the passive activity limitations on losses
and credits, but only to the extent of the amount you have "at risk" in the
partnership under Section 465 of the Code at the end of a taxable year. (See "-
Limitations on Passive Activity Losses and Credits" and "- Tax Basis of Units,"
above.) "Loss," for purposes of the "at risk" rules, means the excess of your
share of the allocable deductions for a taxable year from the partnership in
which you invest over the amount of income actually received or accrued by you
during the year from that partnership. This "at risk" limitation on your share
of your partnership's losses, however, does not apply to you if you are a
corporation that is neither an S corporation nor a corporation in which at any
time during the last half of the taxable year five or fewer individuals owned
more than 50% (in value) of the outstanding stock under Section 542(a)(2) of the
Code. (See "- Limitations on Passive Activity Losses and Credits," above,
relating to the application of Section 469 of the Code to closely held C
corporations for additional information on the stock ownership requirements
under Section 542(a)(2) of the Code.

Your initial "at risk" amount in the partnership in which you invest will be
equal to the amount of money you paid for your units. However, any amounts
borrowed by you to buy your units will not be considered "at risk" if the
amounts are borrowed from another investor in your partnership or anyone related
to another investor in your partnership. In this regard, the managing general
partner has represented that it and its affiliates will not make or arrange
financing for you or any other potential investors to use to purchase units in
the partnerships. Also, the amount you have "at risk" in your partnership will
not include the amount of any loss that you are protected against through:


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     o    nonrecourse loans;

     o    guarantees;

     o    stop loss agreements; or

     o    other similar arrangements.

The amount of any loss that exceeds your "at risk" amount in the partnership in
which you invest at the end of any taxable year must be carried forward by you
to the next taxable year, and will then be available to the extent you are "at
risk" in the partnership at the end of that taxable year. Further, your "at
risk" amount in subsequent taxable years of the partnership will be reduced by
any portion of a partnership loss that is allowable to you as a deduction.

Since income, gains, losses and distributions of the partnership in which you
invest will affect your "at risk" amount in the partnership, the extent to which
you are "at risk" in the partnership must be determined annually. Previously
allowed losses must be included in your gross income if your "at risk" amount is
reduced below zero. The amount included in your income, however, may be deducted
in the next taxable year to the extent of any increase in the amount that you
have "at risk" in your partnership.

DISTRIBUTIONS FROM A PARTNERSHIP

A cash distribution from your partnership to you in excess of the adjusted basis
of your units immediately before the distribution is treated as gain to you from
the sale or exchange of your units to the extent of the excess. I.R.C. Section
731(a)(1). Different rules apply, however, to payments by a partnership to a
deceased investor's successor in interest and to payments for an investor's
share of his partnership's unrealized receivables and inventory items as those
terms are defined in Section 751 of the Code. Under Section 731(a)(2) of the
Code, no loss can be recognized by you on these types of distributions, unless
the distribution is made to liquidate your units in your partnership and then
only to the extent of the excess, if any, of your adjusted basis in your units
over the sum of the amount of money distributed to you plus your share of the
basis (as determined under Section 732 of the Code) of any unrealized
receivables and inventory items of your partnership. (See "- Disposition of
Units," below, for a discussion of a partnership's unrealized receivables and
inventory items under Section 751 of the Code.)

No gain or loss will be recognized by the partnership in which you invest on
cash distributions to you and the other investors. I.R.C. Section 731(b). If
property is distributed by the partnership to the managing general partner and
you and the other investors in that partnership, basis adjustments to the
partnership's properties may be made by the partnership, and adjustments to the
basis in their respective interests in the partnership may be made by the
managing general partner and you and the other investors. I.R.C. Sections 732,
733, 734, and 754. (See Section 5.04(d) of the Partnership Agreement and "- Tax
Elections," below.) Other distributions of cash, disproportionate distributions
of property, if any, and liquidating distributions of the partnership may result
in taxable gain or loss to you and the other investors.

SALE OF THE PROPERTIES

The maximum tax rate on a noncorporate taxpayer's adjusted net capital gain on
the sale of most capital assets held more than a year is 15%, or 5% to the
extent the gain would have been taxed at a 10% or 15% rate if it had been
ordinary income, respectively, for most capital assets. In addition, for 2008
only, the 5% tax rate on adjusted net capital gain will be reduced to 0%. The
former maximum tax rates of 18% and 8%, respectively, on qualified five-year
gain have been eliminated. These capital gain rates also apply for purposes of
the alternative minimum tax. (See "- Alternative Minimum Tax," below.) However,
the former tax rates on adjusted net capital gain of 20% and 10%, respectively,
are scheduled to be reinstated on January 1, 2009.

Under Section 1(h)(3) of the Code, "adjusted net capital gain" means net capital
gain determined without taking qualified dividend income into account:

     o    reduced (but not below zero) by:


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          o    any amount of qualified dividend income taken into account as
               investment income under Section 163(d)(4)(B)(iii) of the Code;

          o    net capital gain that is taxed a maximum rate of 28% (such as
               gain on the sale of most collectibles and gain on the sale of
               qualified small business stock qualified under Section 1202 of
               the Code); and

          o    net capital gain that is taxed at a maximum rate of 25% (gain
               attributable to real estate depreciation); and

     o    increased by the amount of qualified dividend income.

"Net capital gain" means the excess of net long-term gain (the excess of
long-term gains over long-term losses) over net short-term loss (the excess of
short-term gains over short-term losses). The annual capital loss limitation for
noncorporate taxpayers is the amount of capital gains plus the lesser of $3,000,
which is reduced to $1,500 for married persons filing separate returns, or the
excess of capital losses over capital gains. I.R.C. Section 1211(b)

Gains from the sale by a partnership of a natural gas and oil property held by
it for more than 12 months will be treated as long-term capital gain, while a
net loss will be an ordinary deduction, except to the extent of depreciation
recapture on equipment and recapture of intangible drilling costs and depletion
deductions as discussed below. In addition, gain on the sale of the
partnership's natural gas and oil properties may be recaptured as ordinary
income to the extent of non-recaptured Section 1231 losses (as defined below)
for the five most recent preceding taxable years on previous sales, if any, of
the partnership's natural gas and oil properties or other assets. I.R.C. Section
1231(c). If, for any taxable year, the Section 1231 gains exceed the Section
1231 losses, the gains and losses will be treated as long-term capital gains or
long-term capital losses, as the case may be. If the Section 1231 gains do not
exceed the Section 1231 losses, the gains and losses will not be treated as
gains and losses from sales or exchanges of capital assets. For this purpose,
the term "Section 1231 gain" means any recognized gain:

     o    on the sale or exchange of a property used in a trade or business; and

     o    from the involuntary conversion into other property or money of:

          o    property used in a trade or business; or

          o    any capital assets that are held for more than one year and are
               held in connection with a trade or business or a transaction
               entered into for profit.

The term "Section 1231 loss" means any recognized loss from a sale or exchange
or conversion described above.

The term "property used in a trade or business" means depreciable property and
real property that are used in a trade or business and are held for more than
one year, which are not inventory and are not held primarily for sale to
customers in the ordinary course of a trade or business.

Net Section 1231 gain will be treated as ordinary income to the extent the gain
does not exceed the non-recaptured net Section 1231 losses. The term
"non-recaptured net Section 1231 losses" means the excess of:

     o    the aggregate amount of the net Section 1231 losses for the five most
          recent taxable years; over

     o    the portion of those losses taken into account to determine whether
          the net Section 1231 gain for any taxable year should be treated as
          ordinary income to the extent the gain does not exceed the
          non-recaptured net Section 1231 losses, as discussed above, for those
          preceding taxable years.

Other gains and losses on sales of natural gas and oil properties held by the
partnership for less than 12 months, if any, will result in ordinary gains or
losses.


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In addition, as discussed above deductions for intangible drilling costs and
depletion allowances that are incurred in connection with a natural gas or oil
property may be recaptured as ordinary income when the property is sold or
otherwise disposed of in a taxable transaction by the partnership. The amount of
gain recaptured as ordinary income is the lesser of:

     o    the aggregate amount of expenditures that have been deducted as
          intangible drilling costs with respect to the property and which, but
          for being deducted, would have been included in the adjusted basis of
          the property, plus deductions for depletion that reduced the adjusted
          basis of the property; or

     o    the excess of:

          o    the amount realized, in the case of a sale, exchange or
               involuntary conversion; or

          o    the fair market value of the interest, in the case of any other
               taxable disposition;

          over the adjusted basis of the property. I.R.C. Section 1254(a).

(See "- Intangible Drilling Costs" and "- Depletion Allowance," above.)

Also, all gain on the sale or other taxable disposition of equipment by the
partnership will be treated as ordinary income to the extent of MACRS deductions
previously claimed by the partnership. I.R.C. Section 1254(a). (See "-
Depreciation and Cost Recovery Deductions," above.)

DISPOSITION OF UNITS

The sale or exchange, including a purchase by the managing general partner, of
all or some of your units, if held by you as a capital asset for more than 12
months, will result in your recognition of long-term capital gain or loss,
except for your share of your partnership's "Section 751 assets" (i.e. inventory
items and unrealized receivables). "Unrealized receivables" includes any right
to payment for goods delivered, or to be delivered, to the extent the proceeds
would be treated as amounts received from the sale or exchange of non-capital
assets, services rendered or to be rendered, to the extent not previously
includable in income under your partnership's accounting methods, and deductions
previously claimed by you for depreciation, depletion and intangible drilling
costs with respect to the partnership in which you invest. "Inventory items"
includes property properly includable in inventory and property held primarily
for sale to customers in the ordinary course of business and any other property
that would produce ordinary income if sold, including accounts receivable for
goods and services. These tax items are sometimes referred to in this discussion
as "Section 751 assets." All of these tax items may be recaptured as ordinary
income rather than capital gain regardless of how long you have owned your
units. (See "- Sale of the Properties," above.)

If your units are held for 12 months or less, your gain or loss will be
short-term gain or loss. Also, your pro rata share of your partnership's
liabilities, if any, as of the date of the sale or exchange, must be included in
the amount realized by you. Thus, the gain recognized by you may result in a tax
liability to you greater than the cash proceeds, if any, received by you from
the disposition of your units. In addition to gain from a passive activity, a
portion of any gain recognized by a limited partner on the sale or other taxable
disposition of his units will be characterized as portfolio income under the
passive activity loss rules to the extent the gain is attributable to portfolio
income, e.g. interest income on investments of working capital. Treas. Reg.
Section 1.469-2T(e)(3). (See "- Limitations on Passive Activity Losses and
Credits," above.)

A gift of your units may result in federal and/or state income tax and gift tax
liability to you. Also, interests in different partnerships do not qualify for
tax-free like-kind exchanges. I.R.C. Section 1031(a)(2)(D). Other types of
dispositions of your units may or may not result in recognition of taxable gain.
However, no gain should be recognized by an investor general partner on the
conversion of his investor general partner units to limited partner units so
long as there is no change in his share of his partnership's liabilities or
Section 751 assets as a result of the conversion. Revenue Ruling 84-52, 1984-1
C.B. 157. In addition, if you sell or exchange all or some of your units you are
required by the Code to notify your partnership within 30 days or by January 15
of the following year, if earlier. The partnership will then report to the IRS
any information required by the IRS to be reported regarding the transfer of the
units, including your share of your partnership's Section 751 assets that are
subject to recapture as ordinary income as discussed above.


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If you die, or sell or exchange all of your units, the taxable year of your
partnership will close with respect to you, but not the remaining investors, on
the date of death, sale or exchange, and there will be a proration of
partnership items for the partnership's taxable year. If you sell less than all
of your units, the partnership's taxable year will not terminate with respect to
you, but your proportionate share of the partnership's items of income, gain,
loss, deduction and credit will be determined by taking into account your
varying interests in the partnership during the taxable year.

If you sell or exchange all or some of your units in the partnership in which
you invest, you are required under Section 6050K of the Code to notify the
partnership within 30 days or by January 15 of the following year, if earlier.
After receiving the notice, the partnership must file a return with the IRS
setting forth the name and address of both you, as the transferor, and the
transferee, the fair market value of the portion of the partnership's unrealized
receivables and appreciated inventory (i.e., Section 751 assets) allocable to
the units sold or exchanged by you (which is subject to recapture as ordinary
income instead of capital gain as discussed above) and any other information as
may be required by the IRS. The partnership also must provide each person whose
name is set forth in the return a written statement showing the information set
forth on the return.

You are urged to seek advice based on your particular circumstances from an
independent tax advisor before any sale or other disposition of your units,
including any purchase of your units by the managing general partner.

ALTERNATIVE MINIMUM TAX

With limited exceptions, under Section 55 of the Code you must pay an
alternative minimum tax if it exceeds your regular federal income tax for the
year. Alternative minimum taxable income ("AMTI") is regular federal taxable
income, plus or minus various adjustments, plus tax preference items. The tax
rate for noncorporate taxpayers is 26% for the first $175,000, $87,500 for
married individuals filing separately, of a taxpayer's AMTI in excess of the
applicable exemption amount (as set forth below); and additional AMTI is taxed
at 28%. However, the regular tax rates on capital gains also will apply for
purposes of the alternative minimum tax. (See "- Sale of the Properties,"
above.) Exemption amounts for alternative minimum tax purposes are different
from the regular tax personal exemptions, which are not allowed, and the types
and amounts of itemized deductions allowed for minimum tax purposes are more
limited than those allowed for regular tax purposes as discussed below.

For tax years beginning in 2006, the exemption amounts for individuals under the
Tax Increase Prevention Act were the following amounts:

     o    married individuals filing jointly and surviving spouses, $62,550,
          less 25% of AMTI exceeding $150,000 (zero exemption when AMTI is
          $400,200);

     o    unmarried individuals, $42,500, less 25% of AMTI exceeding $112,500
          (zero exemption when AMTI is $282,500); and

     o    married individuals filing separately, $31,275, less 25% of AMTI
          exceeding $75,000 (zero exemption when AMTI is $200,100). Also, AMTI
          of married individuals filing separately was increased by the lesser
          of $31,275 or 25% of the excess of AMTI (without regard to the
          exemption reduction) over $200,100.

Unless Congress takes further action, for tax years beginning in 2007 the
exemption amounts for individuals for alternative minimum tax purposes will be
reduced substantially from those set forth above as follows: $45,000 for married
individuals filing jointly and surviving spouses, $33,750 for single persons
other than surviving spouses, and $22,500 for married individuals filing
separately.

Code sections suspending losses, such as the rules concerning your "at risk"
amount in the partnership, the amount of your passive activity losses from the
partnership, and your basis in your units, are recomputed for alternative
minimum tax purposes, and the amounts of the deductions that are suspended, or
capital gains that are recaptured as ordinary income, may differ for regular
income tax and alternative minimum tax purposes. Due to the inherently factual
nature of these determinations and each investor's different tax situation,
special counsel is unable to express an opinion as to whether any investor will
incur, or increase, his alternative minimum tax liability because of an
investment in the partnership.


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As of the date of this prospectus, the 2006 exemption amounts and certain
adjustments to the AMTI of a noncorporate taxpayer that were available for 2006
had not been extended to 2007. Thus, you are urged to seek advice from an
independent tax advisor to determine whether changes to the alternative minimum
tax laws have been made after the date of this prospectus.

Some of the principal adjustments to taxable income that are used to determine
an individual's AMTI include those summarized below:

     o    Depreciation deductions of the costs of the equipment placed in
          service in the wells ("Tangible Costs") may not exceed deductions
          computed using the 150% declining balance method. These adjustments
          are discussed in greater detail below. (See "- Depreciation and Cost
          Recovery Deductions," above.)

     o    Miscellaneous itemized deductions are not allowed.

     o    Medical expenses are deductible only to the extent they exceed 10% of
          adjusted gross income.

     o    State and local property taxes and income taxes, which are itemized
          and deducted for regular tax purposes, are not deductible. (In 2005
          you could elect, instead, to itemize state and local sales taxes for
          regular federal income tax purposes, but as of the date of this
          prospectus this election had not been extended to 2007, thus, you are
          urged to seek advice from an independent tax advisor to determine
          whether this election was subsequently extended to 2007).

     o    Interest deductions are restricted.

     o    The standard deduction and personal exemptions are not allowed.

     o    Only some types of operating losses are deductible.

     o    Passive activity losses are computed differently.

     o    Earlier recognition of income from incentive stock options may be
          required.

The principal tax preference items that must be added to taxable income for
alternative minimum tax purposes include:

     o    excess intangible drilling costs, as discussed below; and

     o    tax-exempt interest earned on certain private activity bonds, less any
          deductions that would have been allowable if the interest were
          included in gross income for regular income tax purposes.

For taxpayers other than "integrated oil companies" as that term is defined in
"- Intangible Drilling Costs," above, which does not include the partnerships,
the 1992 National Energy Bill repealed:

     o    the preference for excess intangible drilling costs; and

     o    the excess percentage depletion preference for natural gas and oil.

The repeal of the excess intangible drilling costs preference, however, under
current law may not result in more than a 40% reduction in the amount of the
taxpayer's AMTI computed as if the excess intangible drilling costs preference
had not been repealed. I.R.C. Section 57(a)(2)(E). Under the prior rules, the
amount of intangible drilling costs that is not deductible for alternative
minimum tax purposes is the excess of the "excess intangible drilling costs"
over 65% of net income from natural gas and oil properties. Net natural gas and
oil income is determined for this purpose without subtracting excess intangible
drilling costs. Excess intangible drilling costs is the regular intangible
drilling costs deduction minus the amount that would


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have been deducted under 120-month straight-line amortization, or, at the
taxpayer's election, under the cost depletion method. There is no preference
item for costs of nonproductive wells.

Also, you may elect under Section 59(e) of the Code to capitalize all or part of
your share of your partnership's intangible drilling costs (which does not
include your share of the partnership's intangible drilling costs of a re-entry
well that are treated under the Code as operating costs, if any) and deduct the
costs ratably over a 60-month period beginning with the month in which the costs
were paid or incurred by the partnership. This election also applies for regular
tax purposes and can be revoked only with the IRS' consent. Making this
election, therefore, will include the following principal consequences to you:

     o    your regular federal income tax deduction for intangible drilling
          costs in 2007 will be reduced because you must spread the deduction
          for the amount of intangible drilling costs which you elect to
          capitalize over the 60-month amortization period; and

     o    the capitalized intangible drilling costs will not be treated as a
          preference that is included in your alternative minimum taxable
          income.

Other than intangible drilling costs as discussed above, and passive activity
losses and credits in the case of limited partners, the principal tax item that
may have an impact on your alternative minimum taxable income as a result of
investing in a partnership is depreciation of the partnership's equipment
expenses. (See "- Limitations on Passive Activity Losses and Credits," above.)
As noted in "- Depreciation and Cost Recovery Deductions," above, each
partnership's cost recovery deductions for regular income tax purposes will be
computed differently than for alternative minimum tax purposes. Consequently, in
the early years of the cost recovery period of your partnership's equipment, but
not in the later years, your depreciation deductions from the partnership will
be smaller for alternative minimum tax purposes than your depreciation
deductions for regular income tax purposes on the same equipment. This could
cause you to incur, or may increase, your alternative minimum tax liability in
those taxable years. Conversely, this adjustment may decrease your alternative
minimum taxable income in the later years of the cost recovery period. Also,
under current law, your share of your partnership's marginal well production
credits, if any, may not be used to reduce your alternative minimum tax
liability, if any. In addition, the rules relating to the alternative minimum
tax for corporations are different from those for individuals that are discussed
above.

All prospective investors contemplating purchasing units in a partnership are
urged to seek advice based on their particular circumstances from an independent
tax advisor as to the likelihood of them incurring or increasing any alternative
minimum tax liability as a result of an investment in a partnership.

LIMITATIONS ON DEDUCTION OF INVESTMENT INTEREST

Investment interest expense is deductible by a noncorporate taxpayer only to the
extent of net investment income each year, with an indefinite carryforward of
disallowed investment interest expense deductions to subsequent taxable years.
I.R.C. Section 163(d). An investor general partner's share of any interest
expense incurred by the partnership in which he invests before his investor
general partner units are converted to limited partner units will be subject to
the investment interest limitation. I.R.C. Section 163(d)(5)(A)(ii). In
addition, an investor general partner's share of the partnership's loss in 2007
as a result of the deduction for intangible drilling costs will reduce his net
investment income and may reduce or eliminate the deductibility of his
investment interest expenses, if any, in 2007, with the disallowed portion to be
carried forward to subsequent taxable years. This limitation on the deduction of
investment interest expenses, however, will not apply to any income or expenses
taken into account by limited partners in computing their income or loss from
the partnership as a passive activity under Section 469 of the Code. I.R.C.
Section 163(d)(4)(D). (See "- Limitations on Passive Activity Losses and
Credits," above.)

ALLOCATIONS

The partnership agreement allocates to you your share of your partnership's
income, gains, losses, deductions, and credits, if any, including the deductions
for intangible drilling costs and depreciation. Allocations under the
partnership agreement of some tax items are made in ratios that are different
from allocations of other tax items (i.e., "special allocations"). Your capital
account in the partnership in which you invest will be adjusted to reflect your
share of these allocations, and your capital account, as adjusted, will be given
effect by the partnership in making distributions to you on liquidation of the


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partnership or your units. Also, the basis of the natural gas and oil properties
owned by your partnership for purposes of computing cost depletion and gain or
loss on disposition of a property will be allocated and reallocated when
necessary in the ratio in which the expenditure giving rise to the tax basis of
each property was charged as of the end of the year. (See Section 5.03(b) of the
Partnership Agreement.)

Your capital account in the partnership in which you invest will be:

     o    increased by the amount of money you contribute to the partnership and
          allocations of partnership income and gain to you; and

     o    decreased by the value of property or cash distributed to you by the
          partnership and allocations of partnership losses and deductions to
          you.

Allocations made in a manner that is disproportionate to the respective
interests of the partners in a partnership of any item of partnership income,
gain, loss, deduction or credit will not be given effect unless the allocation
has "substantial economic effect." I.R.C. Section 704(b). Economic effect means
that if there is an economic benefit or burden that corresponds to an
allocation, the partner to whom the allocation is made must receive the economic
benefit or bear the economic burden. The economic effect of an allocation is
substantial if there is a reasonable possibility that the allocation will affect
substantially the dollar amounts to be received by the partners from the
partnership, independent of tax consequences and taking into account the
partners' tax attributes that are unrelated to the partnership. The allocations
under the partnership agreement will have economic effect if throughout the term
of the partnership in which you invest:

     o    the partners' capital accounts are increased and decreased as
          described above;

     o    liquidation proceeds are distributed in accordance with the partners'
          capital accounts; and

     o    any partner with a deficit balance in his capital account following
          the liquidation of his interest in the partnership is required to
          restore the amount of the deficit to the partnership.

Even though you and the other investors are not required under the partnership
agreement to restore any deficit balance in your capital accounts in your
partnership by making additional capital contributions to the partnership, an
allocation that is not attributable to nonrecourse debt or tax credits will
still be considered to have economic effect under the Treasury Regulations to
the extent it does not cause or increase a deficit balance in your capital
account if:

     o    the partners' capital accounts are increased and decreased as
          described above;

     o    the partnership's liquidation proceeds are distributed in accordance
          with the partners' capital accounts; and

     o    the partnership agreement provides that if you unexpectedly incur a
          deficit balance in your capital account because of certain
          adjustments, allocations, or distributions of the partnership, then
          you will be allocated an additional amount of partnership income and
          gain that is sufficient to eliminate the deficit balance as quickly as
          possible.

Treas. Reg. Section 1.704-1(b)(2)(ii)(d). These provisions are included in the
partnership agreement (See Sections 5.02, 5.03(h), and 7.02(a) of the
partnership agreement.)

Special provisions of the Treasury Regulations apply to deductions that are
related to nonrecourse debt and tax credits, since allocations of those tax
items cannot have substantial economic effect under the Treasury Regulations. If
the managing general partner or an affiliate makes a nonrecourse loan to the
partnership in which you invest (a "partner nonrecourse liability"), then that
partnership's losses, deductions, or Section 705(a)(2)(B) expenditures
attributable to the loan must be allocated to the managing general partner.
Also, if there is a net decrease in partner nonrecourse liability minimum gain
with respect to the loan, the managing general partner must be allocated income
and gain equal to the net decrease. (See Sections 5.03(a)(1) and


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5.03(i) of the partnership agreement.) In addition, any marginal well production
credits of the partnership will be allocated among the managing general partner
and you and the other investors in the partnership in accordance with each
partner's respective interest in the partnership's production revenues from the
sale or its natural gas and oil production. (See Section 5.03(g) of the
partnership agreement, "Participation in Costs and Revenues," and "- Marginal
Well Production Credits," above.)

If you sell or transfer your unit in the partnership in which you invest, or on
the death of an investor, or the admission of an additional partner, the
partnership's income, gain, loss, credits and deductions will be allocated among
its partners according to their varying interests in the partnership during the
taxable year. In addition, the Code may require the partnership's property to be
revalued on the admission of additional partners, if any, if disproportionate
distributions are made to the partners, or if there are "built-in" losses on the
transfer of a partner's units or any distribution of the partnership's property
to its partners. (See "- Tax Elections," below.)

It also should be noted that your share of items of income, gain, loss,
deduction, and credit, if any, in the partnership in which you invest must be
taken into account by you whether or not you receive any cash distributions from
the partnership. For example, your share of partnership revenues applied by your
partnership to the repayment of loans, if any, or the reserve for plugging
wells, will be included in your gross income in a manner analogous to an actual
distribution of the revenues (and income) to you. Thus, you may have tax
liability on taxable income from your partnership for a particular year in
excess of any cash distributions from the partnership to you with respect to
that year. To the extent a partnership has cash available for distribution,
however, it is the managing general partner's policy that partnership cash
distributions to you and the other investors in that partnership will not be
less than the managing general partner's estimate of the investors' income tax
liability (as a group) with respect to that partnership's income.

If any allocation under the partnership agreement is not recognized for federal
income tax purposes, your share of the items subject to the allocation will be
determined in accordance with your interest in the partnership in which you
invest by considering all of the relevant facts and circumstances. To the extent
deductions or credits allocated by the partnership agreement exceed deductions
or credits which would be allowed under a reallocation of those tax items by the
IRS, you may incur a greater tax burden.

PARTNERSHIP BORROWINGS

Under the partnership agreement, only the managing general partner and its
affiliates may make loans to the partnerships. The use of partnership revenues
taxable to you to repay borrowings by your partnership could create income tax
liability for you in excess of your cash distributions from the partnership,
since repayments of principal are not deductible for federal income tax
purposes. In addition, interest on the loans will not be deductible unless the
loans are bona fide loans that will not be treated by the IRS as capital
contributions to the partnership by the managing general partner or its
affiliates in light of all of the surrounding facts and circumstances. Also, the
"at risk" amounts of you and the other investors in the partnership in which you
invest, which limit the amount of partnership losses you and the other investors
can claim as discussed in "- 'At Risk' Limitation on Losses," above, will not be
increased by the amount of any partnership borrowings from the managing general
partner or its affiliates, because you and the other investors will not bear any
risk of repaying the borrowings from your non-partnership assets, even if you
invest in the partnership as an investor general partner.

PARTNERSHIP ORGANIZATION AND OFFERING COSTS

Expenses connected with the offer and sale of units in a partnership, such as
the dealer-manager fee, sales commissions, and other selling expenses,
professional fees, and printing costs, which are charged under the partnership
agreement 100% to the managing general partner as organization and offering
costs, are not deductible. Although expenses incident to the creation of a
partnership may be amortized over a period of not less than 180 months, these
expenses also will be paid by the managing general partner as part of each
partnership's organization costs. Thus, any related deductions, which the
managing general partner does not anticipate will be material in amount as
compared to the total amount of subscription proceeds of each partnership, will
be allocated under the partnership agreement to the managing general partner.

TAX ELECTIONS

Each partnership may elect to adjust the basis of its property (other than cash)
on the transfer of a unit in the partnership by sale or exchange or on the death
of an investor, and on the distribution of property (other than money) by the
partnership to


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an investor (the Section 754 election). If the Section 754 election is made, the
transferees of the units are treated, for purposes of depreciation and gain, as
though they had acquired a direct interest in the partnership assets and the
partnership is treated for these purposes, on distributions to the investors, as
though it had newly acquired an interest in the partnership assets and therefore
acquired a new cost basis for the assets. Any election, once made, may not be
revoked without the consent of the IRS.

In this regard, due to the complexities and added expense of the tax accounting
required to implement a Section 754 election to adjust the basis of a
partnership's property when units are sold, taking into account the limitations
on the sale of the partnership's units as described in "Transferability of
Units," the managing general partner anticipates that the partnerships will not
make the Section 754 election, although they reserve the right to do so. Even if
the partnerships do not make the Section 754 election, however, the basis
adjustment described above is mandatory under the Code with respect to the
transferee partner only, if at the time a unit is transferred by sale or
exchange, or on the death of an investor, a partnership's adjusted basis in its
property exceeds the fair market value of the property by more than $250,000
immediately after the transfer of the unit. Similarly, a basis adjustment is
mandatory under the Code if a partnership distributes property in-kind to a
partner and the sum of the partner's loss on the distribution and the basis
increase to the distributed property is more than $250,000. I.R.C. Sections 734
and 743. In this regard, under Section 7.02 of the partnership agreement, a
partnership will not distribute its assets in-kind to its investors except to a
liquidating trust or similar entity for the benefit of its investors on the
dissolution and termination of the partnership, unless at the time of the
distribution its investors have been offered the election of receiving in-kind
property distributions, and you or any other investor in that partnership
accepts the offer after being advised of the risks associated with direct
ownership; or there are alternative arrangements in place which assure that you
and the other investors in that partnership will not, at any time, be
responsible for the operation or disposition of the partnership's properties.

If the basis of a partnership's assets must be adjusted as discussed above, the
primary effect on the partnership, other than the federal income tax
consequences discussed above, would be an increase in its administrative and
accounting expenses to make the required basis adjustments to its properties and
separately account for those adjustments after they are made. In this regard,
the partnerships will not make in-kind property distributions to their
respective investors except in the limited circumstances described above, and
the units will have no readily available market and will be subject to
substantial restrictions on their transfer. (See "Transferability of Units -
Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the
Partnership Agreement.") These factors will tend to reduce the likelihood that a
partnership will be required to make mandatory basis adjustments to its
properties.

In addition to the Section 754 election, each partnership may make various
elections under the Code for federal tax reporting purposes that could result in
the deductions of intangible drilling costs and depreciation, and the depletion
allowance, being treated differently for tax purposes than for accounting
purposes. Also, under Section 195 of the Code "start-up expenditures" may be
capitalized and amortized over a 180-month period. The term "start-up
expenditure" for this purpose includes any amount:

     o    paid or incurred in connection with:

          o    investigating the creation or acquisition of an active trade or
               business;

          o    creating an active trade or business; or

          o    any activity engaged in for profit and for the production of
               income before the day on which the active trade or business
               begins, in anticipation of that activity becoming an active trade
               or business; and

     o    that would be allowable as a deduction if paid or incurred in
          connection with the expansion of an existing business.


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If it is ultimately determined by the IRS or the courts that any of a
partnership's expenses constituted start-up expenditures, that partnership's
deductions for those expenses, including your share, if any, of those deductions
under the partnership agreement would be amortized over the 180-month period.

TAX RETURNS AND IRS AUDITS

The tax treatment of most partnership items is determined at the partnership,
rather than the partner level. Accordingly, you are required to treat the
partnership's tax items of the partnership in which you invest on your
individual federal income tax returns in a manner that is consistent with the
treatment of the partnership items on the partnership's federal information
income tax returns, unless you disclose to the IRS, by attaching the required
IRS notice to your individual federal income tax return, that your tax treatment
of the partnership's tax items on your personal federal income tax returns is
different from their partnership's tax treatment of those partnership tax items.
I.R.C. Sections 6221 and 6222. Treasury Regulations define partnership tax items
for this purpose as including distributive share items that must be allocated
among the partners, such as partnership liabilities, data pertaining to the
computation of the depletion allowance, and guaranteed payments. Treas. Reg.
Section 301.6231(a)(3)-1.

In most cases, the IRS must make an administrative determination as to
partnership tax items at the partnership level before conducting deficiency
proceedings against a partner, and the partners must file a request for an IRS
administrative determination with respect to the partnership before filing suit
for any credit or refund. Also, the period for assessing tax against you and the
other investors because of a partnership tax item may be extended by agreement
between the IRS and the managing general partner, which will serve as each
partnership's representative ("Tax Matters Partner") in all administrative tax
proceedings and tax litigation, if any, conducted at the partnership level.

The Tax Matters Partner may enter into a settlement on behalf of, and binding
on, any investor owning less than a 1% profits interest in a partnership if
there are more than 100 partners in the partnership, unless that investor timely
files a statement with the Secretary of the Treasury providing that the Tax
Matters Partner does not have authority to enter into a settlement agreement on
behalf of that investor. Based on its past experience, the managing general
partner anticipates that there will be more than 100 investors in each
partnership in which units are offered for sale. However, by executing the
Subscription Agreement you also are executing the partnership agreement if your
Subscription Agreement is accepted by the managing general partner. Under the
partnership agreement, you and the other investors in that partnership agree
that you will not form or exercise any right as a member of a notice group and
will not file a statement notifying the IRS that the Tax Matters Partner does
not have binding settlement authority. In addition, a partnership with at least
100 partners may elect to be governed under simplified tax reporting and audit
rules as an "electing large partnership." However, most limitations affecting
the calculation of the taxable income and tax credits of an electing large
partnership are applied at the partnership level and not the partner level.
Thus, the managing general partner does not anticipate that the partnerships
will make this election, although they reserve the right to do so.

All expenses of any tax proceedings involving a partnership and the managing
general partner acting as Tax Matters Partner, which might be substantial, will
be paid for by the partnership and not by the managing general partner from its
own funds. The managing general partner, however, is not obligated to contest
any adjustments made by the IRS to a partnership's federal information income
tax returns, even if the adjustment also would affect the individual federal
income tax returns of you and the other investors in that partnership. The
managing general partner will notify you and the other investors in your
partnership of any IRS audits or other tax proceedings involving your
partnership, and will provide you and the other investors any other information
regarding the proceedings as may be required by the partnership agreement or
law.

TAX RETURNS. Your individual income tax returns are your responsibility. Each
partnership will provide its investors with the tax information applicable to
their investment in the partnership necessary to prepare their tax returns.

PROFIT MOTIVE, IRS ANTI-ABUSE RULE AND JUDICIAL DOCTRINES LIMITATIONS ON
DEDUCTIONS

Under Section 183 of the Code, your ability to deduct your share of your
partnership's deductions could be limited or lost if the partnership lacks the
appropriate profit motive as determined from an examination of all facts and
circumstances at the time. Section 183 of the Code creates a presumption that an
activity is engaged in for profit if, in any three of five consecutive taxable
years, the gross income derived from the activity exceeds the deductions
attributable to the activity. Thus, if your


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partnership fails to show a profit in at least three out of five consecutive
years this presumption will not be available and the possibility that the IRS
could successfully challenge the partnership deductions claimed by you would be
substantially increased. The fact that the possibility of ultimately obtaining
profits is uncertain, standing alone, does not appear under the Treasury
Regulations to be sufficient grounds for the denial of losses. Also, if a
principal purpose of a partnership is to reduce substantially the partners'
federal income tax liability in a manner that is inconsistent with the intent of
the partnership rules of the Code, based on all the facts and circumstances, the
IRS is authorized under Treasury Regulation Section 1.701-2 to remedy the abuse.
Finally, under potentially relevant judicial doctrines such as the step
transaction, business purpose, economic substance, substance over form, and sham
transaction doctrines, tax deductions and tax credits from a transaction,
including each partnership's deduction for intangible drilling costs in 2007,
would be disallowed if your partnership were found by the IRS or the courts, to
have no economic substance apart from the tax benefits.

With respect to these issues, special counsel has given its opinions that the
partnerships will possess the requisite profit motive, and the IRS anti-abuse
rule in Treas. Reg. Section 1.701-2 and the potentially relevant judicial
doctrines listed above will not have a material adverse effect on the tax
consequences of an investment in a partnership by a typical investor as
described in special counsel's opinions. These opinions are based in part on the
results of the previous partnerships sponsored by the managing general partner
as set forth in "Prior Activities" and the managing general partner's
representations to special counsel, which are set forth in its tax opinion
letter attached as Exhibit 8 to the Registration Statement of which this
prospectus is a part. The managing general partner's representations include
that each partnership will be operated as described in this prospectus (see
"Management" and "Proposed Activities") and the principal purpose of each
partnership is to locate, produce and market natural gas and oil on a profitable
basis to its investors, apart from tax benefits, as described in this
prospectus. Also, see the information concerning the partnerships' proposed
drilling areas in "Proposed Activities," and the geological evaluations and
other information for the specific prospects proposed to be drilled by Atlas
America Public #16-2007(A) L.P. included in Appendix A to this prospectus, which
represent a portion of the prospects to be drilled if that partnership's
targeted maximum subscription proceeds of $100 million are received (which is
not binding on the partnership) as described in "Terms of the Offering -
Subscription to a Partnership." Also, the managing general partner has
represented that Appendix A in this prospectus will be supplemented or amended
to cover a portion of the specific prospects proposed to be drilled by Atlas
America Public #16-2007(B) L.P. if units in that partnership are offered to
prospective investors.

FEDERAL INTEREST AND TAX PENALTIES

Taxpayers must pay tax and interest on underpayments of federal income taxes and
the Code contains various penalties, including penalties for negligence and
substantial valuation misstatements with respect to their individual federal
income tax returns. In addition, there is a penalty equal to 20% of the amount
of a substantial understatement of federal income tax liability. There is a
substantial understatement by a noncorporate taxpayer if the correct income tax,
as finally determined by the IRS or the courts, exceeds the income tax liability
shown on the taxpayer's federal income tax return by the greater of 10% of the
correct tax, or $5,000. In the case of a corporation, other than an S
corporation, or a personal holding company as defined in Section 542 of the
Code, an understatement is substantial if it exceeds the lesser of: (i) 10% of
the correct tax (or, if greater, $10,000); or (ii) $10 million). I.R.C. Section
6662. A noncorporate taxpayer may avoid this penalty if the understatement was
not attributable to a "tax shelter," as that term is defined below, and there is
or was substantial authority for the taxpayer's tax treatment of the item that
caused the understatement, or if the relevant facts were adequately disclosed on
the taxpayer's individual federal income tax return or a statement attached to
the return and the taxpayer had a "reasonable basis" for the tax treatment of
that item. In the case of an understatement that is attributable to a "tax
shelter," however, which may include each of the partnerships for this purpose,
the penalty may be avoided by a non-corporate taxpayer only if there was
reasonable cause for the underpayment and the taxpayer acted in good faith, or
there is or was substantial authority for the taxpayer's treatment of the item
that caused the understatement, and the taxpayer reasonably believed that his or
her treatment of the item on his individual federal income tax return was more
likely than not the proper treatment.

For purposes of this penalty, the term "tax shelter" includes a partnership if a
significant purpose of the partnership is the avoidance or evasion of federal
income tax. Because the IRS has not explained what a "significant" purpose of
avoiding or evading federal income taxes means, special counsel cannot give an
opinion as to whether the partnerships are "tax shelters" as defined by the Code
for purposes of this penalty.


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Also, under Section 6662A of the Code, there is a 20% penalty for reportable
transaction understatements of federal income taxes on a taxpayer's individual
federal income tax return for any tax year. However, if the disclosure rules for
reportable transactions under the Code and the Treasury Regulations are not met
by the taxpayer, this penalty is increased from 20% to 30%, and a "reasonable
cause" exception to the penalty that is set forth in Section 6664(d) of the Code
will not be available to the taxpayer. Under Treasury Regulation Section
1.6011-4, a taxpayer who participates in a reportable transaction in any taxable
year must attach to his individual federal income tax return IRS Form 8886
"Reportable Transaction Disclosure Statement," and file it with the IRS as
directed in the Regulation, in order to comply with the disclosure rules.

A tax item is subject to the reportable transaction rules if the tax item is
attributable to:

     o    any listed transaction, which is a transaction that is the same as, or
          substantially similar to, a transaction that the IRS has publicly
          pronounced to be a tax avoidance transaction; or

     o    any of four additional types of reportable transactions, if a
          significant purpose of the transaction is federal income tax avoidance
          or evasion.

A "loss transaction" is one type of reportable transaction, but only if a
"significant" purpose of the transaction is federal income tax avoidance or
evasion. As set forth above, special counsel cannot give an opinion with respect
to whether or not each partnership has a "significant" purpose of avoiding or
evading federal income taxes, because the IRS has not explained what that phrase
means for purposes of this penalty. Subject to the foregoing, under Treasury
Regulation Section 1.6011-4(b)(5), there is a loss transaction if a partnership
or any of its noncorporate partners claims a loss under Section 165 of the Code
of at least $2 million, in the aggregate, in any taxable year of the
partnership, or at least $4 million, in the aggregate, over the partnership's
first six years. In this regard, however, special counsel has given its opinion
that the partnerships are not, and should not be in the future, reportable
transactions under the Code.

For purposes of the "loss transaction" rules, a Section 165 loss includes an
amount deductible under a provision of the Code that treats a transaction as a
sale or other disposition of property, or otherwise results in a deduction under
Section 165. A Section 165 loss includes, for example, a loss resulting from a
sale or exchange of a partnership interest, such as an investor's units in a
partnership. The amount of a Section 165 loss is adjusted for any salvage value
and for any insurance or other compensation received. However, a Section 165
loss for this purpose does not take into account offsetting gains or other
income limitations under the Code.

Each partnership will incur a tax loss in 2007 in excess of $2 million if the
partnership receives subscription proceeds of approximately $2,225,000 or more,
or a loss in excess of $4 million if subscription proceeds of at least
$4,450,000 are received by the partnership, due primarily to the amount of
intangible drilling costs for productive wells that each partnership intends to
claim as a deduction. Notwithstanding the foregoing, in special counsel's
opinion the partnerships' losses resulting from deductions claimed for
intangible drilling costs for productive wells properly should be treated as
losses under Section 263(c) of the Code and Treas. Reg. Section 1.612-4(a), and
should not be treated as Section 165 losses for purposes of the "loss
transaction" rules under Treas. Reg. 1.6011-4(b)(5). However, the partnerships
may incur losses under Section 165 of the Code, such as losses for the
abandonment by a partnership of:

     o    wells drilled that are nonproductive (i.e. a "dry hole"), if any, in
          which case the intangible drilling costs, the tangible costs, and
          possibly the lease acquisition costs of the abandoned wells would be
          deducted as Section 165 losses; and

     o    wells that have been operated until their commercial natural gas and
          oil reserves have been depleted, in which case the undepreciated
          tangible costs, if any, and possibly the lease acquisition costs,
          would be deducted as Section 165 losses.

In this regard, based primarily on its past experience (as shown in "Prior
Activities"), including Atlas America's 97% completion rate for wells drilled by
its previous development drilling partnerships in the Appalachian Basin (see "-
Management"), the managing general partner has represented the following:


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     o    when a well is plugged and abandoned by a partnership, the salvage
          value of the well's equipment usually will cover a substantial amount
          of the costs of abandoning and reclaiming the well site;

     o    each partnership will drill relatively few non-productive wells (i.e.,
          "dry holes"), if any;

     o    each productive well drilled by a partnership will have a different
          productive life and the wells will not all be depleted and abandoned
          in the same taxable year;

     o    each productive well drilled by a partnership will produce for more
          than six years; and

     o    approximately 389 gross wells (which is approximately 355) net wells
          will be drilled by Atlas America Public #16-2007(A) L.P. if its
          targeted maximum subscription proceeds of $100 million are received,
          based on the managing general partner's estimate of the average
          weighted cost of drilling and completing the partnership's wells. (See
          "Compensation - Drilling Contracts).

STATE AND LOCAL TAXES

Each partnership will operate in states and localities that may impose a tax on
it, or on you and the partnership's other investors, based on the partnership's
assets or income or your share of its assets or income. Because of widespread
state budget deficits, several states are evaluating ways to subject
partnerships to entity-level taxation through the imposition of state income,
franchise or other forms of taxation. If any state were to impose a tax upon
your partnership as an entity, the cash available for distribution to you would
be reduced. Each partnership also may be subject to state income tax withholding
requirements on its income allocable to you and its other investors, whether or
not the revenues that created the income are distributed to you and its other
investors. Deductions and credits, including federal marginal well production
credits, if any, which may be available to you for federal income tax purposes,
may not be available to you for state or local income tax purposes. If you
reside in a state or locality that imposes income taxes on its residents, you
likely will be required under those income tax laws to include your share of
your partnership's net income or net loss in determining your reportable income
for state or local tax purposes in the jurisdiction in which you reside. To the
extent that you pay tax to another state because of partnership operations
within that state, you may be entitled to a deduction or credit against tax owed
to your state of residence with respect to the same income. Also, due to a
partnership's operations in a state or local jurisdiction, state or local estate
or inheritance taxes may be payable on the death of an investor in addition to
taxes imposed by his own domicile.

Each partnership's units may be sold in all 50 states and the District of
Columbia and other jurisdictions, and it is not practical for special counsel to
evaluate the many different state and local tax laws that may affect one or more
of a partnership's investors with respect to their investment in the
partnership. You are urged to seek advice based on your particular circumstances
from an independent tax advisor to determine the effect state and local taxes,
including gift and death taxes as well as income taxes, may have on you in
connection with an investment in a partnership.

SEVERANCE AND AD VALOREM (REAL ESTATE) TAXES

Each partnership will incur various ad valorem or severance taxes imposed by
state or local taxing authorities on its natural gas and oil wells and/or
natural gas and oil production from the wells. These taxes will reduce the
amount of each partnership's cash available for distribution to you and its
other investors.

SOCIAL SECURITY BENEFITS AND SELF-EMPLOYMENT TAX

A limited partner's share of income or loss from a partnership is excluded from
the definition of "net earnings from self-employment." No increased benefits
under the Social Security Act will be earned by limited partners and if any
limited partners are currently receiving Social Security benefits, their shares
of partnership taxable income will not be taken into account in determining any
reduction in benefits because of "excess earnings."

An investor general partner's share of income or loss from a partnership will
constitute "net earnings from self-employment" for these purposes. The ceiling
for social security tax of 12.4% in 2006 was $94,200, which will be adjusted
annually for inflation in 2007 and subsequent years. There is no ceiling for
medicare tax of 2.9%. Self-employed individuals can deduct one-half of their
self-employment tax.


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FARMOUTS

Under a farmout by a partnership, if a property interest, other than an interest
in the drilling unit assigned to the partnership well in question, is earned by
the farmee (anyone other than the partnership) from the farmor (the partnership)
as a result of the farmee drilling or completing the well, then the farmee must
recognize income equal to the fair market value of the outside interest earned,
and the farmor must recognize gain or loss on a deemed sale equal to the
difference between the fair market value of the outside interest and the
farmor's tax basis in the outside interest. Neither the farmor nor the farmee
would have received any cash to pay the tax. The managing general partner has
represented that it will attempt to eliminate or reduce any gain to a
partnership from a farmout, if any. However, if the IRS claims that a farmout by
a partnership results in taxable income to the partnership and its position is
ultimately sustained, you and the other investors in that partnership would be
required to include your share of the resulting taxable income on your
individual income tax returns, even though the partnership and you and the other
investors in that partnership received no cash from the farmout.

FOREIGN PARTNERS

Each partnership will be required to withhold and pay income tax to the IRS at
the highest rate under the Code applicable to partnership income allocable to
its foreign investors, even if no cash distributions are made to them. In the
event of overwithholding, a foreign investor must seek a refund on his
individual United States federal income tax return. For withholding purposes, a
foreign investor means an investor who is not a United States person and
includes a nonresident alien individual, a foreign corporation, a foreign
partnership, and a foreign trust or estate, unless the investor has certified to
his partnership the investor's status as a U.S. person on Form W-9 or any other
form permitted by the IRS for that purpose.

Foreign investors are urged to seek advice based on their particular
circumstances from an independent tax advisor regarding the applicability of
these rules and the other tax consequences of an investment in a partnership to
them.

ESTATE AND GIFT TAXATION

There is no federal tax on lifetime or testamentary transfers of property
between spouses. The gift tax annual exclusion amount was $12,000 per donee in
2007, which will be adjusted in 2007 and subsequent years for inflation. Under
the Economic Growth and Tax Relief Reconciliation Act of 2001 (the "2001 Tax
Act"), the maximum estate and gift tax rate is 45% from 2007 through 2009.
Estates of $2.0 million or less in 2007, which increases to estates of $3.5
million or less in 2009, are not subject to federal estate tax to the extent
those exemption amounts (i.e., unified credit amounts) were not previously used
by the decedent to reduce gift taxes on any lifetime gifts in excess of the
applicable annual exclusion amount for gifts. Under the 2001 Tax Act, the
federal estate tax will be repealed in 2010, and the maximum gift tax rate in
2010 will be 35%. In 2011, however, the federal estate and gift taxes are
scheduled to be reinstated under the rules in effect before the 2001 Tax Act was
enacted.

CHANGES IN THE LAW

Your tax benefits from an investment in a partnership may be affected by changes
in the tax laws. For example, in 2003 the top four federal income tax brackets
for individuals were reduced through December 31, 2010, including reducing the
top bracket to 35% from 38.6%. The lower federal income tax rates will reduce to
some degree the amount of taxes you can save by virtue of your share of your
partnership's deductions for intangible drilling costs, depletion and
depreciation, and marginal well production credits, if any. On the other hand,
the lower federal income tax rates also will reduce the amount of federal income
tax liability incurred by you on your share of your partnership's net income.
However, the federal income tax brackets discussed above could be changed again,
even before 2011, and other changes in the tax laws could be made which would
affect your tax benefits from an investment in a partnership.

You are urged to seek advice based on your particular circumstances from an
independent tax advisor with respect to the impact of recent federal tax
legislation on an investment in a partnership and the status of federal and
state legislative, regulatory or administrative tax developments and tax
proposals and their potential effect on the tax consequences to you of an
investment in a partnership.


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                        SUMMARY OF PARTNERSHIP AGREEMENT

The rights and obligations of the managing general partner and you and the other
investors in a partnership are governed by the form of partnership agreement, a
copy of which attached as Exhibit (A) to this prospectus. You are urged to
thoroughly review the partnership agreement before you decide to invest in a
partnership. The following is a summary of the material provisions in the
partnership agreement that are not covered elsewhere in this prospectus. Thus,
this prospectus summarizes all of the material provisions of the partnership
agreement.

LIABILITY OF LIMITED PARTNERS

Each partnership will be governed by the Delaware Revised Uniform Limited
Partnership Act. If you invest as a limited partner, then generally you will not
be liable to third-parties for the obligations of your partnership unless you:

     o    also invest as an investor general partner;

     o    take part in the control of the partnership's business in addition to
          the exercise of your rights and powers as a limited partner; or

     o    fail to make a required capital contribution to the extent of the
          required capital contribution.

In addition, you may be required to return any distribution you receive from a
partnership if you knew at the time the distribution was made that it was
improper because it rendered the partnership insolvent.

AMENDMENTS

Amendments to the partnership agreement of a partnership may be proposed in
writing by:

     o    the managing general partner and adopted with the consent of investors
          whose units equal a majority of the total units in the partnership; or

     o    investors whose units equal 10% or more of the total units in the
          partnership and adopted by an affirmative vote of investors whose
          units equal a majority of the total units in the partnership.

The partnership agreement of each partnership may also be amended by the
managing general partner without the consent of the investors for certain
limited purposes. However, an amendment that materially and adversely affects
the investors can only be made with the consent of the affected investors.

NOTICE

The following provisions apply regarding notices:

     o    when the managing general partner gives you and other investors notice
          it begins to run from the date of mailing the notice and is binding
          even if it is not received;

     o    the notice periods are frequently quite short, a minimum of 22
          calendar days, and apply to matters that may seriously affect your
          rights; and

     o    if you fail to respond in the specified time to the managing general
          partner's second request for approval of or concurrence in a proposed
          action, then you will conclusively be deemed to have approved the
          action unless the partnership agreement expressly requires your
          affirmative approval.

VOTING RIGHTS

Other than as set forth below, you generally will not be entitled to vote on any
partnership matters at any partnership meeting. At any time, however, investors
whose units equal 10% or more of the total units in a partnership may call a
meeting to vote, or vote without a meeting, on the matters set forth below
without the concurrence of the managing general


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partner. On the matters being voted on you are entitled to one vote per unit or
if you own a fractional unit that fraction of one vote equal to the fractional
interest in the unit. Investors whose units equal a majority of the total units
in a partnership may vote to:

     o    dissolve the partnership;

     o    remove the managing general partner and elect a new managing general
          partner;

     o    elect a new managing general partner if the managing general partner
          elects to withdraw from the partnership;

     o    remove the operator and elect a new operator;

     o    approve or disapprove the sale of all or substantially all of the
          partnership's assets;

     o    cancel any contract for services with the managing general partner,
          the operator, or their affiliates without penalty on 60 days notice;
          and

     o    amend the partnership agreement, however, any amendment may not:

          o    without the approval of you or the managing general partner
               increase the duties or liabilities of you or the managing general
               partner, or increase or decrease the profits or losses or
               required capital contribution of you or the managing general
               partner; or

          o    without the unanimous approval of all investors in the
               partnership, affect the classification of partnership income and
               loss for federal income tax purposes.

The managing general partner, its officers, directors, and affiliates may also
subscribe for units in each partnership on a discounted basis, and they may vote
on all matters, including the issues set forth above, other than:

     o    removing the managing general partner and operator; and

     o    any transaction between the managing general partner or its affiliates
          and the partnership.

Any units owned by the managing general partner and its affiliates will not be
included in determining the requisite number of units necessary to approve any
partnership matter on which the managing general partner and its affiliates may
not vote or consent.

ACCESS TO RECORDS

You will have access to all records of your partnership at any reasonable time
on adequate notice. However, logs, well reports, and other drilling and
operating data may be kept confidential for reasonable periods of time. Also,
your ability to obtain the list of investors is subject to additional
requirements set forth in the partnership agreement.

WITHDRAWAL OF MANAGING GENERAL PARTNER

After 10 years the managing general partner may voluntarily withdraw as managing
general partner of a partnership for any reason by giving 120 days' written
notice to you and the other investors in the partnership. Although the
withdrawing managing general partner is not required to provide a substitute
managing general partner, a new managing general partner may be substituted by
the affirmative vote of investors whose units equal a majority of the total
units in the partnership. If the investors, however, choose not to continue the
partnership and do not select a substitute managing general partner, then the
partnership would dissolve and terminate, which could result in adverse tax and
other consequences to you.


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Also, the managing general partner may assign its general partner interest in
the partnership to its affiliates, and it may withdraw a property interest in
the form of a working interest in the partnership's wells equal to or less than
its revenue interest at any time if the withdrawal is:

     o    to satisfy the bona fide request of its creditors; or

     o    approved by investors in the partnership whose units equal a majority
          of the total units.

(See "Management - Managing General Partner and Operator" and "Conflicts of
Interest - Conflicts Regarding the Managing General Partner Withdrawing or
Assigning an Interest."

RETURN OF SUBSCRIPTION PROCEEDS IF FUNDS ARE NOT INVESTED IN TWELVE MONTHS

Although the managing general partner anticipates that each partnership will
spend all of its subscription proceeds soon after the offering of the
partnership closes, each partnership will have 12 months in which to use or
commit its subscription proceeds to drilling activities. If within the 12-month
period the partnership has not used, or committed for use, all of its
subscription proceeds, then the managing general partner will distribute the
remaining subscription proceeds to you and the other investors in the
partnership in accordance with your respective subscription amounts as a return
of capital.

                   SUMMARY OF DRILLING AND OPERATING AGREEMENT

The managing general partner will serve as the operator under the drilling and
operating agreement, Exhibit (II) to the partnership agreement. The operator may
be replaced at any time on 60 days' advance written notice by the managing
general partner acting on behalf of a partnership on the affirmative vote of
investors whose units equal a majority of the total units in the partnership.
You are urged to thoroughly review the drilling and operating agreement before
you decide to invest in a partnership. The following is a summary of the
material provisions of the drilling and operating agreement that are not covered
elsewhere in this prospectus. Thus, this prospectus summarizes all of the
material provisions of the drilling and operating agreement.

The drilling and operating agreement includes the material provisions set forth
below.

     o    The operator's right to resign after five years.

     o    The operator's right beginning one year after a partnership well
          begins producing to retain $200 per month to cover future plugging and
          abandonment costs of the well.

     o    The grant of a first lien and security interest in the wells and
          related production to secure payment of amounts due to the operator by
          a partnership.

     o    The prescribed insurance coverage to be maintained by the operator.

     o    Limitations on the operator's authority to incur extraordinary costs
          with respect to producing wells in excess of $5,000 per well.

     o    Restrictions on the partnership's ability to transfer its interest in
          fewer than all wells unless the transfer is of an equal undivided
          interest in all of the wells.

     o    The limitation of the operator's liability to a partnership except for
          the operator's:

          o    violations of law;

          o    negligence or misconduct by it, its employees, agents or
               subcontractors; or

          o    breach of the drilling and operating agreement.


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     o    The excuse for nonperformance by the operator due to force majeure
          which generally means acts of God, catastrophes and other causes which
          preclude the operator's performance and are beyond its control.

                              REPORTS TO INVESTORS

Under the partnership agreement for each partnership you and certain state
securities commissions will be provided the reports and information set forth
below for your partnership, which your partnership will pay as a direct cost.

     o    Beginning with the calendar year in which your partnership closes, you
          will be provided an annual report within 120 days after the close of
          the calendar year, and beginning with the following calendar year, a
          report within 75 days after the end of the first six months of its
          calendar year, containing at least the following information.

          o    Audited financial statements of the partnership prepared on an
               accrual basis in accordance with generally accepted accounting
               principles with a reconciliation for information furnished for
               income tax purposes. Independent certified public accountants
               will audit the financial statements to be included in the annual
               report, but semiannual reports will not be audited.

          o    A summary of the total fees and compensation paid by the
               partnership to the managing general partner, the operator, and
               their affiliates. In this regard, the independent certified
               public accountant will provide written attestation annually,
               which will be included in the annual report, that the method used
               to make allocations was consistent with the method described in
               Section 4.04(a)(2)(c) of the partnership agreement and that the
               total amount of costs allocated did not materially exceed the
               amounts actually incurred by the managing general partner.

               If the managing general partner subsequently decides to allocate
               expenses in a manner different from that described in Section
               4.04(a)(2)(c) of the partnership agreement, then the change must
               be reported to you and the other investors with an explanation of
               the reason for the change and the basis used for determining the
               reasonableness of the new allocation method.

          o    A description of each prospect owned by the partnership,
               including the cost, location, number of acres, and the interest.

          o    A list of the wells drilled or abandoned by the partnership
               indicating:

               o    whether each of the wells has or has not been completed; and

               o    a statement of the cost of each well completed or abandoned.

          o    A description of all farmouts, farmins, and joint ventures.

          o    A schedule reflecting:

               o    the total partnership costs;

               o    the costs paid by the managing general partner and the costs
                    paid by the investors;

               o    the total partnership revenues; and

               o    the revenues received or credited to the managing general
                    partner and the revenues received or credited to you and the
                    other investors.


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     o    On request the managing general partner will provide you the
          information specified by Form 10-Q (if that report is required to be
          filed with the SEC) within 45 days after the close of each quarterly
          fiscal period. Also, this information is available at the SEC website
          www.sec.gov.

     o    By March 15 of each year you will receive the information that is
          required for you to file your federal and state income tax returns.

     o    Beginning with the second calendar year after your partnership closes,
          and every year thereafter, you will receive a computation of the
          partnership's total natural gas and oil proved reserves and its dollar
          value. The reserve computations will be based on engineering reports
          prepared by the managing general partner and reviewed by an
          independent expert.

                               PRESENTMENT FEATURE

Beginning with the fifth calendar year after your partnership closes, you and
the other investors in your partnership may present your units to the managing
general partner to purchase your units. However, you are not required to offer
your units to the managing general partner, and you may receive a greater return
if you retain your units. The managing general partner will not purchase less
than one unit unless the fractional unit represents your entire interest in the
partnership.

The managing general partner has no obligation or intention to establish a
reserve to satisfy the presentment feature and it may immediately suspend the
presentment obligation by notice to you if it determines, in its sole
discretion, that it:

     o    does not have the necessary cash flow; or

     o    cannot borrow funds for this purpose on terms it deems reasonable.

If fewer than all units presented at any time are to be purchased by the
managing general partner, then the units to be purchased will be selected by
lot.

The managing general partner's obligation to purchase the units presented may be
discharged for its benefit by a third-party or an affiliate. If you sell your
unit it will be transferred to the party who pays for it, and you will be
required to deliver an executed assignment of your unit along with any other
documents that the managing general partner requests. Your presentment of your
units to the managing general partner for purchase is subject to the following
conditions:

     o    the managing general partner will not purchase more than 5% of the
          total outstanding units in a partnership in any calendar year;

     o    your presentment request must be made within 120 days of the
          partnership reserve report discussed below;

     o    in accordance with Treas. Reg. Section 1.7704-1(f) the managing
          general partner may not purchase your units until at least 60 calendar
          days after you notify the partnership in writing of your intent to
          present your units for purchase; and

     o    the purchase of your units will not be considered effective until the
          presentment price has been paid to you in cash.

The amount of the presentment price for your units that is attributable to a
partnership's natural gas and oil reserves, as discussed below, will be
determined based on the last reserve report prepared by the managing general
partner and reviewed by an independent expert. Beginning with the second
calendar year after your partnership closes and every year thereafter, the
managing general partner will estimate the present worth of future net revenues
attributable to your partnership's interest in proved reserves. In making this
estimate, the managing general partner will use:


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     o    a 10% discount rate;

     o    a constant oil price; and

     o    base natural gas prices on the existing natural gas contracts at the
          time of the presentment.

Your presentment price will be based on your share of your partnership's net
assets and liabilities as described below, based on the ratio that your number
of units bears to the total number of units in your partnership. The presentment
price will include the sum of the following partnership items:

     o    an amount based on 70% of the present worth of future net revenues
          from the proved reserves determined as described above;

     o    cash on hand;

     o    prepaid expenses and accounts receivable, less a reasonable amount for
          doubtful accounts; and

     o    the estimated market value of all assets not separately specified
          above, determined in accordance with standard industry valuation
          procedures.

There will be deducted from the foregoing sum the following partnership items:

     o    an amount equal to all debts, obligations, and other liabilities,
          including accrued expenses; and

     o    any distributions made to you between the date of your presentment
          request and the date the presentment price is paid to you. However, if
          any cash distributed to you by the partnership, after your presentment
          request was derived from the sale of oil, natural gas, or a producing
          property the amount of those cash distributions will be discounted at
          the same rate used to take into account the risk factors employed to
          determine the present worth of the partnership's proved reserves for
          purposes of determining the reduction of the presentment price.

The presentment price may be further adjusted by the managing general partner
for estimated changes from the date of the reserve report discussed above to the
date of payment of the presentment price to you due to the following:

     o    the production or sales of, or additions to, reserves and lease and
          well equipment, sale or abandonment of leases, and similar matters
          occurring before the presentment request; and

     o    any of the following occurring before payment of the presentment price
          to you;

          o    changes in well performance;

          o    increases or decreases in the market price of oil, natural gas,
               or other minerals;

          o    revision of regulations relating to the importing of
               hydrocarbons; and

          o    changes in income, ad valorem, and other tax laws such as
               material variations in the provisions for depletion; and

          o    similar matters.

As of September 15 2006, approximately 230 units have been presented to the
managing general partner for purchase in its previous 53 limited partnerships.


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                            TRANSFERABILITY OF UNITS

RESTRICTIONS ON TRANSFER IMPOSED BY THE SECURITIES LAWS, THE TAX LAWS AND THE
PARTNERSHIP AGREEMENT

Your ability to sell or otherwise transfer your units in your partnership is
restricted by the securities laws, the tax laws, and the partnership agreement
as described below. Also, the sale or other transfer of your units may create
negative tax consequences to you as described in "Federal Income Tax
Consequences - Disposition of Units."

First, due to the tax laws, the partnership agreement provides that you will not
be able to sell, assign, exchange, or transfer your unit if it would, in the
opinion of counsel for the partnership, result in the following:

     o    the termination of your partnership for tax purposes; or

     o    your partnership being treated as a "publicly traded" partnership for
          tax purposes.

Second, under the partnership agreement sales or other transfers of the units
are subject to the following additional limitations:

     o    except as provided by operation of law, the partnership will recognize
          the transfer of only one or more whole units unless you own less than
          a whole unit, in which case your entire fractional interest must be
          transferred;

     o    the costs and expenses associated with the transfer must be paid by
          the person transferring the unit;

     o    the form of transfer must be in a form satisfactory to the managing
          general partner; and

     o    the terms of the transfer must not contravene those of the partnership
          agreement.

Your transfer of a unit will not:

     o    relieve you of your responsibility for any obligations related to your
          units under the partnership agreement;

     o    grant rights under the partnership agreement as among your
          transferees, to more than one party unanimously designated by the
          transferees to the managing general partner; nor

     o    require an accounting of the partnership by the managing general
          partner.

If the assignee of the unit does not become a substituted partner as described
below in "- Conditions to Becoming a Substitute Partner," the transfer will be
effective as of midnight of the last day of the calendar month in which it is
made or, at the managing general partner's election, 7:00 A.M. of the following
day.

Finally, you will not be able to sell, assign, pledge, hypothecate, or transfer
your unit if the managing general partner requires, in its sole discretion, that
you must provide an opinion of counsel acceptable to the managing general
partner that the registration and qualification under any applicable federal or
state securities laws are not required.

CONDITIONS TO BECOMING A SUBSTITUTE PARTNER

An assignee of a unit will not be entitled to any of the rights granted to a
partner under the partnership agreement, other than the right to receive all or
part of the share of the profits, losses, income, gain, credits and cash
distributions or returns of capital to which his assignor would otherwise be
entitled, unless the assignee becomes a substituted partner in accordance with
the provisions set forth below. The conditions to become a substitute partner
are as follows:

     o    the assignor gives the assignee the right;

     o    the assignee pays all costs and expenses incurred in connection with
          the substitution; and


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     o    the assignee executes and delivers, in a form acceptable to the
          managing general partner, the instruments necessary to establish that
          a legal transfer has taken place and to confirm his agreement to be
          bound by all of the terms and provisions of the partnership agreement.

A substitute partner is entitled to all of the rights of full ownership of the
assigned units, including the right to vote. Each partnership will amend its
records at least once each calendar quarter to effect the substitution of
substituted partners.

                              PLAN OF DISTRIBUTION

COMMISSIONS

The units in each partnership will be offered on a "best efforts" basis by
Anthem Securities, which is an affiliate of the managing general partner, acting
as dealer-manager and by other selected registered broker/dealers that are
members of the NASD acting as selling agents. Anthem Securities was formed for
the purpose of serving as dealer-manager of partnerships sponsored by the
managing general partner and became an NASD member firm in April, 1997.

The dealer-manager will manage and oversee the offering of the units as
described above. Best efforts generally means that the dealer-manager and
selling agents will not guarantee that a certain number of units will be sold.
Units may also be sold by the officers and directors of the managing general
partner in those states where they are licensed to do so or are exempt from
licensing. All offers and sales of units by the managing general partner's
remaining officers and directors will be made under the SEC safe harbor from
broker/dealer registration provided by Rule 3a4-1.

Subject to the exceptions described below, the dealer-manager will receive on
each unit sold:

     o    a 2.5% dealer-manager fee;

     o    a 7% sales commission; and

     o    an up to .5% reimbursement of the selling agent's bona fide due
          diligence expenses.

All of the reimbursement of the selling agents' bona fide due diligence expenses
and generally all of the 7% sales commission will be reallowed by the
dealer-manager to the selling agents. With respect to the up to .5%
reimbursement of a selling agent's bona fide due diligence expenses, any bill
presented by a selling agent to the dealer-manager for reimbursement of costs
associated with its due diligence activities must be for actual costs, including
overhead, incurred by the selling agent and may not include a profit margin. It
is the responsibility of the managing general partner and the dealer-manager to
ensure compliance with the above guideline. If the selling agent provides the
dealer-manager an itemized bill for actual due diligence expenses which is in
excess of .5%, then the excess over .5% will not be included within the 10%
compensation guideline, but instead will be included within the 4.5%
organization and offering cost guideline under NASD Conduct Rule 2810.

From the 2.5% dealer-manager fee, the dealer-manager may pay up to a .5%
marketing fee if the selling agent meets certain sales thresholds and provides
marketing support. Additionally, the Dealer-Manager may use a portion of its
Dealer-Manager fee to pay for permissible non-cash compensation. Under Rule 2810
of the NASD Conduct Rules, non-cash compensation means any form of compensation
received in connection with the sale of the units that is not cash compensation,
including but not limited to merchandise, gifts and prizes, travel expenses,
meals and lodging. Permissible non-cash compensation includes the following:

     o    an accountable reimbursement for training and education meetings for
          associated persons of the selling agents;

     o    gifts that do not exceed $100 per year and are not preconditioned on
          achievement of a sales target;


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     o    an occasional meal, a ticket to a sporting event or the theater, or
          comparable entertainment which is neither so frequent nor so extensive
          as to raise any question of propriety and is not preconditioned on
          achievement of a sales target; and

     o    contributions to a non-cash compensation arrangement between a selling
          agent and its associated persons, provided that neither the managing
          general partner nor the dealer-manager directly or indirectly
          participates in the selling agent's organization of a permissible
          non-cash compensation arrangement.

In no event shall a selling agent receive non-cash compensation and the
marketing fee if it represents more than .5% per unit.

The managing general partner is also using the services of wholesalers who are
employed by it or its affiliates and are registered through Anthem Securities.
The wholesalers include four Regional Marketing Directors. A portion of the 2.5%
dealer-manager fee will be reallowed to the affiliated wholesalers for
subscriptions obtained through their efforts and their reimbursement of
expenses. The dealer-manager will retain the remainder of the dealer-manager fee
not reallowed to the wholesalers or as described in the prior paragraph.

The offering will be made in compliance with Rule 2810 of the NASD Conduct Rules
and all compensation, including non-cash compensation, to broker/dealers and
wholesalers, regardless of the source, will be limited to 10% of the gross
proceeds of the offering plus the .5% reimbursement for bona fide due diligence
expenses on each subscription. Also, the offering will be made in compliance
with Rule 2810(b)(2)(C) of the NASD Conduct Rules and the broker/dealers and
wholesalers will not execute a transaction for the purchase of units in a
discretionary account without the prior written approval of the transaction by
the customer. Finally, the offering will be conducted in compliance with SEC
Rule 15c2-4.

Subject to the following, you and the other investors will pay $10,000 per unit
and generally will share costs, revenues, and distributions in the partnership
in which you invest in proportion to your respective number of units. However,
the subscription price for certain investors will be reduced as set forth below:

     o    the subscription price for the managing general partner, its officers,
          directors, and affiliates, and investors who buy units through the
          officers and directors of the managing general partner, will be
          reduced by an amount equal to the 2.5% dealer-manager fee, the 7%
          sales commission and the .5% reimbursement for bona fide due diligence
          expenses, which will not be paid with respect to these sales; and

     o    the subscription price for registered investment advisors and their
          clients, and selling agents and their registered representatives and
          principals, will be reduced by an amount equal to the 7% sales
          commission, which will not be paid with respect to these sales.

No more than 5% of the total units in each partnership may be sold with the
discounts described above. These investors who pay a reduced price for their
units generally will share in a partnership's costs, revenues, and distributions
on the same basis as the other investors who pay $10,000 per unit as discussed
in "Participation in Costs and Revenues - Allocation and Adjustments Among
Investors." Although the managing general partner and its affiliates may buy up
to 5% of the units, they do not currently anticipate buying any units. If they
do buy units, then those units will not be applied towards the minimum
subscription proceeds required for a partnership to begin operations.

To help assure an orderly market for the units, the managing general partner,
the dealer-manager and the selling agents may use such methods as they deem
appropriate to allocate units among interested investors if they anticipate that
demand for units will exceed the available supply, provided that no changes to
compensation may be made. These methods may include, but will not be limited to:

     o    allocations of units to selling agents;

     o    priority acceptance of subscriptions from previous investors in
          partnerships sponsored by the managing general partner;


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     o    priority treatment for investors whose subscriptions were declined by
          earlier partnerships sponsored by the managing general partner because
          the number of units available was not sufficient to accommodate their
          subscriptions; or

     o    any other methods as may be approved by the managing general partner.

After the minimum subscription proceeds are received in a partnership and the
checks have cleared the banking system, the dealer-manager fee and the sales
commissions will be paid to the dealer-manager and selling agents approximately
every two weeks until the offering closes.

INDEMNIFICATION

The dealer-manager is an underwriter as that term is defined in the 1933 Act and
the sales commissions and dealer-manager fees will be deemed underwriting
compensation. The managing general partner and the dealer-manager have agreed to
indemnify each other, and it is anticipated that the dealer-manager and each
selling agent will agree to indemnify each other against certain liabilities,
including liabilities under the 1933 Act.

                                 SALES MATERIAL

In addition to the prospectus, the managing general partner intends to use the
following sales material with the offering of the units:

     o    a flyer entitled "Atlas America Public #16-2007 Program";

     o    an article entitled "Tax Rewards with Oil and Gas Partnerships";

     o    a brochure of tax scenarios entitled "How an Investment in Atlas
          America Public #16-2007 Program Can Help Achieve an Investor's Tax
          Objectives";

     o    a booklet entitled "Outline of Tax Consequences of Oil and Gas
          Drilling Programs";

     o    a brochure entitled "Investment Insights - Tax Time";

     o    a brochure entitled "Frequently Asked Questions";

     o    a brochure entitled "The Drilling Process"; and

     o    possibly other supplementary materials.

The managing general partner has not authorized the use of other sales material
and the offering of units is made only by means of this prospectus. The sales
material is subject to the following considerations:

     o    it must be preceded or accompanied by this prospectus;

     o    it is not complete;

     o    it does not contain any information which is inconsistent with this
          prospectus; and

     o    it should not be considered a part of or incorporated into this
          prospectus or the registration statement of which this prospectus is a
          part.

In addition, supplementary materials, including prepared presentations for group
meetings, must be submitted to the state administrators before they are used and
their use must either be preceded by or accompanied by a prospectus. Also, all


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advertisements of, and oral or written invitations to, "seminars" or other group
meetings at which the units are to be described, offered, or sold will clearly
indicate the following:

     o    that the purpose of the meeting is to offer the units for sale;

     o    the minimum purchase price of the units;

     o    the suitability standards to be employed; and

     o    the name of the person selling the units.

Also, no cash, merchandise, or other items of value may be offered as an
inducement to you or any other prospective investor to attend the meeting. All
written or prepared audiovisual presentations, including scripts prepared in
advance for oral presentations to be made at the meetings, must be submitted to
the state administrators within a prescribed review period. These provisions,
however, will not apply to meetings consisting only of the registered
representatives of the selling agents.

You should rely only on the information contained in this prospectus in making
your investment decision. No one is authorized to provide you with information
that is different.

                                 LEGAL OPINIONS

Kunzman & Bollinger, Inc., has issued its opinion to the managing general
partner regarding the validity and due issuance of the units, including
assessibility, and its opinion on the material and any significant federal tax
issues involving individual typical investors in the partnerships. However, the
factual statements in this prospectus are those of the partnerships or the
managing general partner, and counsel has not given any opinions with respect to
any of the tax or other legal aspects of this offering except as expressly set
forth above.

                                     EXPERTS

The financial statements included in this prospectus for Atlas Resources, LLC,
the managing general partner, as of and for the years ended September 30, 2005
and 2004 and the balance sheet for Atlas America Public #16-2007(A) L.P. have
been audited by Grant Thornton LLP, as of the dates indicated in its reports
which appear elsewhere in this prospectus. These financial statements have been
included in this prospectus in reliance on the reports of Grant Thornton LLP on
the authority of that firm as an expert in accounting and auditing.

The information concerning the estimated future net cash flows from proved
reserves presented under "Prior Activities - Table 3 Investor Operating
Results-Including Expenses" was reviewed by Wright & Company, Inc., Brentwood,
Tennessee, independent petroleum consultants, which is not affiliated with the
managing general partner or its affiliates, and is included in this prospectus
in reliance on Wright & Company, Inc. as an expert in petroleum consulting.

The geologic evaluations of United Energy Development Consultants, Inc., which
is not affiliated with the managing general partner or its affiliates, appearing
elsewhere in this prospectus have been included in this prospectus on the
authority of United Energy Development Consultants, Inc. as an expert with
respect to the matters covered by the evaluations and in the giving of the
evaluations.

                                   LITIGATION

The managing general partner knows of no litigation pending or threatened to
which the managing general partner or the partnerships are subject or may be a
party, which it believes would have a material adverse effect on the
partnerships or their business, and no such proceedings are known to be
contemplated by governmental authorities or other parties.


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FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL PARTNER AND ATLAS AMERICA
                             PUBLIC #16-2007(A) L.P.

Financial information concerning the managing general partner and the second
partnership in the program, Atlas America Public #16-2007(A) L.P., is reflected
in the following financial statements. With respect to the managing general
partner's financial information, the managing general partner was changed from a
corporation to a limited liability company in March, 2006. (See "Management -
Managing General Partner and Operator.")

The securities offered by this prospectus are not securities of, nor are you
acquiring an interest in the managing general partner, its affiliates, or any
other entity other than the partnership in which you purchase units.

                          INDEX TO FINANCIAL STATEMENTS

ATLAS AMERICA PUBLIC #16-2007(A) L.P. FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm dated September
   30, 2006..............................................................    F-1
Balance Sheet as of September 30, 2006...................................    F-2
Notes to Financial Statement dated September 30, 2006....................    F-3

ATLAS RESOURCES, INC. AND SUBSIDIARY AUDITED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm dated January
   6, 2006 (except for Note 10, as to which the date is April 7, 2006)...    F-8
Atlas Resources, Inc. and Subsidiary Consolidated Balance Sheets for
   the years ended September 30, 2005 and 2004...........................    F-9
Atlas Resources, Inc. and Subsidiary Consolidated Statements of Income
   for the years ended September 30, 2005 and 2004.......................   F-10
Atlas Resources, Inc. and Subsidiary Consolidated Statements of Changes
   in Stockholder's Equity for the years ended September 30, 2005 and
   2004..................................................................   F-11
Atlas Resources, Inc. and Subsidiary Consolidated Statements of Cash
   Flows for the years ended September 30, 2005 and 2004.................   F-12
Atlas Resources, Inc. and Subsidiary Notes to Consolidated Financial
   Statements dated January 6, 2006 (except for Note 10, as to which
   the date is April 7, 2006)............................................   F-13

ATLAS RESOURCES, LLC AND SUBSIDIARY CONSOLIDATED FINANCIAL STATEMENTS
   (UNAUDITED) AS OF JUNE 30, 2006

Atlas Resources, LLC and Subsidiary Consolidated Balance Sheets
   (Unaudited) as of June 30, 2006 and September 30, 2005................   F-29
Atlas Resources, LLC and Subsidiary Consolidated Statements of Income
   for the nine months ended June 30, 2006 and 2005 (Unaudited)..........   F-30
Atlas Resources, LLC and Subsidiary Consolidated Statements of Changes
   in Member's Equity for the nine months ended June 30, 2006
   (Unaudited)...........................................................   F-31
Atlas Resources, LLC and Subsidiary Consolidated Statements of Cash
   Flows for the nine months ended June 30, 2006 and 2005 (Unaudited)....   F-32
Atlas Resources, LLC and Subsidiary Notes to Consolidated Financial
   Statements dated as of June 30, 2006 (Unaudited)......................   F-33


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             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners
ATLAS AMERICA PUBLIC 16-2007 (A) L.P.
(A DELAWARE LIMITED PARTNERSHIP)

We have audited the accompanying balance sheet of Atlas America Public 16-2007
(A) L.P. (A Delaware Limited Partnership) as of September 30, 2006. This
financial statement is the responsibility of the Partnership's management. Our
responsibility is to express an opinion on this financial statement based on our
audit.

We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statement is free of material misstatement. The Partnership is not
required to have, nor were we engaged to perform an audit of its internal
control over financial reporting. Our audit included consideration of internal
control over financial reporting as a basis for designing audit procedures that
are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Partnership's internal control over
financial reporting. Accordingly, we express no such opinion. An audit also
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.

In our opinion, the financial statement referred to above presents fairly, in
all material respects, the financial position of Atlas America Public 16-2007
(A) L.P. as of September 30, 2006, in conformity with accounting principles
generally accepted in the United States of America.


                                        /s/ GRANT THORNTON LLP

Cleveland, Ohio
October 6, 2006


                                       F-1

<PAGE>

                      Atlas America Public 16-2007 (A) L.P.
                        (A Delaware Limited Partnership)

                                  BALANCE SHEET

                               September 30, 2006

                                     ASSETS

Cash                $100
                    ====

                                PARTNER'S CAPITAL

Partners' capital   $100
                    ====

   The accompanying notes to financial statement are an integral part of this
                                   statement.


                                       F-2

<PAGE>

                      Atlas America Public 16-2007 (A) L.P.
                        (A Delaware Limited Partnership)

                          NOTES TO FINANCIAL STATEMENT

                               SEPTEMBER 30, 2006

1.   ORGANIZATION AND DESCRIPTION OF BUSINESS

     Atlas America Public 16-2007 (A) L.P. (the "Partnership") is a Delaware
     limited partnership in which Atlas Resources, LLC ("Atlas Resources") of
     Pittsburgh, Pennsylvania (a second-tier wholly-owned subsidiary of Atlas
     America, Inc., a publicly traded company), will be Managing General Partner
     and Operator, and subscribers to units will be either Limited Partners or
     Investor General Partners depending upon their individual elections.

     The Partnership will be funded to drill development wells which are
     proposed to be located primarily in the Appalachian Basin located in
     western Pennsylvania, eastern and southern Ohio, western New York and north
     central Tennessee.

     Subscriptions at a cost of $10,000 per unit, subject to discounts for
     certain investors, generally will be sold using wholesalers and through
     broker-dealers including Anthem Securities, Inc., an affiliated company,
     which will receive on each unit sold to an investor, a 2.5% dealer-manager
     fee, a 7% sales commission and up to a .5% reimbursement of the selling
     agents' bona fide due diligence expenses. Commencement of Partnership
     operations is subject to the receipt of minimum Partnership subscriptions
     of $2,000,000 (up to a maximum of $200,000,000) by December 31, 2007.

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     BASIS OF ACCOUNTING

     The Partnership prepares its financial statements in accordance with
     accounting principles generally accepted in the United States of America.

     OIL AND GAS PROPERTIES

     The Partnership will use the successful efforts method of accounting for
     oil and gas producing activities. Costs to acquire mineral interests in oil
     and gas properties and to drill and equip wells will be capitalized.
     Depreciation and depletion will be computed on a field-by field basis by
     the unit-of-production method based on periodic estimates of oil and gas
     reserves. Undeveloped leaseholds and proved properties will be assessed
     periodically or whenever events or circumstances indicate that the carrying
     amount of these assets may not be recoverable. Proved properties will be
     assessed based on estimates of future cash flows.


                                      F-3

<PAGE>

                      Atlas America Public 16-2007 (A) L.P.
                        (A Delaware Limited Partnership)

                    NOTES TO FINANCIAL STATEMENT (CONTINUED)

                               SEPTEMBER 30, 2006

2    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

     USE OF ESTIMATES

     The preparation of financial statements in conformity with accounting
     principles generally accepted in the United States of America requires
     management to make estimates and assumptions that affect the amounts
     reported in the financial statements and accompanying notes. Actual results
     could differ from those estimates.

3.   FEDERAL INCOME TAXES

     The Partnership will not be treated as a taxable entity for federal income
     tax purposes. Any item of income, gain, loss, deduction or credit would
     flow through to the partners as though each partner has incurred such item
     directly. As a result, each partner must take into account his or her
     pro-rata share under the partnership agreement of all items of Partnership
     income and deductions in computing his or her federal income tax liability.

4.   PARTICIPATION IN REVENUES AND COSTS

     The Managing General Partner and the investor partners will participate in
     revenues and costs in the following manner:

<TABLE>
<CAPTION>
                                                                           MANAGING
                                                                            GENERAL   INVESTOR
                                                                            PARTNER   PARTNERS
                                                                           --------   --------
<S>                                                                        <C>        <C>
PARTNERSHIP COSTS
Organization and offering costs                                            100%         0%
Lease costs                                                                100%         0%
Intangible drilling costs (1)                                                0%       100%
Equipment costs                                                               (2)        (2)
Operating costs, administrative costs, direct costs, and all other costs      (3)        (3)

PARTNERSHIP REVENUES
Interest income                                                               (4)        (4)
Equipment proceeds                                                            (2)        (2)
All other revenues including production revenues                              (5)(6)     (5)(6)
</TABLE>


                                      F-4

<PAGE>

                      Atlas America Public 16-2007 (A) L.P.
                        (A Delaware Limited Partnership)

                    NOTES TO FINANCIAL STATEMENT (CONTINUED)

                               SEPTEMBER 30, 2006

4.   PARTICIPATION IN REVENUES AND COSTS (CONTINUED)

     (1)  An amount equal to 90% of the subscription proceeds of investor
          partners in the partnership will be used to pay 100% of the intangible
          drilling costs incurred by the partnership in drilling and completing
          its wells.

     (2)  An amount equal to 10% of the subscription proceeds of investor
          partners in the partnership will be used to pay a portion of the
          equipment costs incurred by the partnership in drilling and completing
          its wells. All equipment costs in excess of that amount will be
          charged to the Managing General Partner. Equipment proceeds, if any,
          will be credited in the same percentage in which the equipment costs
          were charged.

     (3)  These costs will be charged to the parties in the same ratio as the
          related production revenues are being credited. These costs also
          include plugging and abandonment costs of the wells after the wells
          have been drilled and produced.

     (4)  Interest earned on subscription proceeds before the final closing of
          the partnership will be credited to investor partners' accounts and
          paid not later than the partnerships first cash distribution from
          operations. After the final closing of the partnership and until the
          subscription proceeds are invested in the partnership's natural gas
          and oil operations any interest income from temporary investments will
          be allocated pro rata to the investor partners providing the
          subscription proceeds. All other interest income, including interest
          earned on the deposit of operating revenues, will be credited as
          natural gas and oil production revenues are credited.

     (5)  The managing general partner and the investor partners in the
          partnership will share in all of the partnership's other revenues in
          the same percentage as their respective capital contributions bear to
          the total partnership capital contributions except that the managing
          general partner will receive an additional 7% of the partnership
          revenues. However, the managing general partner's total revenue share
          may not exceed 40% of partnership revenues.

          The partnership will enter into a drilling and operating agreement
          with Atlas Resources to drill and complete all of the partnership
          wells for an amount equal to the sum of the following items (i) the
          cost of permits, supplies, materials, equipment, and all other items
          used in the drilling and completion of a well provided by
          third-parties, or if the foregoing items are provided by affiliates of
          the managing general partner, then those items will be charged at
          competitive rates; (ii) fees for third-party services; (iii) fees for
          services provided by the managing general partner's affiliates, which
          will be charged at competitive rates; (iv) an administration and
          oversight fee of $15,000 per well, which will be charged to the
          investors as part of each well's intangible drilling costs and the
          portion of equipment costs paid by the investors; and (v) a mark-up in
          an amount equal to 15% of the sum of (i), (ii), (iii) and (iv), above,
          for the managing general partner's services as general drilling
          contractor. This will be proportionately reduced if the partnership's
          working interest in a well is less than 100%.


                                      F-5

<PAGE>

                      Atlas America Public 16-2007 (A) L.P.
                        (A Delaware Limited Partnership)

                    NOTES TO FINANCIAL STATEMENT (CONTINUED)

                               SEPTEMBER 30, 2006

4.   PARTICIPATION IN REVENUES AND COSTS (CONTINUED)

     (6)  The actual allocation of partnership revenues between the managing
          general partner and the investor partners will vary from the
          allocation described in (5) above if a portion of the managing general
          partner's partnership net production revenues is subordinated as
          described in note 7.

5.   TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES

     The Partnership intends to enter into the following significant
     transactions with Atlas Resources and its affiliates as provider under the
     Partnership agreement:

     The partnership will enter into a drilling and operating agreement with
     Atlas Resources to drill and complete all of the partnership wells for an
     amount equal to the sum of the following items (i) the cost of permits,
     supplies, materials, equipment, and all other items used in the drilling
     and completion of a well provided by third-parties, or if the foregoing
     items are provided by affiliates of the managing general partner, then
     those items will be charged at competitive rates; (ii) fees for third-party
     services; (iii) fees for services provided by the managing general
     partner's affiliates, which will be charged at competitive rates; (iv) an
     administration and oversight fee of $15,000 per well, which will be charged
     to the investors as part of each well's intangible drilling costs and the
     portion of equipment costs paid by the investors; and (v) a mark-up in an
     amount equal to 15% of the sum of (i), (ii), (iii) and (iv), above, for the
     managing general partner's services as general drilling contractor. This
     will be proportionately reduced if the partnership's working interest in a
     well is less than 100%. The cost of the wells will include all ordinary and
     actual costs of drilling, testing and completing the wells.

     Atlas Resources will receive an unaccountable, fixed payment reimbursement
     for its administrative costs at $75 per well per month, which will be
     proportionately reduced if the partnership's working interest in a well is
     less than 100%.

     Atlas Resources will receive well supervision fees for operating and
     maintaining the wells during producing operations at a competitive rate
     (currently the competitive rate is $362 per well per month in the primary
     and secondary drilling areas). The well supervision fees will be
     proportionately reduced if the partnership's working interest in a well is
     less than 100%.

     Atlas Resources will charge the partnership a fee for gathering and
     transportation at a competitive rate (currently 10% of the natural gas
     price).

     Atlas Resources will contribute all the undeveloped leases necessary to
     cover each of the partnership's prospects and will receive a credit for its
     capital account in the partnership equal to the cost of the leases
     (approximately $11,310 per prospect which will be proportionately reduced
     if the Partnership's working interest is the prospect is less than 100%).


                                      F-6

<PAGE>

                      Atlas America Public 16-2007 (A) L.P.
                        (A Delaware Limited Partnership)

                    NOTES TO FINANCIAL STATEMENT (CONTINUED)

                               SEPTEMBER 30, 2006

5.   TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES (CONTINUED)

     As the Managing General Partner, Atlas Resources will perform all
     administrative and management functions for the partnership including
     billing and collecting revenues and paying expenses. Atlas Resources will
     be reimbursed for all direct costs expended on behalf of the partnership.

6.   PURCHASE COMMITMENT

     Subject to certain conditions, investor partners may present their
     interests after five years from the partnership's first cash distribution
     from operations for purchase by the Managing General Partner. The Managing
     General Partner is not obligated to purchase more than 5% of the units in
     any calendar year. In the event that the Managing General Partner is unable
     to obtain the necessary funds, the Managing General Partner may suspend its
     purchase obligation.

7.   SUBORDINATION OF PORTION OF MANAGING GENERAL PARTNER'S NET PRODUCER REVENUE
     SHARE

     The Managing General Partner will subordinate up to 50% of its share of
     production revenues of the Partnership, net of related operating costs,
     direct costs, administrative costs, and all other costs not specifically
     allocated, to the receipt by the investor partners of cash distributions
     from the Partnership equal to at least 10% per unit, based on $10,000 per
     unit regardless of the actual price paid, determined on a cumulative basis,
     in each of the first five 12-month periods beginning with the Partnership's
     first cash distribution from operations.

8.   INDEMNIFICATION

     In order to limit the potential liability of the investor general partners
     for partnership liabilities and obligations, Atlas Resources has agreed to
     indemnify each investor general partner from any liability incurred which
     exceeds such partner's share of undistributed Partnership net assets and
     insurance proceeds.


                                      F-7

<PAGE>

             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors
ATLAS RESOURCES, INC.

We have audited the accompanying consolidated balance sheets of ATLAS RESOURCES,
INC. (a Pennsylvania corporation) and subsidiaries as of September 30, 2005 and
2004, and the related consolidated statements of income, changes in
stockholder's equity, and cash flows for the years then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. The Company is not required to
have, nor were we engaged to perform an audit of its internal control over
financial reporting. Our audit included consideration of internal control over
financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company's internal control over financial
reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of ATLAS RESOURCES,
INC. and subsidiaries as of September 30, 2005 and 2004, and the consolidated
results of their operations and cash flows for the years then ended, in
conformity with accounting principles generally accepted in the United States of
America.


/s/ Grant Thornton LLP
-------------------------------------
Cleveland, Ohio
January 6, 2006 (except for Note 10, as to which the date is April 7, 2006)


                                      F-8

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
                           CONSOLIDATED BALANCE SHEETS
                           SEPTEMBER 30, 2005 AND 2004

<TABLE>
<CAPTION>
                                                                                2005       2004
                                                                              --------   --------
                                                                                 (In thousands,
                                                                               except share data)
<S>                                                                           <C>        <C>
ASSETS
Current assets:
   Cash and cash equivalents ..............................................   $  2,856   $    242
   Accounts receivable ....................................................      9,735      7,080
   Prepaid expenses .......................................................      2,172      1,488
                                                                              --------   --------
      Total current assets ................................................     14,763      8,810
Property and equipment:
   Oil and gas properties and equipment (successful efforts) ..............    184,009    120,506
   Buildings and land .....................................................      3,000      2,947
   Other ..................................................................        389        368
                                                                              --------   --------
                                                                               187,398    123,821
Less - accumulated depreciation, depletion, and amortization ..............    (32,719)   (23,654)
                                                                              --------   --------
   Net property and equipment .............................................    154,679    100,167
Goodwill (net of accumulated amortization of $2,320) ......................     20,868     20,868
Intangible assets (net of accumulated amortization of $3,385 and $2,909)...      3,028      3,444
                                                                              --------   --------
                                                                              $193,338   $133,289
                                                                              ========   ========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
   Current portion of long-term debt ......................................   $     59   $     56
   Accounts payable .......................................................      7,054      5,304
   Liabilities associated with drilling contracts .........................     60,971     29,375
   Accrued liabilities ....................................................      4,928      3,174
   Advances and note from parent ..........................................     72,603     66,725
                                                                              --------   --------
      Total current liabilities ...........................................    145,615    104,634
Asset retirement obligation ...............................................      5,415      1,910
Long-term debt ............................................................         22         82
Stockholder's equity:
   Common stock, stated at $10 per share;
      500 authorized shares; 200 shares issued and outstanding ............          2          2
   Additional paid-in capital .............................................     30,505     16,505
   Retained earnings ......................................................     11,779     10,156
                                                                              --------   --------
      Total stockholder's equity ..........................................     42,286     26,663
                                                                              --------   --------
                                                                              $193,338   $133,289
                                                                              ========   ========
</TABLE>

           See accompanying notes to consolidated financial statements


                                      F-9

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
                        CONSOLIDATED STATEMENTS OF INCOME
                     YEARS ENDED SEPTEMBER 30, 2005 AND 2004

                                                               2005       2004
                                                             --------   --------
                                                                (In thousands)
REVENUES
Well drilling ............................................   $134,623   $ 86,880
Gas and oil production ...................................     34,042     23,098
Well services ............................................      5,991      4,137
Transportation ...........................................      2,275      2,476
Other income .............................................         --         44
                                                             --------   --------
                                                              176,931    116,635
COSTS AND EXPENSES
Well drilling ............................................    116,816     75,548
Gas and oil production and exploration ...................      4,224      2,580
Well services ............................................      2,287      1,648
Non-direct ...............................................     38,886     24,831
Depreciation, depletion and amortization .................     10,409      8,197
Interest .................................................      2,206      2,625
                                                             --------   --------
                                                              174,828    115,429
                                                             --------   --------
Income from operations before income taxes ...............      2,103      1,206
Provision for income taxes ...............................        480        217
                                                             --------   --------
Net income ...............................................   $  1,623   $    989
                                                             ========   ========

           See accompanying notes to consolidated financial statements


                                      F-10

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
           CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
                     YEARS ENDED SEPTEMBER 30, 2005 AND 2004
                        (In thousands, except share data)

<TABLE>
<CAPTION>
                                                                    ACCUMULATED
                                                      ADDITIONAL       OTHER                      TOTAL
                                     COMMON STOCK       PAID-IN    COMPREHENSIVE   RETAINED   STOCKHOLDER'S
                                    SHARES   AMOUNT     CAPITAL    INCOME (LOSS)   EARNINGS       EQUITY
                                    ---------------   ----------   -------------   --------   -------------
<S>                                   <C>      <C>      <C>             <C>         <C>          <C>
Balance, September 30, 2003......     200      $ 2      $16,505         $--         $ 9,167      $25,674
Net income.......................      --       --           --          --             989          989
                                      ---      ---      -------         ---         -------      -------
Balance, September 30, 2004......     200        2       16,505          --          10,156       26,663
                                      ---      ---      -------         ---         -------      -------
Contributed capital..............      --       --       14,000          --              --       14,000
Net income.......................      --       --           --          --           1,623        1,623
                                      ---      ---      -------         ---         -------      -------
Balance, September 30, 2005           200      $ 2      $30,505         $--         $11,779      $42,286
                                      ===      ===      =======         ===         =======      =======
</TABLE>

           See accompanying notes to consolidated financial statements


                                      F-11

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                     YEARS ENDED SEPTEMBER 30, 2005 AND 2004

<TABLE>
<CAPTION>
                                                                                      2005       2004
                                                                                    --------   --------
                                                                                       (In thousands)
<S>                                                                                 <C>        <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ......................................................................   $  1,623   $    989
Adjustments to reconcile net income to net cash provided by operating activities:
   Depreciation, depletion and amortization .....................................     10,409      8,197
   Management fees, cost allocations and inter company interest allocated
      from affiliates ...........................................................     49,465     32,809
   Gain on sale of assets .......................................................        (22)       (11)
   Change in operating assets and liabilities ...................................     31,691      4,016
                                                                                    --------   --------
Net cash provided by operating activities .......................................     93,166     46,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ............................................................    (60,216)   (33,051)
Proceeds from sale of assets ....................................................         24         33
                                                                                    --------   --------
Net cash used in investing activities ...........................................    (60,192)   (33,018)
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments on borrowings ................................................        (57)       (56)
Net payments to affiliates ......................................................    (30,303)   (17,386)
                                                                                    --------   --------
Net cash used in financing activities ...........................................    (30,360)   (17,442)
                                                                                    --------   --------
Increase (decrease) in cash and cash equivalents ................................      2,614     (4,460)
Cash and cash equivalents at beginning of year ..................................        242      4,702
                                                                                    --------   --------
Cash and cash equivalents at end of year ........................................   $  2,856   $    242
                                                                                    ========   ========
</TABLE>

           See accompanying notes to consolidated financial statements


                                      F-12

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                               SEPTEMBER 30, 2005

NOTE 1 - NATURE OF OPERATIONS

     Atlas Resources, Inc. (the "Company"), a Pennsylvania corporation, and its
subsidiary, ARD Investments, are engaged in the exploration for development and
production of natural gas and oil primarily in the Appalachian Basin Area. In
addition, the Company performs contract drilling and well operation services.

     The Company is a second-tier wholly-owned subsidiary of Atlas America, Inc.
("Atlas"), a publicly traded company trading under the symbol ATLS on the NASDAQ
System. The Company's operations are dependent upon the resources and services
provided by Atlas. The Company finances a substantial portion of its drilling
activities through drilling partnerships it sponsors and typically acts as the
managing general partner of and has a material interest in these partnerships.

SPIN-OFF OF ATLAS FROM RESOURCE AMERICA, INC.

     On June 30, 2005, Resource America, Inc. ("RAI") the Company's former
indirect Parent, distributed its remaining 10.7 million shares of Atlas to its
stockholders in the form of a tax-free dividend. Although the distribution
itself is tax-free to RAI stockholders, as a result of the deconsolidation there
may be some tax liability arising from prior unrelated corporate transactions
among Atlas and some of its subsidiaries. Atlas (and the Company) no longer
consolidates with RAI as of June 30, 2005. The Company does not anticipate that
there will be a direct material impact on its financial position or results of
operations.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION

     The consolidated financial statements include the accounts of the Company
and its wholly owned subsidiary. The Company also owns individual interests in
the assets, and is separately liable for its share of the liabilities of energy
partnerships, whose activities include only exploration and production
activities. In accordance with established practice in the oil and gas industry,
the Company includes in its consolidated financial statements its pro-rata share
of assets, liabilities, income and costs and expenses of the energy partnerships
in which it has an interest. All material intercompany transactions have been
eliminated.

USE OF ESTIMATES

     Preparation of the consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and the disclosure of contingent assets and
liabilities as of the date of the consolidated financial statements and the
reported amounts of revenues and costs and expenses during the reporting period.
Actual results could differ from these estimates.


                                      F-13

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

RECLASSIFICATIONS

     Certain reclassifications have been made to the fiscal 2004 consolidated
financial statements to conform to the fiscal 2005 presentation.

COMPREHENSIVE INCOME

     Comprehensive income includes net income and all other changes in the
equity of a business during a period from transactions and other events and
circumstances from non-owner sources. There are no elements of comprehensive
income, other than net income, to report.

RECEIVABLES

     In evaluating its allowance for possible losses, the Company performs
ongoing credit evaluations of its customers and adjusts credit limits based upon
payment history and the customers' current creditworthiness, as determined by
the Company's review of its customers' credit information. The Company extends
credit on an unsecured basis to many of its energy customers. At September 30,
2005 and 2004, the Company's credit evaluation indicated that it has no need for
an allowance for possible losses.

PROPERTY AND EQUIPMENT

     Property and equipment is stated at cost. Depreciation, depletion and
amortization is based on cost less estimated salvage value primarily using the
unit-of-production or straight line method over the assets' estimated useful
lives. Maintenance and repairs are expensed as incurred. Major renewals and
improvements that extend the useful lives of property are capitalized.

     The estimated service lives of property and equipment are as follows:

Pipelines, processing and compression facilities.......   15-35 years
Rights-of-way - Mid-Continent..........................      40 years
Rights-of-way - Appalachia.............................      20 years
Land, building and improvements........................   10-40 years
Furniture and equipment................................     3-7 years
Other..................................................    3-10 years


                                      F-14

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

PROPERTY AND EQUIPMENT (CONTINUED)

     Property and equipment consists of the following at the dates indicated:

                                                            AT SEPTEMBER 30,
                                                          -------------------
                                                            2005       2004
                                                          --------   --------
                                                             (In thousands)
Mineral interest in properties:
   Proved properties...................................   $  2,009   $  1,701
   Unproved properties.................................        465        463
Wells and related equipment............................    179,818    117,242
Support equipment......................................      1,717      1,100
Other..................................................      3,389      3,315
                                                          --------   --------
                                                           187,398    123,821
Accumulated depreciation, depletion, amortization and
valuation allowances:..................................
   Oil and gas properties..............................    (31,320)   (22,623)
   Other...............................................     (1,399)    (1,031)
                                                          --------   --------
                                                           (32,719)   (23,654)
                                                          --------   --------
                                                          $154,679   $100,167
                                                          ========   ========

OIL AND GAS PROPERTIES

     The Company follows the successful efforts method of accounting for oil and
gas producing activities. Exploratory drilling costs are capitalized pending
determination of whether a well is successful. Exploratory wells subsequently
determined to be dry holes are charged to expense. Costs resulting in
exploratory discoveries and all development costs, whether successful or not,
are capitalized. Geological and geophysical costs, delay rentals and
unsuccessful exploratory wells are expensed. Oil is converted to gas equivalent
basis ("mcfe") at the rate one-barrel equals 6 mcf. Depletion is provided on the
units-of-production method. Unproved properties are reviewed for impairment
annually, or whenever events or circumstances indicate that the carrying amount
of an asset may not be recoverable. An impairment charge would be recognized if
conditions indicated that the Company would not explore the acreage prior to
expiration of applicable leases or if the carrying value of the property
exceeded its fair value.

     The Company's long-lived assets are reviewed for impairment annually for
events or changes in circumstances that indicate that the carrying amount of an
asset may not be recoverable. Long-lived assets are reviewed for potential
impairment at the lowest levels for which there are identifiable cash flows that
are largely independent of other groups of assets. The review is done by
determining if the historical cost of proved properties less the applicable
accumulated depreciation, depletion and amortization and reserve for abandonment
is less than the estimated expected undiscounted future cash flows. The expected
future cash flows are estimated based on the Company's plans to continue to
produce and develop proved reserves. The expected future cash flows from the
sale of the production of reserves is calculated using estimated future prices
based upon market related information available to the Company, which includes


                                      F-15

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

OIL AND GAS PROPERTIES (CONTINUED)

published futures prices. The estimated future level of production is based on
assumptions surrounding future levels of prices and costs, field decline rates,
market demand and supply, and the economic and regulatory climates. If the
carrying value exceeds such cash flows, an impairment loss is recognized for the
difference between the estimated fair market value (as determined by discounted
future cash flows), and the carrying value of the assets.

     Upon the sale or retirement of a complete unit of a proved property, its
cost is eliminated from the property accounts, and the resultant gain or loss is
reclassified to accumulated depletion. Upon the sale of an entire interest in an
unproved property that has been assessed for impairment individually, a gain or
loss is recognized in the statement of operations. If a partial interest in an
unproved property is sold, any funds received reduce the cost in the interest
retained.

ASSET RETIREMENT OBLIGATION

     If a reasonable estimate of the fair values of asset retirement obligations
can be made, such obligations are recorded when assets are acquired. Changes to
the estimated fair values of the assets are recorded in the period in which they
occur. Asset retirement obligations primarily relate to the abandonment of oil
and gas producing facilities and include costs to dismantle and relocate or
dispose of production equipment, gathering systems, wells and related
structures. Estimates, which are based on historical experience in plugging and
abandoning wells, include estimated remaining lives of the wells based on
reserve estimates, external estimates as to the cost to plug and abandon the
wells in the future and federal and state regulatory requirements. The Company
does not provide for a market risk premium associated with asset retirement
obligations because a reliable estimate cannot be determined.

FAIR VALUE OF FINANCIAL INSTRUMENTS

     The Company uses the following methods and assumptions in estimating the
fair value of each class of financial instruments for which it is practicable to
estimate fair value.

     For cash and cash equivalents, receivables and payables, the carrying
amounts approximate fair value because of the short maturity of these
instruments.

     For long-term debt, the carrying value approximates fair value because
interest rates approximate current market rates.

CONCENTRATION OF CREDIT RISK

     Financial instruments that potentially subject the Company to
concentrations of credit risk consist principally of periodic temporary
investments of cash. The Company places its temporary cash investments in
high-quality short-term money market instruments and deposits with high-quality
financial institutions and brokerage firms. At September 30, 2005, the Company
had $2,925,900 in deposits at various banks, of which $2,825,900 is over the
insurance limit of the Federal Deposit Insurance Corporation. No losses have
been experienced on such investments.


                                      F-16

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

ENVIRONMENTAL MATTERS

     The Company is subject to various federal, state and local laws and
regulations relating to the protection of the environment. The Company has
established procedures for the ongoing evaluation of its operations to identify
potential environmental exposures and to comply with regulatory policies and
procedures.

     The Company accounts for environmental contingencies in accordance with
SFAS No. 5 "Accounting for Contingencies." Environmental expenditures that
relate to current operations are expensed or capitalized as appropriate.
Expenditures that relate to an existing condition caused by past operations, and
do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are
probable, and the costs can be reasonably estimated. The Company maintains
insurance that may cover in whole or in part certain environmental expenditures.
For the two years ended September 30, 2005 and 2004, the Company had no
environmental matters requiring specific disclosure or the recording of a
liability.

REVENUE RECOGNITION

     The Company conducts certain energy activities through, and a portion of
its revenues is attributable to, sponsored energy limited partnerships. These
energy partnerships raise capital from investors to drill gas and oil wells. The
income from the Company's general partner interest is recorded when the gas and
oil are sold by a partnership.

     The Company contracts with the energy partnerships to drill partnership
wells. The contracts require that the energy partnerships must pay the Company
the full contract price upon execution. The income from a drilling contract is
recognized as the services are performed using the percentage of completion
method. The contracts are typically completed in less than 60 days. The Company
classifies the difference between the contract payments it has received and the
revenue earned as a current liability, included in liabilities associated with
drilling contracts.

     The Company recognizes transportation revenues at the time the natural gas
is delivered to the purchaser.

     The Company recognizes well services revenues at the time the services are
performed.

     The Company is entitled to receive well operating and management fees
according to the respective partnership agreements. The Company recognizes well
operating and management fees as income when earned and includes them in well
services revenues.


                                      F-17

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

SUPPLEMENTAL CASH FLOW INFORMATION

     The Company considers temporary investments with maturity at the date of
acquisition of 90 days or less to be cash equivalents.

                                    YEARS ENDED
                                   SEPTEMBER 30,
                                  --------------
                                   2005     2004
                                  ------   ------
                                   (In thousands)
CASH PAID DURING THE YEARS FOR:
Interest.......................    $628     $   3
Income taxes paid (refunded)...    $  1     $(223)

INCOME TAXES

     The Company is included in the consolidated federal income tax return of
its Parent. Income taxes are reported by the Company in amounts consistent with
what the Company's estimated taxes would have been had it filed a return on a
separate company basis utilizing its calculated effective rate of 23% and 18%
for fiscal years 2005 and 2004 respectively. The Company's effective tax rate is
lower than the federal statutory rate due to the benefit of percentage
depletion. Deferred tax assets and liabilities, which have been transferred to
the Parent since it files the consolidated tax return, are included in Advances
and note from Parent. These deferred taxes reflect the tax effect of temporary
differences between the tax bases of the Company's assets and liabilities and
the amounts reported in the financial statements. Separate company state tax
returns are filed in those states in which the Company is registered to do
business.

RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS

     In May 2005, the Financial Accounting Standards Board, ("FASB") issued
Statement No.154, Accounting Changes and Error Corrections ("SFAS 154"). SFAS
154 requires retrospective application to prior periods' financial statements of
changes in accounting principle. It also requires that the new accounting
principle be applied to the balances of assets and liabilities as of the
beginning of the earliest period for which retrospective application is
practicable and that a corresponding adjustment be made to the opening balance
of retained earnings for that period rather than being reported in an income
statement. The statement will be effective for accounting changes and
corrections of errors made in fiscal years beginning after December 15, 2005.
The impact of SFAS 154 will depend on the nature and extent of any voluntary
accounting changes and correction of errors after the effective date, but
management does not currently expect SFAS 154 to have a material impact on the
Company's financial position or results of operations.


                                      F-18

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS (CONTINUED)

     In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for
Conditional Asset Retirement Obligations ("FIN 47"), which will result in (a)
more consistent recognition of liabilities relating to asset retirement
obligations, (b) more information about expected future cash outflows associated
with those obligations, and (c) more information about investments in long-lived
assets because additional asset retirement cost will be recognized as part of
the carrying amounts of the assets. FIN 47 clarifies that the term conditional
asset retirement obligation as used in SFAS No. 143, Accounting for Asset
Retirement Obligations, refers to a legal obligation to perform an asset
retirement activity in which the timing and (or) method of settlement are
conditional on a future event that may or may not be within the control of the
entity. The obligation to perform the asset retirement activity is unconditional
even though uncertainty exists about the timing and (or) method of settlement.
Uncertainty about the timing and (or) method of settlement of a conditional
asset retirement obligation should be factored into the measurement of the
liability when sufficient information exists. FIN 47 also clarifies when an
entity would have sufficient information to reasonably estimate the fair value
of an asset retirement obligation. FIN 47 is effective no later than the end of
fiscal years ending after December 15, 2005. Retrospective application of
interim financial information is permitted, but not required. Early adoption of
this interpretation is encouraged. Management does not believe the
interpretation will have a significant impact on the Company's financial
position or results of operations.

     In December 2004, the FASB issued FASB Staff Position No. FSP 109-1 ("FSP
109-1"), Application of FASB Statement No. 109, Accounting for Income Taxes, to
the Tax Deduction on Qualified Production Activities Provided by the American
Jobs Creation Act of 2004 ("AJCA"). The AJCA introduces a special 9% tax
deduction on qualified production activities. FSP 109-1 concludes that this
deduction should be accounted for as a special tax deduction in accordance with
SFAS No. 109. As such, the special deduction has no effect on deferred tax
assets and liabilities existing at the enactment date. Rather, the impact of
this deduction will be reported in the same period in which the deduction is
claimed in the Company's tax return. FSP 109-1 is not expected to have a
material impact on the Company's financial position or results of operations.

NOTE 3 -- OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL

INTANGIBLE ASSETS

     Intangible assets consist of partnership management and operating contracts
acquired through acquisitions and recorded at fair value on their acquisition
dates. The Company amortizes contracts acquired on a declining balance method,
over their respective estimated lives, ranging from five to thirteen years.
Amortization expense for the years ended September 30, 2005 and 2004 was
approximately $478,000. The estimated amortization expense for each of the next
five fiscal years is approximately $478,000.

GOODWILL

     The Company applies the provisions of SFAS No. 142 ("SFAS 142") Goodwill
and Other Intangible Assets, which requires that goodwill no longer be
amortized, but instead evaluated for impairment at least annually. The
evaluation of impairment under SFAS 142 requires the use of projections,
estimates and assumptions as to the future performance of the Company's
operations, including anticipated future revenues, expected future operating
costs and the discount factor used. Actual results could differ from
projections, resulting in revisions to the Company's assumptions and, if
required, recognition of an impairment loss. The Company evaluated goodwill and
determined that there was no impairment at September 30, 2005. The Company will
continue to evaluate its goodwill at least annually and will reflect the
impairment of goodwill, if any, within the consolidated statements of income in
the period in which such impairment is indicated.


                                      F-19

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 4 - ASSET RETIREMENT OBLIGATION

     Effective October 1, 2002, the Company adopted the SFAS No. 143, Accounting
for Asset Retirement Obligations ("SFAS 143") which requires the Company to
recognize an estimated liability for the plugging and abandonment of its oil and
gas wells and associated pipelines and equipment. Under SFAS 143, the Company
must currently recognize a liability for future asset retirement obligations if
a reasonable estimate of the fair value of that liability can be made. The
associated asset retirement costs are capitalized as part of the carrying amount
of the long lived asset. SFAS 143 requires the Company to consider estimated
salvage value in the calculation of depreciation, depletion and amortization.
Consistent with industry practice, historically the Company had determined the
cost of plugging and abandonment on its oil and gas properties would be offset
by salvage values received. The adoption of SFAS 143 resulted in (i) an increase
of total liabilities because retirement obligations are required to be
recognized, (ii) an increase in the recognized cost of assets because the
retirement costs are added to the carrying amount of the long-lived assets and
(iii) a decrease in depletion expense, because the estimated salvage values are
now considered in the depletion calculation.

     The Company determines the estimated liability based upon its historical
experience in plugging and abandoning wells. The estimate includes consideration
of the remaining lives of the wells based on reserve estimates, external
estimates as to the cost to plug and abandon the wells in the future and federal
and state regulatory requirements. The liability is discounted using an assumed
credit-adjusted risk-free interest rate. Revisions to the liability could occur
due to changes in estimates of plugging and abandonment costs or remaining lives
of the wells, or if federal or state regulators enact new plugging and
abandonment requirements. The increase in asset retirement obligations in fiscal
2005 was due to an upward revision in the estimated cost of plugging and
abandoning wells.

     The Company has no assets legally restricted for purposes of settling asset
retirement obligations. The Company has determined that there are no material
retirement obligations associated with tangible long-lived assets.

     A reconciliation of the Company's liability for well plugging and
abandonment costs for the years ended September 30, 2005 and 2004 is as follows
(in thousands):

                                                     2005     2004
                                                    ------   ------
Asset retirement obligation, beginning of year...   $1,910   $  701
Liabilities incurred.............................      770    1,212
Liabilities settled..............................       (8)     (40)
Revision in estimates............................    2,593      (60)
Accretion expense................................      150       97
                                                    ------   ------
Asset retirement obligation, end of year.........   $5,415   $1,910
                                                    ======   ======

     The above accretion expense is included in depreciation, depletion and
amortization in the Company's consolidated statements of income.

NOTE 5 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     The Company conducts certain energy activities through, and a substantial
portion of its revenues is attributable to, energy-limited partnerships
("Partnerships"). The Company serves as general partner of the Partnerships and
assumes customary rights and obligations for the Partnerships. As the general
partner, the Company is liable for Partnership liabilities and can be liable to
limited partners if it breaches its responsibilities with respect to the
operations of the Partnerships. The Company is entitled to receive management
fees, reimbursement for administrative costs incurred, and to share in the
Partnerships' revenues, costs and expenses according to the respective
Partnership agreements.


                                      F-20

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 5 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS (CONTINUED)

     Advances and note from Parent represents amounts owed for advances and
transactions in the normal course of business. Both the note and the advances
are subordinated to any third party debt. During fiscal 2005 the note due to
Parent was reclassified to contributed capital. Interest expense related to the
note was $1.6 million and $2.1 million for the years ended September 30, 2005
and 2004. The advances have no repayment terms, therefore, the Company has
classified the amounts due the Parent as a current liability on its Consolidated
Balance Sheets.

     The Company is dependent on its Parent for management and administrative
functions and financing for its capital expenditures. The Company paid
management fees to its Parent of $47.3 million and $23.7 million for the years
ended September 30, 2005 and 2004, respectively.

NOTE 6 - DEBT

     During the fiscal year ended September 30, 2003, the Company entered into
two loans through General Motors Acceptance Corporation to finance the purchase
of ten trucks used in its well drilling and oil and gas production activities.
One loan had a principal balance at September 30, 2005 and 2004 of $41,000 and
$69,300, respectively, and bears interest at an annual rate of 1.9%. The second
loan had a principal balance at September 30, 2005 and 2004 of $40,000 and
$69,000, respectively, and bears interest at an annual rate of 2.9%. The current
portion of the long-term debt for the periods ended September 30, 2005 and 2004
were $59,000 and $56,000, respectively. Both loans had an original term of 48
months.

NOTE 7 - COMMITMENTS AND CONTINGENCIES

     The Company is the managing general partner of various energy partnerships,
and has agreed to indemnify each investor partner from any liability that
exceeds such partner's share of partnership assets. Subject to certain
conditions, investor partners in certain energy partnerships have the right to
present their interests for purchase by the Company, as managing general
partner. The Company is not obligated to purchase more than 5% to 10% of the
units in any calendar year. Based on past experience, the Company believes that
any liability incurred would not be material.

     The Company may be required to subordinate a part of its net partnership
revenues to the receipt by investor partners of cash distributions from the
energy partnerships equal to at least 10% of their agreed subscriptions
determined on a cumulative basis, in accordance with the terms of the
partnership agreements.

     The Parent may draw from its revolving credit facility on behalf of the
Company. In March 2004, the Company's parent entered into a credit facility led
by Wachovia Bank, which has a current borrowing base of $75.0 million. The
facility permits draws based on the remaining proved developed non-producing and
proved undeveloped natural gas and oil reserves attributable to the Parent's
wells and the projected fees and revenues from operation of the wells and the
administration of the energy partnerships. Up to $50.0 million of the facility
may be in the form of standby letters of credit. The facility is secured by the
Parent's assets, including those of the Company.

     The revolving credit facility has a term ending in March 2007, when all
outstanding borrowings must be repaid. Borrowings bear interest at one of two
rates (elected at the borrower's option) which increase as the amount
outstanding under the facility increases: (i) Wachovia prime rate plus between
25 to 75 basis points, or (ii) LIBOR plus between 175 and 225 basis points. At
September 30, 2005 and 2004, the parent had $9.5 million and $26.7 million,
respectively, outstanding under this facility, including $1.5 million and $1.7
million at September 30, 2005 and 2004 under letters of credit. The interest
rates ranged from 5.52% to 7.0% at September 30, 2005.


                                      F-21

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 7 - COMMITMENTS AND CONTINGENCIES (CONTINUED)

     The Company is a party to various routine legal proceedings arising out of
the ordinary course of its business. Management believes that none of these
actions, individually or in the aggregate, will have a material adverse effect
on the Company's financial position or results of operations.

NOTE 8 - MAJOR CUSTOMERS

     The Company's natural gas is sold under contract to various purchasers. For
the year ended September 30, 2005, gas sales to Amerada Hess Corporation
(formerly First Energy Solutions Corporation) and UGI Energy Services accounted
for 52% and 30%, respectively, of total revenues. For the year ended September
30, 2004, First Energy Solutions Corporation accounted for 10% of total
revenues. No other customer accounted for 10% or more of total revenues for the
years ended September 30, 2005 and 2004.

NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION

     Results of operations from oil and gas producing activities:

<TABLE>
<CAPTION>
                                                                 YEARS ENDED SEPTEMBER 30,
                                                                 -------------------------
                                                                       2005      2004
                                                                     -------   -------
                                                                       (In thousands)
<S>                                                                  <C>       <C>
Revenues......................................................       $34,042   $23,098
Production costs..............................................        (3,320)   (2,107)
Exploration expenses..........................................          (904)     (473)
Depreciation, depletion and amortization......................        (9,562)   (7,445)
Income taxes..................................................        (8,013)   (4,256)
                                                                     -------   -------
Results of operations from oil and gas producing activities...       $12,243   $ 8,817
                                                                     =======   =======
</TABLE>

     Capitalized Costs Related to Oil and Gas Producing Activities. The
components of capitalized costs related to the Company's oil and gas-producing
activities are as follows:

<TABLE>
<CAPTION>
                                                                                  AT SEPTEMBER 30,
                                                                                -------------------
                                                                                  2005       2004
                                                                                --------   --------
                                                                                   (In thousands)
<S>                                                                             <C>        <C>
Proved properties............................................................   $  2,009   $  1,701
Unproved properties..........................................................        465        463
Wells and related equipment and facilities...................................    179,818    117,242
Support equipment and facilities.............................................      1,717      1,100
                                                                                --------   --------
                                                                                $184,009   $120,506
Accumulated depreciation, depletion, amortization and valuation allowances...    (31,320)   (22,623)
                                                                                --------   --------
Net capitalized costs........................................................   $152,688   $ 97,883
                                                                                ========   ========
</TABLE>


                                      F-22

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION (Continued)

     Costs Incurred in Oil and Gas Producing Activities. The costs incurred by
the Company in its oil and gas activities during the periods indicated are as
follows:

                                       YEARS ENDED SEPTEMBER 30,
                                       -------------------------
                                             2005      2004
                                           -------   -------
                                             (In thousands)
Property acquisition costs:
Unproved properties.................       $    --   $   438
Exploration costs...................       $   904   $   473
Development costs...................       $59,524   $32,766

     The development costs above for the years ended September 30, 2005 and 2004
were substantially all incurred for the development of proved undeveloped
properties.

     Oil and Gas Reserve Information (Unaudited) The estimates of the Company's
proved and unproved gas reserves are based upon evaluations made by management
and verified by Wright & Company, Inc., an independent petroleum engineering
firm, as of September 30, 2005 and 2004. All reserves are located within the
United States. Reserves are estimated in accordance with guidelines established
by the Securities and Exchange Commission and the Financial Accounting Standards
Board, which require that reserve estimates be prepared under existing economic
and operating conditions with no provisions for price and cost escalation except
by contractual arrangements.

     Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas, and natural gas liquids, which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, i.e. prices
and costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.

     o    Reservoirs are considered proved if economic feasibility is supported
          by either actual production or conclusive formation tests. The area of
          a reservoir considered proved includes (a) that portion delineated by
          drilling and defined by gas-oil and/or oil-water contacts, if any; and
          (b) the immediately adjoining portions not yet drilled, but which can
          be reasonably judged as economically productive on the basis of
          available geological and engineering data. In the absence of
          information on fluid contacts, the lowest known structural occurrence
          of hydrocarbons controls the lower proved limit of the reservoir.


                                      F-23

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION (CONTINUED)

     o    Reserves which can be produced economically through application of
          improved recovery techniques (such as fluid injection) are included in
          the "proved" classification when successful testing by a pilot
          project, or the operation of an installed program in the reservoir,
          provides support for the engineering analysis on which the project or
          program was based.

     o    Estimates of proved reserves do not include the following: (a) oil
          that may become available from known reservoirs but is classified
          separately as "indicated additional reservoirs"; (b) crude oil,
          natural gas, and natural gas liquids, the recovery of which is subject
          to reasonable doubt because of uncertainty as to geology, reservoir
          characteristics or economic factors; (c) crude oil, natural gas and
          natural gas liquids, that may occur in undrilled prospects; and (d)
          crude oil and natural gas, and natural gas liquids, that may be
          recovered from oil shale's, coal, gilsonite and other such sources.

     Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operation
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.

     There are numerous uncertainties inherent in estimating quantities of
proven reserves and in projecting future net revenues and the timing of
development expenditures. The reserve data presented represents estimates only
and should not be construed as being exact. In addition, the standardized
measure of discounted future net cash flows may not represent the fair market
value of the Company's oil and gas reserves or the present value of future cash
flows of equivalent reserves, due to anticipated future changes in oil and gas
prices and in production and development costs and other factors for effects
have not been proved.


                                      F-24

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION (CONTINUED)

     The Company's reconciliation of changes in proved reserve quantities is as
follows (unaudited):

                                                         GAS          OIL
                                                        (Mcf)       (Bbls)
                                                     -----------   --------
Balance at September 30, 2003                         83,830,378     62,415
   Current additions..............................    26,806,939    235,902
   Transfers to limited partnerships..............    (7,808,942)   (15,217)
   Revisions......................................    (6,493,890)    (7,135)
   Production.....................................    (3,872,923)   (15,898)
                                                     -----------    -------
Balance at September 30, 2004                         92,461,562    260,067
   Current additions..............................    31,509,029    173,068
   Transfers to limited partnerships..............    (5,397,575)  (147,153)
   Revisions......................................    (4,739,866)   (41,575)
   Production.....................................    (4,548,987)   (22,972)
                                                     -----------    -------
Balance at September 30, 2005                        109,284,163    221,435
Proved developed reserves at:
   September 30, 2005.............................    56,043,521     78,558
   September 30, 2004.............................    46,580,498    111,168

     The following schedule presents the standardized measure of estimated
discounted future net cash flows relating to proved oil and gas reserves. The
estimated future production is priced at fiscal year-end prices, adjusted only
for fixed and determinable increases in natural gas and oil prices provided by
contractual agreements. The resulting estimated future cash inflows are reduced
by estimated future costs to develop and produce the proved reserves based on
fiscal year-end cost levels. The future net cash flows are reduced to present
value amounts by applying a 10% discount factor. The standardized measure of
future cash flows was prepared using the prevailing economic conditions existing
at September 30, 2005 and 2004 and such conditions continually change.


                                      F-25

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION (Continued)

     Accordingly, such information should not serve as a basis in making any
judgment on the potential value of recoverable reserves or in estimating future
results of operations (unaudited).

<TABLE>
<CAPTION>
                                                                          YEARS ENDED SEPTEMBER 30,
                                                                          -------------------------
                                                                              2005         2004
                                                                           ----------   ---------
                                                                               (In thousands)
<S>                                                                        <C>          <C>
Future cash inflows ...................................................    $1,616,657   $ 652,811
Future production costs................................................    $ (141,456)  $ (79,989)
Future development costs...............................................    $ (116,287)  $ (91,195)
Future income tax expense..............................................    $ (383,239)  $(122,962)
                                                                           ----------   ---------
Future net cash flows..................................................       975,675     358,665
   Less 10% annual discount for estimated timing of cash flows.........      (575,713)   (222,143)
                                                                           ----------   ---------
   Standardized measure of discounted future net cash flows............    $  399,962   $ 136,522
                                                                           ==========   =========
</TABLE>

     The future cash flows estimated to be spent to develop proved undeveloped
properties in the years ended September 30, 2005, 2006 and 2007 are $45.0
million, $46.0 million and $26.0 million, respectively.

     The following table summarizes the changes in the standardized measure of
discounted future net cash flows from estimated production of proved oil and gas
reserves after income taxes (unaudited):

<TABLE>
<CAPTION>
                                                                          YEARS ENDED SEPTEMBER 30,
                                                                          -------------------------
                                                                                2005       2004
                                                                             ---------   --------
<S>                                                                          <C>         <C>
Balance, beginning of year.............................................      $ 136,522   $ 77,734
Increase (decrease) in discounted future net cash flows:
   Sales and transfers of oil and gas, net of related costs............        (31,505)   (20,991)
   Net changes in prices and production costs..........................        265,150     59,345
   Revisions of previous quantity estimates............................        (22,272)   (10,197)
   Purchases of reserves in place......................................            458        270
   Estimated settlement of asset retirement obligations................           (201)    (1,209)
   Estimated proceeds on disposal of well equipment....................             72        190
   Development costs incurred..........................................          4,289      4,838
   Changes in future development costs.................................         (1,577)    (1,033)
   Transfers to limited partnerships...................................        (25,295)    (9,835)
   Extensions, discoveries, and improved recovery less related costs...        153,630     54,979
   Accretion of discount...............................................         17,942      9,697
   Net changes in future income taxes..................................       (104,412)   (23,737)
   Other...............................................................          7,161     (3,529)
                                                                             ---------   --------
 Balance, end of year..................................................      $ 399,962   $136,522
                                                                             =========   ========
</TABLE>


                                      F-26

<PAGE>

                      ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 10 - SUBSEQUENT EVENTS

     Atlas recently announced that it intends to form either a wholly-owned
limited liability company or limited partnership subsidiary and transfer to that
entity substantially all of its natural gas and oil exploration and production
assets. In connection with that contemplated transaction, in March 2006 the
Company was merged into a newly-formed limited liability company, Atlas
Resources, LLC, which is anticipated to become an indirect subsidiary of Atlas'
newly-formed subsidiary. Atlas Resources, LLC, however, will continue to serve
as managing general partner of its various energy partnerships, and does not
expect that any of these transactions will have a material effect on the
Partnerships' financial position or results of operations. Atlas further intends
to make a registered initial public offering of an estimated 20% minority
interest in its newly-formed subsidiary.


                                      F-27

<PAGE>

                        CONSOLIDATED FINANCIAL STATEMENTS
                                   (UNAUDITED)

                       ATLAS RESOURCES, LLC AND SUBSIDIARY

                                  JUNE 30, 2006


                                      F-28

<PAGE>

                       ATLAS RESOURCES, LLC AND SUBSIDIARY
                           CONSOLIDATED BALANCE SHEETS
                      (IN THOUSANDS, EXCEPT PER SHARE DATA)
                                   (UNAUDITED)

<TABLE>
<CAPTION>
                                                                           JUNE 30,   SEPTEMBER 30,
                                                                             2006         2005
                                                                           --------   -------------
<S>                                                                        <C>          <C>
ASSETS
Current assets:
   Cash and cash equivalents ...........................................   $    196     $  2,856
   Accounts receivable .................................................     13,003        9,735
   Prepaid expenses ....................................................      2,666        2,172
   Hedge receivable short term-affiliate ...............................      3,937           --
                                                                           --------     --------
      Total current assets .............................................     19,802       14,763
Property and equipment:
   Oil and gas properties and equipment (successful efforts) ...........    240,315      184,009
   Buildings and land ..................................................      3,000        3,000
   Other ...............................................................        424          389
                                                                           --------     --------
                                                                            243,739      187,398
Less - accumulated depreciation, depletion, and amortization ...........    (45,226)     (32,719)
                                                                           --------     --------
   Net property and equipment ..........................................    198,513      154,679
Other long term assets .................................................      5,293           --
Goodwill (net of accumulated amortization of $2,320) ...................     20,868       20,868
Intangible assets (net of accumulated amortization
   of $3,743 and $3,385) ...............................................      2,663        3,028
                                                                           --------     --------
                                                                           $247,139     $193,338
                                                                           ========     ========

LIABILITIES AND MEMBERS' EQUITY
Current liabilities:
   Current portion of long-term debt ...................................   $     67     $     59
   Accounts payable ....................................................      8,634        7,054
   Liabilities associated with drilling contracts ......................     88,810       60,971
   Accrued liabilities .................................................      5,999        4,928
   Accrued hedge liability .............................................         --           --
   Advances from parent ................................................     60,655       72,603
                                                                           --------     --------
      Total current liabilities ........................................    164,165      145,615
Asset retirement obligation ............................................      7,430        5,415
Long-term debt .........................................................         45           22
Hedge liability long term-affiliate ....................................      6,528           --
Members' equity:
   Common stock, stated at $10 per share;
      500 authorized shares; 200 shares issued and outstanding .........         --            2
   Additional paid-in capital ..........................................         --       30,505
Accumulated comprehensive income (loss) ................................      2,702           --
   Retained earnings ...................................................         --       11,779
                                                                                        --------
      Total stockholder's equity .......................................         --       42,286
Member's capital .......................................................     66,269           --
                                                                           --------     --------
      Total equity .....................................................     68,971           --
                                                                           --------     --------
                                                                           $247,139     $193,338
                                                                           ========     ========
</TABLE>

           See accompanying notes to consolidated financial statements


                                      F-29

<PAGE>

                       ATLAS RESOURCES, LLC AND SUBSIDIARY
                        CONSOLIDATED STATEMENTS OF INCOME
                    NINE MONTHS ENDED JUNE 30, 2006 AND 2005
                                   (UNAUDITED)

                                                               2006       2005
                                                             --------   --------
                                                               (In thousands)

REVENUES
Well construction and completion .........................   $126,833   $ 98,758
Gas and oil production ...................................     42,783     23,098
Well services ............................................      5,620      6,115
Transportation ...........................................      3,468         --
Administration and oversight .............................      6,232         --
                                                             --------   --------
                                                              184,936    127,971
COSTS AND EXPENSES
Well construction and completion .........................    110,288     85,876
Gas and oil production and exploration ...................      4,785      3,329
Well services ............................................      2,260      1,428
Non-direct ...............................................     45,610     26,315
Depreciation, depletion and amortization .................     13,031      6,813
Income tax benefit (see Note 9) ..........................    (15,246)        --
Interest expense - affiliates ............................        283      2,072
Other interest expense ...................................         44         72
Other (income) expense ...................................       (102)        66
                                                             --------   --------
                                                              160,953    125,971
                                                             --------   --------
Income from operations ...................................     23,983      2,000
Provision for income taxes ...............................         --        360
                                                             --------   --------
Net income ...............................................   $ 23,983   $  1,640
                                                             ========   ========

           See accompanying notes to consolidated financial statements


                                      F-30

<PAGE>

                       ATLAS RESOURCES, LLC AND SUBSIDIARY
              CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY
                         NINE MONTHS ENDED JUNE 30, 2006
                        (IN THOUSANDS, EXCEPT SHARE DATA)
                                   (UNAUDITED)

<TABLE>
<CAPTION>
                                                                       ACCUMULATED
                                         COMMON STOCK    ADDITIONAL       OTHER                  STOCKHOLDER'S                TOTAL
                                       ---------------     PAID-IN    COMPREHENSIVE   RETAINED   EQUITY BEFORE   MEMBER'S   MEMBER'S
                                       SHARES   AMOUNT     CAPITAL    INCOME (LOSS)   EARNINGS     CONVERSION     CAPITAL    EQUITY
                                       ------   ------   ----------   -------------   --------   -------------   --------   --------
<S>                                    <C>       <C>      <C>             <C>         <C>          <C>            <C>       <C>
Balance, October 1, 2005 ...........    200      $ 2      $ 30,505        $   --      $ 11,779     $ 42,286       $    --   $    --
Conversion of  Corporation to LLC ..   (200)      (2)      (30,505)           --       (11,779)     (42,286)       42,286    42,286
Other Comprehensive Income .........     --       --            --         2,702            --           --            --     2,702
Net Income .........................     --       --            --            --            --           --        23,983    23,983
                                        ---      ---      --------        ------      --------     --------       -------   -------
Balance, June 30, 2006 .............     --      $--      $     --        $2,702      $     --     $     --       $66,269   $68,971
                                        ===      ===      ========        ======      ========     ========       =======   =======
</TABLE>


                                      F-31

<PAGE>

                       ATLAS RESOURCES, LLC AND SUBSIDIARY
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                    NINE MONTHS ENDED JUNE 30, 2006 AND 2005
                                   (UNAUDITED)

<TABLE>
<CAPTION>
                                                                      2006       2005
                                                                    --------   --------
                                                                       (In thousands)
<S>                                                                 <C>        <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ......................................................   $ 23,983   $  1,640
   Adjustments to reconcile net income to net cash provided by
      operating activities:
   Depreciation, depletion and amortization .....................     13,031      6,813
   Management fees, cost allocations and intercompany interest
      allocated from affiliates .................................     45,074     32,435
   Deferred tax benefit .........................................    (16,896)        --
   Gain on disposal of assets ...................................        (12)       (15)
   Change in operating assets and liabilities ...................     26,735     29,914
                                                                    --------   --------
Net cash provided by operating activities .......................     91,915     70,787

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ............................................    (55,229)   (42,281)
Proceeds from sale of assets ....................................      1,336         17
                                                                    --------   --------
Net cash used in investing activities ...........................    (53,893)   (42,264)

CASH FLOWS FROM FINANCING ACTIVITIES:
Net payments on borrowings ......................................         31        (43)
Net payments to affiliates ......................................    (40,713)   (28,005)
                                                                    --------   --------
Net cash used in financing activities ...........................    (40,682)   (28,048)
                                                                    --------   --------
Decrease in cash and cash equivalents ...........................     (2,660)       475
Cash and cash equivalents at beginning of year ..................      2,856        242
                                                                    --------   --------
Cash and cash equivalents at end of year ........................   $    196   $    717
                                                                    ========   ========
</TABLE>

           See accompanying notes to consolidated financial statements


                                      F-32

<PAGE>

                       ATLAS RESOURCES, LLC AND SUBSIDIARY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                  JUNE 30, 2006
                                   (UNAUDITED)

NOTE 1 - NATURE OF OPERATIONS

     The consolidated financial statements of Atlas Resources, LLC and its
wholly-owned subsidiary (the "Company") as of June 30, 2006 are unaudited. Atlas
Resources, LLC is a wholly-owned subsidiary of Atlas America, Inc. (the "Parent"
or "Atlas"). These consolidated financial statements have been prepared in
accordance with accounting principles generally accepted in the United States of
America ("US GAAP") for interim financial information and certain rules and
regulations of the Securities and Exchange Commission. Accordingly, they do not
include all of the information and footnotes required by US GAAP for complete
financial statements. The results of operations for the nine months ended June
30, 2006 may not necessarily be indicative of the results of operations for the
full fiscal year ending September 30, 2006.

     Atlas America, Inc. recently announced that it intends to transfer
substantially all of its natural gas and oil exploration and production assets
into a newly-formed wholly-owned limited liability company subsidiary. In
connection with that transaction, the Company was formed on March 24, 2006 and
Atlas Resources, Inc. was merged into it. Atlas America, Inc. anticipates that
Atlas Resources, LLC will become an indirect subsidiary of its newly-formed
subsidiary Atlas Energy Resources, LLC ("Atlas Energy"), see Note 10. The assets
and liabilities of Atlas Resources, Inc. were transferred into Atlas Resources,
LLC without any changes to their cost bases. The shareholder's equity from Atlas
Resources, Inc. was transferred to member's equity in Atlas Resources LLC to
reflect the entity's change from a corporation to a limited liability company.
The results of operations up through March 23, 2006 are from Atlas Resources,
Inc. before it was merged into a non-taxable entity. Deferred tax assets and
liabilities were eliminated upon the merger since the Company is a non-taxable
entity. On the effective date of the merger, the Company became a single member
LLC and each share of Atlas Resources, Inc. was cancelled.

SPIN-OFF OF ATLAS FROM RESOURCE AMERICA, INC.

     On June 30, 2005, Resource America, Inc. ("RAI") Atlas Resources, Inc.'s
former indirect Parent, distributed its remaining 10.7 million shares of Atlas
to its stockholders in the form of a tax-free dividend. Although the
distribution itself is tax-free to RAI stockholders, as a result of the
deconsolidation there may be some tax liability arising from prior unrelated
corporate transactions among Atlas and some of its subsidiaries. The Company
does not anticipate that there will be a direct material impact on its financial
position or results of operations. Since June 30, 2005, Atlas (and the Company)
are no longer included within RAI's consolidated tax return.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

RECEIVABLES

     In evaluating its allowance for possible losses, the Company performs
ongoing credit evaluations of its customers and adjusts credit limits based upon
payment history and the customers' current creditworthiness, as determined by
the Company's review of its customers' credit information. The Company extends
credit on an unsecured basis to many of its energy customers. At June 30, 2006
and 2005, the Company's credit evaluation indicated that it has no need for an
allowance for possible losses.


                                      F-33

<PAGE>

                       ATLAS RESOURCES, LLC AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                  JUNE 30, 2006
                                   (UNAUDITED)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

REVENUE RECOGNITION

     Because there are timing differences between the delivery of natural gas
and oil and the Company's receipt of a delivery statement, the Company has
unbilled revenues. These revenues are accrued based upon volumetric data from
the Company's records and the Company's estimates of the related transportation
and compression fees, which are, in turn, based upon applicable product prices.
The Company had unbilled trade receivables at June 30, 2006 and September 30,
2005 of $11.0 million and $8.5 million respectively, which are included in
Accounts receivable, on its Consolidated Balance Sheets.

SUPPLEMENTAL CASH FLOW INFORMATION

     The Company considers temporary investments with maturity at the date of
acquisition of 90 days or less to be cash equivalents.

                                     NINE MONTHS ENDED JUNE 30,
                                     --------------------------
                                             2006   2005
                                             ----   ----
                                           (In thousands)
CASH PAID DURING THE PERIOD FOR:

Interest..........................           $ 53   $489
Income taxes paid.................           $129   $  1

RECLASSIFICATIONS

     Certain accounts in the prior year financial statements have been
reclassified for comparative purposes to conform to the presentation in the
current year financial statements.

NOTE 3 - COMPREHENSIVE INCOME

     Comprehensive income includes net income and other gains and losses
affecting stockholders equity from non-owner sources that, under accounting
principles generally accepted in the United States of America, have not been
recognized in the calculation of net income. For the Company, this includes only
changes in the fair value of unrealized hedging gains and losses (shown in
thousands).

<TABLE>
<CAPTION>
                                                                         NINE MONTHS ENDED JUNE 30,
                                                                         --------------------------
                                                                                2006     2005
                                                                              -------   ------
<S>                                                                           <C>       <C>
Net earnings..........................................................        $23,983   $1,640
Other comprehensive income (loss):
Unrealized holding gains on hedging contracts.........................          5,490       --
Less: reclassification adjustment for gains realized in net income....         (2,788)      --
                                                                              -------   ------
                                                                                2,702       --
                                                                              =======   ======
Comprehensive income..................................................        $26,685   $1,640
                                                                              =======   ======
</TABLE>

NOTE 4 - PROPERTY AND EQUIPMENT

     Property and equipment is stated at cost. Depletion and amortization of oil
and gas properties is calculated based on cost less estimated salvage value
primarily using the unit-of-production method. Other fixed assets are
depreciated using the straight-line method over the assets estimated useful
lives. Maintenance and repairs are expensed as incurred. Major renewals and
improvements that extend the useful lives of property are capitalized.


                                      F-34

<PAGE>

                       ATLAS RESOURCES, LLC AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                  JUNE 30, 2006
                                   (UNAUDITED)

NOTE 4 - PROPERTY AND EQUIPMENT (CONTINUED)

Property and equipment consists of the following at the dates indicated (in
thousands):

                                                        JUNE 30,   SEPTEMBER 30,
                                                          2006          2005
                                                        --------   -------------

Mineral interests:

   Proved properties.................................   $  1,543      $  2,009
   Unproved properties...............................        463           465
Wells and related equipment..........................    235,844       179,818
Support equipment....................................      2,465         1,717
Other                                                      3,424         3,389
                                                        --------      --------
                                                         243,739       187,398
Accumulated depreciation, depletion and amortization:

   Oil and gas properties............................    (43,450)      (31,320)
   Other.............................................     (1,776)       (1,399)
                                                        --------      --------
                                                         (45,226)      (32,719)
                                                        --------      --------
                                                        $198,513      $154,679
                                                        ========      ========

NOTE 5 - ASSET RETIREMENT OBLIGATION

     A reconciliation of the Company's liability for well plugging and
abandonment costs for the nine months ended June 30, 2006 and 2005 is as follows
(in thousands):

                                                         2006     2005
                                                        ------   ------
Asset retirement obligation, beginning of period.....   $5,415   $1,910
Liabilities incurred.................................    1,851    2,057
Liabilities settled..................................       (1)      (7)
Revision in estimates................................       --     (183)
Accretion expense....................................      165      137
                                                        ------   ------
Asset retirement obligation, end of period...........   $7,430   $3,914
                                                        ======   ======

     The above accretion expense is included in depreciation, depletion and
amortization in the Company's consolidated statements of income.

NOTE 6 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     Advances from Parent shown on the Company's Balance Sheets represents
amounts owed for advances and other transactions in the normal course of
business. The advances are subordinated to any third party debt. The Company
incurred interest expense related to inter company transactions of $283 thousand
and $2.1 million in June 2006 and 2005, respectively. The advances have no
repayment terms, therefore, the Company has classified the amounts due the
Parent as a current liability on its Consolidated Balance Sheets.


                                      F-35

<PAGE>

                       ATLAS RESOURCES, LLC AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                  JUNE 30, 2006
                                  (UNAUDITED )

NOTE 7 - COMMITMENTS AND CONTINGENCIES

     The Company is the managing general partner of various energy partnerships,
and has agreed to indemnify each investor partner from any liability that
exceeds such partner's share of partnership assets. Subject to certain
conditions, investor partners in certain energy partnerships have the right to
present their interests for purchase by the Company, as managing general
partner. The Company is not obligated to purchase more than 5% to 10% of the
units in any calendar year. Based on past experience, the Company believes that
any liability incurred would not be material.

     The Company may be required to subordinate a part of its net partnership
revenues to the receipt by investor partners of cash distributions from the
energy partnerships equal to at least 10% of their agreed subscriptions
determined on a cumulative basis, in accordance with the terms of the
partnership agreements.

     The Parent may draw from its revolving credit facility on behalf of the
Company. In April 2006, the Company's parent entered into a credit facility led
by Wachovia Bank, which has a current borrowing base of $150.0 million. The
facility permits draws based on the remaining proved developed non-producing and
proved undeveloped natural gas and oil reserves attributable to all wells that
Atlas America has an interest in, including the wells of the Company, and the
projected fees and revenues from operation of the wells and the administration
of the energy partnerships. Up to $50.0 million of the facility may be in the
form of standby letters of credit. The facility is secured by the Parent's
assets, including those of the Company. The revolving credit facility has a term
ending in April 2011, when all outstanding borrowings must be repaid and bears
interest at one of two rates (elected at the borrower's option) which increases
as the amount outstanding under the facility increases. At June 30, 2006 and
September 30, 2005, the Parent had $1.5 million and $9.5 million, respectively,
outstanding under this facility under letters of credit which are not reflected
as borrowings on the Parent's consolidated balance sheet.

     The Company is a party to various routine legal proceedings arising out of
the ordinary course of its business. Management believes that none of these
actions, individually or in the aggregate, will have a material adverse effect
on the Company's financial position or results of operations.

NOTE 8 - DERIVATIVE INSTRUMENTS

     Atlas from time to time enters into natural gas futures and option
contracts on the Company's behalf to hedge its exposure to changes in natural
gas prices. At any point in time, such contracts may include regulated New York
Mercantile Exchange ("NYMEX") futures and options contracts and non-regulated
over-the-counter futures contracts with qualified counterparties. NYMEX
contracts are generally settled with offsetting positions, but may be settled by
the delivery of natural gas.

     Atlas and the Company formally document all relationships between hedging
instruments and the items being hedged, including the Company's risk management
objectives and strategy for undertaking the hedging transactions. This includes
matching the natural gas futures and options contracts to the forecasted
transactions. Atlas and the Company assess, both at the inception of the hedge
and on an ongoing basis, whether the derivatives are highly effective in
offsetting changes in fair value of hedged items. Historically these contracts
have qualified and been designated as cash flow hedges and recorded at their
fair values. Gains or losses on future contracts are determined as the
difference between the contract price and a reference price, generally prices on
NYMEX. Such gains and losses are charged or credited to Accumulated Other
Comprehensive Income (Loss) and recognized as a component of oil and gas
production revenues in the month the hedged gas is sold. If it is determined
that a derivative is not highly effective as a hedge or it has ceased to be a
highly effective hedge, due to the loss of correlation between changes in gas
reference prices under a hedging instrument and actual gas prices, the Company
will discontinue hedge accounting for the derivative and subsequent changes in
fair value for the derivative will be recognized immediately into earnings.


                                      F-36

<PAGE>

                       ATLAS RESOURCES, LLC AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                  JUNE 30, 2006
                                  (UNAUDITED )

NOTE 8 - DERIVATIVE INSTRUMENTS (CONTINUED)

     At June 30, 2006, the Company had 117 open natural gas futures contracts
allocated to it by Atlas related to natural gas sales covering 16,145,800
dekatherms ("Dth") (net to the Company) of natural gas, maturing through
December 31, 2009 at a combined average settlement price of $8.88 per Dth. At
June 30, 2006, the Company reflected net hedging assets on its balance sheet of
$2.7 million. There were no open hedge contracts at September 30, 2005. Of the
$2.7 million net gain in accumulated other comprehensive income at June 30,
2006, if the fair values of the instruments remain at current market values, the
Company will reclassify $3,936,500 of net gains to its statement of operations
over the next twelve month period as these contracts expire, and $1,234,500 of
net losses will be reclassified in later periods. Actual amounts that will be
reclassified will vary as a result of future price changes. Ineffective hedge
gains or losses are recorded within the statement of operations while the hedge
contract is open and may increase or decrease until settlement of the contract.
The Company recognized gains of $2,788,200 for the nine months ended June 30,
2006 within its statement of operations related to the settlement of qualifying
hedge instruments. The Company recognized no gains or losses during the nine
months ended June 30, 2006 and 2005 for hedge ineffectiveness or as a result of
the discontinuance of these cash flow hedges.

        Derivatives are recorded on the balance sheet as assets or liabilities
at fair value. For derivatives qualifying as hedges, the effective portion of
changes in fair value are recognized in member's equity as Accumulated Other
Comprehensive Income (Loss) and reclassified to earnings as such transactions
are settled. For non-qualifying derivatives and for the ineffective portion of
qualifying derivatives, changes in fair value are recognized in earnings as they
occur.

        At June 30, 2006, Atlas had allocated the following natural gas
fixed-price swaps in place to the Company:

NATURAL GAS FIXED - PRICE SWAPS

 TWELVE MONTH                    AVERAGE
    PERIOD         VOLUMES     FIXED PRICE       FAIR VALUE
ENDED JUNE 30,   (MMBTU)(1)   (PER MMBTU)    ASSET (LIABILITY)(2)
--------------   ----------   ------------   --------------------
     2007         2,825,500       $9.67             $ 3,937
     2008         6,155,600        8.76              (2,308)
     2009         5,121,300        8.69                 201
     2010         2,043,400        8.61                 872
                                                    -------
Total asset                                         $ 2,702
                                                    =======

----------
(1)  MMBTU represents million British Thermal Units.

(2)  Fair value based on forward NYMEX natural gas prices, as applicable.


                                      F-37

<PAGE>

                       ATLAS RESOURCES, LLC AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                  JUNE 30, 2006
                                  (UNAUDITED )

NOTE 8 - DERIVATIVE INSTRUMENTS (CONTINUED)

     The following table sets forth the book and estimated fair values of
derivative instruments at the dates indicated (in thousands):

                                     JUNE 30, 2006          SEPTEMBER 30, 2005
                               -----------------------   -----------------------
                               BOOK VALUE   FAIR VALUE   BOOK VALUE   FAIR VALUE
                               ----------   ----------   ----------   ----------
Assets
Derivative instruments......     $ 9,230      $ 9,230        $--          $--
                                 -------      -------        ---          ---
                                 $ 9,230      $ 9,230        $--          $--
                                 =======      =======        ===          ===
Liabilities
Derivative instruments......     $(6,528)     $(6,528)       $--          $--
                                 -------      -------        ---          ---
                                 $ 2,702      $ 2,702        $--          $--
                                 =======      =======        ===          ===

     The fair value of the derivatives are included in the consolidate balance
sheets as follows (in thousands):

                                        JUNE 30,   SEPTEMBER 30,
                                          2006         2005
                                        --------   -------------
Unrealized hedge gains-short-term ...   $ 3,937          $--
Other assets-long term ..............     5,293           --
Unrealized hedge loss-long-term .....    (6,528)          --
                                        -------          ---
                                        $ 2,702          $--
                                        =======          ===

NOTE 9 - INCOME TAXES

     The Company was included in the consolidated federal income tax return of
its Parent up through the merger date in March 2006. After the merger, the
Company became a nontaxable single member limited liability company. The net
balance of Atlas Resources, Inc.'s deferred tax liability of $16.9 million has
been eliminated through a credit to the Company's income from operations in
accordance with Financial Accounting Standard Board Statement 109. The current
tax expense of $1.7 million incurred from October 1, 2005 up to the merger at
March 24, 2006 has also been charged to income from continuing operations.

NOTE 10 - SUBSEQUENT EVENTS

     On July 28, 2006, Atlas America Inc.'s wholly owned subsidiary, Atlas
Energy, filed a registration statement with the Securities and Exchange
Commission for an initial public offering of 5,750,000 common units,
representing an approximate 16.9% limited partner interest in it. Atlas Energy
will own substantially all of the Company's natural gas and oil exploration and
production assets. The Company will enter into a management agreement with Atlas
Energy and be responsible for its day-to-day operations.


                                      F-38

<PAGE>

                                   APPENDIX A

                              INFORMATION REGARDING
                          CURRENTLY PROPOSED PROSPECTS
                                       FOR
                      ATLAS AMERICA PUBLIC #16-2007(A) L.P.

<PAGE>

               INFORMATION REGARDING CURRENTLY PROPOSED PROSPECTS

The partnerships do not currently hold any interests in any prospects on which
the wells will be drilled, and the managing general partner has absolute
discretion in determining which prospects will be acquired to be drilled.
However, set forth below is information relating to certain proposed prospects
and the wells which will be drilled on the prospects by Atlas America Public
#16-2007(A) L.P., which is the first partnership in the program. It is referred
to in this section as the "2007(A) Partnership." One well will be drilled on
each development prospect, and for purposes of this discussion the well and
prospect are referred to together as the "well." The managing general partner
does not anticipate that the wells will be selected in the order in which they
are set forth below. Also, the wells currently proposed to be drilled by the
2007(A) Partnership when its subscription proceeds are released from escrow, and
from time to time thereafter, are subject to the managing general partner's
right to:

     o    withdraw the wells and to substitute other wells;

     o    take a lesser working interest in the wells;

     o    add other wells; or

     o    any combination of the foregoing.

The specified wells represent the necessary wells if subscription proceeds of
approximately $___ million are raised and the 2007(A) Partnership takes the
working interests in the wells that are set forth below in the "Lease
Information" for each area. The managing general partner has not proposed any
other wells if:

     o    a greater amount of subscription proceeds is raised;

     o    a lesser working interest in the wells is acquired; or

     o    other wells are substituted for the proposed wells for any of the
          reasons set forth below.

The managing general partner has not authorized any person to make any
representations to you concerning the possible inclusion of any other wells
which will be drilled by the 2007(A) Partnership or the other remaining
partnership, and you should rely only on the information in this prospectus. The
currently proposed wells will be assigned to the 2007(A) Partnership unless
there are circumstances which, in the managing general partner's opinion, lessen
the relative suitability of the wells. These considerations include:

     o    the amount of the subscription proceeds received by the 2007(A)
          Partnership;

     o    the latest geological and production data available;

     o    potential title or spacing problems;

     o    availability and price of drilling services, tubular goods and
          services;

     o    approvals by federal and state departments or agencies;

     o    agreements with other working interest owners in the wells;

     o    farmins; and

     o    continuing review of other properties which may be available.

Any substituted and/or additional wells will meet the same general criteria that
the managing general partner used in selecting the currently proposed wells, and
generally will be located in areas where the managing general partner or its
affiliates have


                                       1

<PAGE>

previously conducted drilling operations. You, however, will not have the
opportunity to evaluate for yourself the relevant production and geological
information for the substituted and/or additional wells.

The information regarding the currently proposed wells is intended to help you
evaluate the economic potential and risks of drilling the proposed wells. This
includes production information for wells in the same general area as the
proposed well, which the managing general partner believes is an important
indicator in evaluating the economic potential of any well to be drilled.
However, a well drilled by the 2007(A) Partnership may not experience production
comparable to the production experienced by wells in the surrounding area since
the geological conditions in these areas can change in a short distance.
However, generally, there will be a lack of production information from
surrounding wells for the majority of the wells to be drilled by a partnership,
which results in greater uncertainty to you and the other investors. This lack
of production information results from the Pennsylvania Department of
Environmental Resources keeping production data confidential for the first five
years from the time a well starts producing, so if there was a third-party
operator and the well has been drilled within five years the production
information is not available. Also, when the managing general partner is the
operator the wells may often be drilled adjacent to wells which are not yet
completed, on-line to sell production, or have been producing for only a short
period of time so there is little or no production information available. See
"Risk Factors - Risks Related to an Investment In a Partnership - Lack of
Production Information Increases Your Risk and Decreases Your Ability to
Evaluate the Feasibility of a Partnership's Drilling Program." The managing
general partner has proposed these wells to be drilled, even though there is no
production data for other wells in the immediate area, because geologic trends
in the immediate area, such as sand thickness, porosities and water saturations,
lead the managing general partner to believe that the proposed wells also will
be productive.

When reviewing production information for each well offsetting, or in the
general area, of a proposed well to be drilled, you should consider the factors
set forth below.

     o    The length of time that the well has been on-line, and the time period
          for which production information is shown. Generally, the shorter the
          period for which production information is shown the less reliable the
          information is in predicting the ultimate recovery of reserves from a
          well.

     o    Production from a well declines throughout the life of the well. The
          rate of decline, the "decline curve," varies based on which geological
          formation is producing, and may be affected by the operation of the
          well. For example, the wells in the Clinton/Medina geological
          formation in western Pennsylvania will have a different decline curve
          from the wells in the Mississippian/Upper Devonian Sandstone Reservoir
          in Fayette, Greene and Westmoreland Counties, which also are situated
          in western Pennsylvania. Also, each well in a geological formation or
          reservoir will have a different rate of decline from the other wells
          in the same formation or reservoirs.

     o    The greatest volume of production ("flush production") from a well
          usually occurs in the early period of well operations and may indicate
          a greater reserve volume (generally, the ultimate amount of natural
          gas and oil recoverable from a well) than the well actually will
          produce. This period of flush production can vary depending on how the
          well is operated and the location of the well.

     o    The production information for the majority of the wells is incomplete
          or very limited. The designation "N/A" means:

          o    the production information was not available to the managing
               general partner for the reasons discussed in "Risk Factors -
               Risks Related to an Investment In a Partnership - Lack of
               Production Information Increases Your Risk and Decreases Your
               Ability to Evaluate the Feasibility of a Partnership's Drilling
               Program"; or

          o    if the managing general partner was the operator, then when the
               information was prepared the well was:

               o    not completed;


                                       2

<PAGE>

               o    completed, but was not on-line to sell production; or

               o    producing for only a short period of time.

     o    Production information for wells located close to a proposed well
          tends to be more relevant than production information for wells
          located farther away, although performance and volume of production
          from wells located on contiguous prospects can be much different.

     o    Consistency in production among wells tends to confirm the reliability
          and predictability of the production.

The information set forth below is included to help you become familiar with the
proposed wells.

     o    A map of western Pennsylvania and eastern Ohio showing their
          counties.

     o    Fayette County, Pennsylvania (Mississippian/Upper Devonian Sandstone
          Reservoirs)

          o    Lease information for Fayette, Greene and Westmoreland Counties,
               Pennsylvania.

          o    Location and Production Maps for Fayette, Greene and Westmoreland
               Counties, Pennsylvania showing the proposed wells and the wells
               in the area.

          o    Production data for Fayette, Greene and Westmoreland Counties,
               Pennsylvania.

          o    United Energy Development Consultants, Inc.'s geologic evaluation
               for the currently proposed wells in Fayette, Greene and
               Westmoreland Counties, Pennsylvania.

     o    Western Pennsylvania (Clinton/Medina Geological Formation)

          o    Lease information for western Pennsylvania and eastern Ohio.

          o    Location and Production Maps for western Pennsylvania and eastern
               Ohio showing the proposed wells and the wells in the area.

          o    Production data for western Pennsylvania and eastern Ohio.

          o    United Energy Development Consultants, Inc.'s geologic evaluation
               for the currently proposed wells in western Pennsylvania and
               eastern Ohio.

     o    Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee
          (Mississippian Carbonate and Devonian Shale Reservoirs)

          o    A map of Tennessee showing its Counties.

          o    Lease information for Anderson, Campbell, Morgan, Roane and Scott
               Counties, Tennessee.

          o    Location and Production Maps for Anderson, Campbell, Morgan,
               Roane and Scott Counties, Tennessee showing the proposed wells
               and the wells in the area.

          o    Production data for Anderson, Campbell, Morgan, Roane and Scott
               Counties, Tennessee.

          o    United Energy Development Consultants, Inc.'s geologic evaluation
               for the primary drilling area in Anderson, Campbell, Morgan,
               Roane and Scott Counties, Tennessee.


                                       3

<PAGE>

                                   EXHIBIT (A)

                                     FORM OF

                        AMENDED AND RESTATED CERTIFICATE

                      AND AGREEMENT OF LIMITED PARTNERSHIP

                                       FOR

                      ATLAS AMERICA PUBLIC #16-2007(A) L.P.

           [FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF
         LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #16-2007(B) L.P.]

<PAGE>

                                TABLE OF CONTENTS

SECTION NO.                        DESCRIPTION                              PAGE
-----------                        -----------                              ----
I.    FORMATION
      1.01 Formation.....................................................     1
      1.02 Certificate of Limited Partnership............................     1
      1.03 Name, Principal Office and Residence..........................     1
      1.04 Purpose.......................................................     1

II.   DEFINITION OF TERMS
      2.01 Definitions...................................................     2

III.  SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS
      3.01 Designation of Managing General Partner and Participants......    11
      3.02 Participants..................................................    11
      3.03 Subscriptions to the Partnership..............................    11
      3.04 Capital Contributions of the Managing General Partner.........    13
      3.05 Payment of Subscriptions......................................    13
      3.06 Partnership Funds.............................................    14

IV.   CONDUCT OF OPERATIONS
      4.01 Acquisition of Leases.........................................    15
      4.02 Conduct of Operations.........................................    16
      4.03 General Rights and Obligations of the Participants and
           Restricted and Prohibited Transactions........................    20
      4.04 Designation, Compensation and Removal of Managing General
           Partner and Removal of Operator...............................    31
      4.05 Indemnification and Exoneration...............................    35
      4.06 Other Activities..............................................    37

V.    PARTICIPATION IN COSTS AND REVENUES, CAPITAL ACCOUNTS, ELECTIONS AND
      DISTRIBUTIONS
      5.01 Participation in Costs and Revenues...........................    38
      5.02 Capital Accounts and Allocations Thereto......................    41
      5.03 Allocation of Income, Deductions and Credits..................    42
      5.04 Elections.....................................................    44
      5.05 Distributions.................................................    45

VI.   TRANSFER OF UNITS
      6.01 Transferability of Units......................................    46
      6.02 Special Restrictions on Transfers of Units by Participants....    46
      6.03 Presentment...................................................    48
      6.04 Redemption of Units from Non-Citizen Assignees................    50

VII.  DURATION, DISSOLUTION, AND
      WINDING UP
      7.01 Duration......................................................    50
      7.02 Dissolution and Winding Up....................................    50

VIII. MISCELLANEOUS PROVISIONS
      8.01 Notices.......................................................    51
      8.02 Time..........................................................    52
      8.03 Applicable Law................................................    52
      8.04 Agreement in Counterparts.....................................    52
      8.05 Amendment.....................................................    52
      8.06 Additional Partners...........................................    53
      8.07 Legal Effect..................................................    53

EXHIBITS
      EXHIBIT (I-A) - Form of Managing General Partner Signature Page
      EXHIBIT (I-B) - Form of Subscription Agreement
      EXHIBIT (II)  - Form of Drilling and Operating Agreement for Atlas
                         America Public #16-2007(A) L.P. [Atlas America
                         Public #16-2007(B) L.P.]


                                        i

<PAGE>

            FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF
         LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #16-2007(A) L.P.
           [FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF
         LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #16-2007(B) L.P.]

THIS AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP
("AGREEMENT"), amending and restating the original Certificate of Limited
Partnership, is made and entered into as of the date set forth below, by and
among Atlas Resources, LLC, referred to as "Atlas" or the "Managing General
Partner," and the remaining parties from time to time signing a Subscription
Agreement for Limited Partner Units, these parties sometimes referred to as
"Limited Partners," or for Investor General Partner Units, these parties
sometimes referred to as "Investor General Partners."

                                    ARTICLE I
                                    FORMATION

1.01. FORMATION. The parties have formed a limited partnership under the
Delaware Revised Uniform Limited Partnership Act on the terms and conditions set
forth in this Agreement.

1.02. CERTIFICATE OF LIMITED PARTNERSHIP. This document is not only an agreement
among the parties, but also is the Amended and Restated Certificate and
Agreement of Limited Partnership of the Partnership. This document shall be
filed or recorded in the public offices required under applicable law or deemed
advisable in the discretion of the Managing General Partner. Amendments to the
certificate of limited partnership shall be filed or recorded in the public
offices required under applicable law or deemed advisable in the discretion of
the Managing General Partner.

1.03. NAME, PRINCIPAL OFFICE AND RESIDENCE.

1.03(a). NAME. The name of the Partnership is Atlas America Public #16-2007(A)
L.P. [Atlas America Public #16-2007(B) L.P.].

1.03(b). RESIDENCE. The residence of the Managing General Partner is its
principal place of business at 311 Rouser Road, Moon Township, Pennsylvania
15108, which shall also serve as the principal place of business of the
Partnership.

The residence of each Participant shall be as set forth on the Subscription
Agreement executed by the Participant.

All addresses shall be subject to change on notice to the parties.

1.03(c). AGENT FOR SERVICE OF PROCESS. The name and address of the agent for
service of process shall be Andrew M. Lubin at 110 S. Poplar Street, Suite 101,
Wilmington, Delaware 19801.

1.04. PURPOSE. The Partnership shall engage in all phases of the natural gas and
oil business. This includes, without limitation, exploration for, development
and production of natural gas and oil on the terms and conditions set forth
below and any other proper purpose under the Delaware Revised Uniform Limited
Partnership Act.

The Managing General Partner may not, without the affirmative vote of
Participants whose Units equal a majority of the total Units, do the following:

     (i)  change the investment and business purpose of the Partnership; or

     (ii) cause the Partnership to engage in activities outside the stated
          business purposes of the Partnership through joint ventures with other
          entities.


                                       1

<PAGE>

                                   ARTICLE II
                               DEFINITION OF TERMS

2.01. DEFINITIONS. As used in this Agreement, the following terms shall have the
meanings set forth below:

     1.   "Administrative Costs" means all customary and routine expenses
          incurred by the Sponsor for the conduct of Partnership administration,
          including: in-house legal, finance, in-house accounting, secretarial,
          travel, office rent, telephone, data processing and other items of a
          similar nature. Administrative Costs shall be limited as follows:

          (i)  no Administrative Costs charged shall be duplicated under any
               other category of expense or cost; and

          (ii) no portion of the salaries, benefits, compensation or
               remuneration of controlling persons of the Managing General
               Partner shall be reimbursed by the Partnership as Administrative
               Costs. Controlling persons include directors, executive officers
               and those holding a 5% or more equity interest in the Managing
               General Partner or a person having power to direct or cause the
               direction of the Managing General Partner, whether through the
               ownership of voting securities, by contract, or otherwise.

     2.   "Administrator" means the official or agency administering the
          securities laws of a state.

     3.   "Affiliate" means with respect to a specific person:

          (i)  any person directly or indirectly owning, controlling, or holding
               with power to vote 10% or more of the outstanding voting
               securities of the specified person;

          (ii) any person 10% or more of whose outstanding voting securities are
               directly or indirectly owned, controlled, or held with power to
               vote, by the specified person;

          (iii) any person directly or indirectly controlling, controlled by, or
               under common control with the specified person;

          (iv) any officer, director, trustee or partner of the specified
               person; and

          (v)  if the specified person is an officer, director, trustee or
               partner, any person for which the person acts in any such
               capacity.

     4.   "Agreement" means this Amended and Restated Certificate and Agreement
          of Limited Partnership, including all exhibits to this Agreement.

     5.   "Anthem Securities" means Anthem Securities, Inc., whose principal
          executive offices are located at 311 Rouser Road, P.O. Box 926, Moon
          Township, Pennsylvania 15108-0926.

     6.   "Assessments" means additional amounts of capital which may be
          mandatorily required of or paid voluntarily by a Participant beyond
          his subscription commitment.

     7.   "Atlas" means Atlas Resources, LLC, a Pennsylvania limited liability
          company, whose principal executive offices are located at 311 Rouser
          Road, Moon Township, Pennsylvania 15108, and any successor entity to
          Atlas Resources, LLC, whether by merger or any other form of
          reorganization, or the acquisition of all, or substantially all, of
          Atlas Resources, LLC's assets.

     8.   "Atlas America Public #16-2007 Program" means the offering of Units in
          a series of up to two limited partnerships entitled Atlas America
          Public #16-2007(A) L.P. and Atlas America Public #16-2007(B) L.P.


                                       2

<PAGE>

     9.   "Capital Account" or "account" means the account established for each
          party, maintained as provided in Section 5.02 and its subsections.

     10.  "Capital Contribution" means the amount agreed to be contributed to
          the Partnership by a Partner pursuant to Sections 3.04 and 3.05 and
          their subsections.

     11.  "Carried Interest" means an equity interest in the Partnership issued
          to a Person without consideration, in the form of cash or tangible
          property, in an amount proportionately equivalent to that received
          from the Participants.

     12.  "Code" means the Internal Revenue Code of 1986, as amended.

     13.  "Cost," when used with respect to the sale or transfer of property to
          the Partnership, means:

          (i)  the sum of the prices paid by the seller or transferor to an
               unaffiliated person for the property, including bonuses;

          (ii) title insurance or examination costs, brokers' commissions,
               filing fees, recording costs, transfer taxes, if any, and like
               charges in connection with the acquisition of the property;

          (iii) a pro rata portion of the seller's or transferor's actual
               necessary and reasonable expenses for seismic and geophysical
               services; and

          (iv) rentals and ad valorem taxes paid by the seller or transferor for
               the property to the date of its transfer to the buyer, interest
               and points actually incurred on funds used to acquire or maintain
               the property, and the portion of the seller's or transferor's
               reasonable, necessary and actual expenses for geological,
               geophysical, engineering, drafting, accounting, legal and other
               like services allocated to the property cost in conformity with
               generally accepted accounting principles and industry standards,
               except for expenses in connection with the past drilling of wells
               which are not producers of sufficient quantities of oil or gas to
               make commercially reasonable their continued operations, and
               provided that the expenses enumerated in this subsection (iv)
               shall have been incurred not more than 36 months before the sale
               or transfer to the Partnership.

          "Cost," when used with respect to services, means the reasonable,
          necessary and actual expense incurred by the seller on behalf of the
          Partnership in providing the services, determined in accordance with
          generally accepted accounting principles.

          As used elsewhere, "Cost" means the price paid by the seller in an
          arm's-length transaction.

     14.  "Dealer-Manager" means Anthem Securities, Inc., an Affiliate of the
          Managing General Partner, the broker/dealer which will manage the
          offering and sale of the Units.

     15.  "Development Well" means a well drilled within the proved area of a
          natural gas or oil reservoir to the depth of a stratigraphic Horizon
          known to be productive.

     16.  "Direct Costs" means all actual and necessary costs directly incurred
          for the benefit of the Partnership and generally attributable to the
          goods and services provided to the Partnership by parties other than
          the Sponsor or its Affiliates. Direct Costs may not include any cost
          otherwise classified as Organization and Offering Costs,
          Administrative Costs, Intangible Drilling Costs, Tangible Costs,
          Operating Costs or costs related to the Leases, but may include the
          cost of services provided by the Sponsor or its Affiliates if the
          services are provided pursuant to written contracts and in compliance
          with Section 4.03(d)(7) or pursuant to the Managing General Partner's
          role as Tax Matters Partner.

     17.  "Distribution Interest" means an undivided interest in the
          Partnership's assets after payments to the Partnership's creditors or
          the creation of a reasonable reserve therefor, in the ratio the
          positive balance of a


                                       3

<PAGE>

          party's Capital Account bears to the aggregate positive balance of the
          Capital Accounts of all of the parties determined after taking into
          account all Capital Account adjustments for the taxable year during
          which liquidation occurs (other than those made pursuant to
          liquidating distributions or restoration of deficit Capital Account
          balances). Provided, however, after the Capital Accounts of all of the
          parties have been reduced to zero, the interest in the remaining
          Partnership assets shall equal a party's interest in the related
          Partnership revenues as set forth in Section 5.01 and its subsections.

     18.  "Drilling and Operating Agreement" means the proposed Drilling and
          Operating Agreement between the Managing General Partner or an
          Affiliate as Operator, and the Partnership as Developer, a copy of the
          proposed form of which is attached to this Agreement as Exhibit (II).

     19.  "Exploratory Well" means a well drilled to:

          (i)   find commercially productive hydrocarbons in an unproved area;

          (ii)  find a new commercially productive Horizon in a field previously
                found to be productive of hydrocarbons at another Horizon; or

          (iii) significantly extend a known prospect.

     20.  "Farmout" means an agreement by the owner of the leasehold or Working
          Interest to assign his interest in certain acreage or well to the
          assignees, retaining some interest such as an Overriding Royalty
          Interest, an oil and gas payment, offset acreage or other type of
          interest, subject to the drilling of one or more specific wells or
          other performance as a condition of the assignment.

     21.  "Final Terminating Event" means any one of the following:

          (i)   the expiration of the Partnership's fixed term;

          (ii)  notice to the Participants by the Managing General Partner of
                its election to terminate the Partnership's affairs;

          (iii) notice by the Participants to the Managing General Partner of
                their similar election through the affirmative vote of
                Participants whose Units equal a majority of the total Units; or

          (iv)  the termination of the Partnership under Section 708(b)(1)(A) of
                the Code or the Partnership ceases to be a going concern.

     22.  "Horizon" means a zone of a particular formation; that part of a
          formation of sufficient porosity and permeability to form a petroleum
          reservoir.

     23.  "Independent Expert" means a person with no material relationship to
          the Sponsor or its Affiliates who is qualified and in the business of
          rendering opinions regarding the value of natural gas and oil
          properties based on the evaluation of all pertinent economic,
          financial, geologic and engineering information available to the
          Sponsor or its Affiliates.

     24.  "Initial Closing Date" means the date after the minimum amount of
          subscription proceeds has been received when subscription proceeds are
          first withdrawn from the escrow account.

     25.  "Intangible Drilling Costs" or "Non-Capital Expenditures" means those
          expenditures associated with property acquisition and the drilling and
          completion of natural gas and oil wells that under present law are
          generally accepted as fully deductible currently for federal income
          tax purposes. This includes:

          (i)  all expenditures made for any well before production in
               commercial quantities for wages, fuel, repairs, hauling, supplies
               and other costs and expenses incident to and necessary for
               drilling the


                                       4

<PAGE>

               well and preparing the well for production of natural gas or oil,
               that are currently deductible pursuant to Section 263(c) of the
               Code and Treasury Reg. Section 1.612-4, and are generally termed
               "intangible drilling and development costs,";

          (ii) the expense of plugging and abandoning any well before a
               completion attempt; and

          (iii) the costs (other than Tangible Costs and Lease acquisition
               costs) to re-enter and deepen an existing well, complete the well
               to deeper reservoirs, or plug and abandon the well if it is
               nonproductive from the targeted deeper reservoirs.

     26.  "Interim Closing Date" means those date(s) after the Initial Closing
          Date, but before the Offering Termination Date, that the Managing
          General Partner, in its sole discretion, applies additional
          subscription proceeds to additional Partnership activities, including
          drilling activities.

     27.  "Investor General Partners" means:

          (i)  the Persons signing the Subscription Agreement as Investor
               General Partners; and

          (ii) the Managing General Partner to the extent of any optional
               subscription as an Investor General Partner under Section
               3.03(b)(1).

          All Investor General Partners shall be of the same class and have the
          same rights.

     28.  "Landowner's Royalty Interest" means an interest in production, or its
          proceeds, to be received free and clear of all costs of development,
          operation, or maintenance, reserved by a landowner on the creation of
          a Lease.

     29.  "Leases" means full or partial interests in natural gas and oil
          leases, oil and natural gas mineral rights, fee rights, licenses,
          concessions, or other rights under which the holder is entitled to
          explore for and produce oil and/or natural gas, and includes any
          contractual rights to acquire any such interest.

     30.  "Limited Partners" means:

          (i)  the Persons signing the Subscription Agreement as Limited
               Partners;

          (ii) the Managing General Partner to the extent of any optional
               subscription as a Limited Partner under Section 3.03(b)(1);

          (iii) the Investor General Partners on the conversion of their
               Investor General Partner Units to Limited Partner Units pursuant
               to Section 6.01(b); and

          (iv) any other Persons who are admitted to the Partnership as
               additional or substituted Limited Partners.

          Except as provided in Section 3.05(b), with respect to the required
          additional Capital Contributions of Investor General Partners, all
          Limited Partners shall be of the same class and have the same rights.

     31.  "Managing General Partner" means:

          (i)  Atlas; or

          (ii) any Person admitted to the Partnership as a general partner,
               other than as an Investor General Partner, who is designated to
               exclusively supervise and manage the operations of the
               Partnership.

     32.  "Managing General Partner Signature Page" means an execution and
          subscription instrument in the form attached as Exhibit (I-A) to this
          Agreement, which is incorporated in this Agreement by reference.


                                       5

<PAGE>

     33.  "Offering Termination Date" means the date after the minimum amount of
          subscription proceeds has been received on which the Managing General
          Partner determines, in its sole discretion, that the Partnership's
          subscription period is closed and the acceptance of subscriptions
          ceases, which may be any date up to and including December 31, 2007.

          Notwithstanding the above, the Offering Termination Date may not
          extend beyond the time that subscriptions for the maximum number of
          Units set forth in Section 3.03(c)(1) have been received and accepted
          by the Managing General Partner.

     34.  "Operating Costs" means expenditures made and costs incurred in
          producing and marketing natural gas or oil from completed wells. These
          costs include, but are not limited to:

          (i)  labor, fuel, repairs, hauling, materials, supplies, utility
               charges and other costs incident to or related to producing and
               marketing natural gas and oil;

          (ii) ad valorem and severance taxes;

          (iii) insurance and casualty loss expense; and

          (iv) compensation to well operators or others for services rendered in
               conducting these operations.

          Operating Costs also include reworking, workover, subsequent
          equipping, and similar expenses relating to any well, the Managing
          General Partner's gathering fees set forth in Section 4.04(a)(2)(d)
          and the reimbursement of the Managing General Partner's Administrative
          Costs set forth in Section 4.04(a)(2)(c); but do not include the costs
          to re-enter and deepen an existing well, complete the well to deeper
          formations or reservoirs, or plug and abandon the well if it is
          nonproductive from the targeted deeper formations or reservoirs.

     35.  "Operator" means Atlas, as operator of Partnership Wells in
          Pennsylvania, and Atlas or an Affiliate as Operator of Partnership
          Wells in other areas of the United States.

     36.  "Organization and Offering Costs" means all costs of organizing and
          selling the offering including, but not limited to:

          (i)  total underwriting and brokerage discounts and commissions,
               including fees of the underwriters' attorneys, the Dealer-Manager
               fee, sales commissions and the up to .5% reimbursement for bona
               fide due diligence expenses;

          (ii) expenses for printing, engraving, mailing, salaries of employees
               while engaged in sales activities, charges of transfer agents,
               registrars, trustees, escrow holders, depositaries, engineers and
               other experts;

          (iii) expenses of qualification of the sale of the securities under
               federal and state law, including taxes and fees, accountants' and
               attorneys' fees; and

          (iv) other front-end fees.

     37.  "Organization Costs" means all costs of organizing the offering
          including, but not limited to:

          (i)  expenses for printing, engraving, mailing, salaries of employees
               while engaged in sales activities, charges of transfer agents,
               registrars, trustees, escrow holders, depositaries, engineers and
               other experts;

          (ii) expenses of qualification of the sale of the securities under
               federal and state law, including taxes and fees, accountants' and
               attorneys' fees; and


                                       6

<PAGE>

          (iii) other front-end fees.

     38.  "Overriding Royalty Interest" means an interest in the natural gas and
          oil produced under a Lease, or the proceeds from the sale thereof,
          carved out of the Working Interest, to be received free and clear of
          all costs of development, operation, or maintenance.

     39.  "Participants" means:

          (i)  the Managing General Partner to the extent of its optional
               subscription under Section 3.03(b)(1);

          (ii) the Limited Partners; and

          (iii) the Investor General Partners.

     40.  "Partners" means:

          (i)  the Managing General Partner;

          (ii) the Investor General Partners; and

          (iii) the Limited Partners.

     41.  "Partnership" means Atlas America Public #16-2007(A) L.P. [Atlas
          America Public #16-2007(B) L.P.].

     42.  "Partnership Net Production Revenues" means gross revenues after
          deduction of the related Operating Costs, Direct Costs, Administrative
          Costs and all other Partnership costs not specifically allocated.

     43.  "Partnership Well" means a well, some portion of the revenues from
          which is received by the Partnership.

     44.  "Person" means a natural person, partnership, corporation,
          association, trust or other legal entity.

     45.  "Production Purchase" or "Income" Program means any program whose
          investment objective is to directly acquire, hold, operate, and/or
          dispose of producing oil and gas properties. Such a program may
          acquire any type of ownership interest in a producing property,
          including, but not limited to, working interests, royalties, or
          production payments. A program which spends at least 90% of capital
          contributions and funds borrowed (excluding offering and
          organizational expenses) in the above described activities is presumed
          to be a production purchase or income program.

     46.  "Program" means one or more limited or general partnerships or other
          investment vehicles formed, or to be formed, for the primary purpose
          of:

          (i)  exploring for natural gas, oil and other hydrocarbon substances;
               or

          (ii) investing in or holding any property interests which permit the
               exploration for or production of hydrocarbons or the receipt of
               such production or its proceeds.

     47.  "Prospect" means an area covering lands which are believed by the
          Managing General Partner to contain subsurface structural or
          stratigraphic conditions making it susceptible to the accumulations of
          hydrocarbons in commercially productive quantities at one or more
          Horizons. The area, which may be different for different Horizons,
          shall be:

          (i)  designated by the Managing General Partner in writing before the
               conduct of Partnership operations; and


                                       7

<PAGE>

          (ii) enlarged or contracted from time to time on the basis of
               subsequently acquired information to define the anticipated
               limits of the associated hydrocarbon reserves and to include all
               acreage encompassed therein.

          If the well to be drilled by the Partnership is to a Horizon
          containing Proved Reserves, then a "Prospect" for a particular Horizon
          may be limited to the minimum area permitted by state law or local
          practice, whichever is applicable, to protect against drainage from
          adjacent wells. Subject to the foregoing sentence, "Prospect" shall be
          deemed the drilling or spacing unit for the Clinton/Medina geological
          formation and the Mississippian and/or Upper Devonian Sandstone
          reservoirs in Ohio, Pennsylvania, and New York and the Mississippian
          Carbonate or the Devonian Shale reservoirs in Anderson, Campbell,
          Morgan, Roane and Scott Counties, Tennessee.

     48.  "Prospectus" means the Prospectus included in the Registration
          Statement on Form S-1 relating to the offer and sale of the Units
          which has been filed with the Securities and Exchange Commission (the
          "Commission") under the Securities Act of 1933, as amended (the
          "Act"). As used in this Agreement, the terms "Prospectus" and
          "Registration Statement" refer solely to the Prospectus and
          Registration Statement, as amended, described above, except that:

          (i)  from and after the date on which any post-effective amendment to
               the Registration Statement is declared effective by the
               Commission, the term "Registration Statement" shall refer to the
               Registration Statement as amended by that post-effective
               amendment, and the term "Prospectus" shall refer to the
               Prospectus then forming a part of the Registration Statement; and

          (ii) if the Prospectus filed pursuant to Rule 424(b) or (c)
               promulgated by the Commission under the Act differs from the
               Prospectus on file with the Commission at the time the
               Registration Statement or any post-effective amendment thereto
               shall have become effective, the term "Prospectus" shall refer to
               the Prospectus filed pursuant thereto from and after the date on
               which it was filed.

     49.  "Proved Developed Oil and Gas Reserves" means reserves that can be
          expected to be recovered through existing wells with existing
          equipment and operating methods. Additional oil and gas expected to be
          obtained through the application of fluid injection or other improved
          recovery techniques for supplementing the natural forces and
          mechanisms of primary recovery should be included as "proved developed
          reserves" only after testing by a pilot project or after the operation
          of an installed program has confirmed through production response that
          increased recovery will be achieved.

     50.  "Proved Reserves" means the estimated quantities of crude oil, natural
          gas, and natural gas liquids which geological and engineering data
          demonstrate with reasonable certainty to be recoverable in future
          years from known reservoirs under existing economic and operating
          conditions, i.e., prices and costs as of the date the estimate is
          made. Prices include consideration of changes in existing prices
          provided only by contractual arrangements, but not on escalations
          based upon future conditions.

          (i)   Reservoirs are considered proved if economic producibility is
                supported by either actual production or conclusive formation
                test. The area of a reservoir considered proved includes:

               (a)  that portion delineated by drilling and defined by gas-oil
                    and/or oil-water contacts, if any; and

               (b)  the immediately adjoining portions not yet drilled, but
                    which can be reasonably judged as economically productive on
                    the basis of available geological and engineering data.

          In the absence of information on fluid contacts, the lowest known
          structural occurrence of hydrocarbons controls the lower proved limit
          of the reservoir.


                                       8

<PAGE>

          (ii)  Reserves which can be produced economically through application
                of improved recovery techniques (such as fluid injection) are
                included in the "proved" classification when successful testing
                by a pilot project, or the operation of an installed program in
                the reservoir, provides support for the engineering analysis on
                which the project or program was based.

          (iii) Estimates of proved reserves do not include the following:

               (a)  oil that may become available from known reservoirs but is
                    classified separately as "indicated additional reserves";

               (b)  crude oil, natural gas, and natural gas liquids, the
                    recovery of which is subject to reasonable doubt because of
                    uncertainty as to geology, reservoir characteristics, or
                    economic factors;

               (c)  crude oil, natural gas, and natural gas liquids, that may
                    occur in undrilled prospects; and

               (d)  crude oil, natural gas, and natural gas liquids, that may be
                    recovered from oil shales, coal, gilsonite and other such
                    sources.

     51.  "Proved Undeveloped Reserves" means reserves that are expected to be
          recovered from either:

          (i)  new wells on undrilled acreage; or

          (ii) from existing wells where a relatively major expenditure is
               required for recompletion.

          Reserves on undrilled acreage shall be limited to those drilling units
          offsetting productive units that are reasonably certain of production
          when drilled. Proved reserves for other undrilled units can be claimed
          only where it can be demonstrated with certainty that there is
          continuity of production from the existing productive formation. Under
          no circumstances should estimates for proved undeveloped reserves be
          attributable to any acreage for which an application of fluid
          injection or other improved recovery technique is contemplated, unless
          such techniques have been proved effective by actual tests in the area
          and in the same reservoir.

     52.  "Roll-Up" means a transaction involving the acquisition, merger,
          conversion or consolidation, either directly or indirectly, of the
          Partnership and the issuance of securities of a Roll-Up Entity. The
          term does not include:

          (i)  a transaction involving securities of the Partnership that have
               been listed for at least 12 months on a national exchange or
               traded through the National Association of Securities Dealers
               Automated Quotation National Market System; or

          (ii) a transaction involving the conversion to corporate, trust or
               association form of only the Partnership if, as a consequence of
               the transaction, there will be no significant adverse change in
               any of the following:

               (a)  voting rights;

               (b)  the Partnership's term of existence;

               (c)  the Managing General Partner's compensation; and

               (d)  the Partnership's investment objectives.

     53.  "Roll-Up Entity" means a partnership, trust, corporation or other
          entity that would be created or survive after the successful
          completion of a proposed roll-up transaction.


                                       9

<PAGE>

     54.  "Sales Commissions" means all underwriting and brokerage discounts and
          commissions incurred in the sale of Units payable to registered
          broker/dealers, but excluding the following:

          (i)  the 2.5% Dealer-Manager fee; and

          (ii) the up to .5% reimbursement for bona fide due diligence expenses.

     55.  "Selling Agents" means the broker/dealers which are selected by the
          Dealer-Manager to participate in the offer and sale of the Units.

     56.  "Sponsor" means any person directly or indirectly instrumental in
          organizing, wholly or in part, a program or any person who will manage
          or is entitled to manage or participate in the management or control
          of a program. The definition includes:

          (i)  the managing and controlling general partner(s) and any other
               person who actually controls or selects the person who controls
               25% or more of the exploratory, development or producing
               activities of the program, or any segment thereof, even if that
               person has not entered into a contract at the time of formation
               of the program; and

          (ii) whenever the context so requires, the term "sponsor" shall be
               deemed to include its affiliates.

               "Sponsor" does not include wholly independent third-parties such
               as attorneys, accountants, and underwriters whose only
               compensation is for professional services rendered in connection
               with the offering of units.

     57.  "Subscription Agreement" means an execution and subscription
          instrument in the form attached as Exhibit (I-B) to this Agreement,
          which is incorporated in this Agreement by reference.

     58.  "Tangible Costs" or "Capital Expenditures" means those costs
          associated with property acquisition and drilling and completing
          natural gas and oil wells which are generally accepted as capital
          expenditures under the Code. This includes all of the following:

          (i)   costs of equipment, parts and items of hardware used in drilling
                and completing a well;

          (ii)  the costs (other than Intangible Drilling Costs and Lease
                acquisition costs) to re-enter and deepen an existing well,
                complete the well to deeper reservoirs, or plug and abandon the
                well if it is nonproductive from the targeted deeper reservoirs;
                and

          (iii) those items necessary to deliver acceptable natural gas and oil
                production to purchasers to the extent installed downstream from
                the wellhead of any well and which are required to be
                capitalized under the Code and its regulations.

     59.  "Tax Matters Partner" means the Managing General Partner.

     60.  "Units" or "Units of Participation" means up to 100 Limited Partner
          interests in the Partnership and up to 19,900 Investor General Partner
          interests in the Partnership, which will be converted to up to 19,900
          Limited Partner Units as set forth in Section 6.01(b), purchased by
          Participants in the Partnership under the provisions of Section 3.03
          and its subsections, including any rights to profits, losses, income,
          gain, credits, deductions, cash distributions or returns of capital or
          other attributes of the Units.

     61.  "Working Interest" means an interest in a Lease which is subject to
          some portion of the cost of development, operation, or maintenance of
          the Lease.


                                       10

<PAGE>

                                  ARTICLE III
                 SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS

3.01. DESIGNATION OF MANAGING GENERAL PARTNER AND PARTICIPANTS. Atlas shall
serve as Managing General Partner of the Partnership. Atlas shall further serve
as a Participant to the extent of any subscription made by it pursuant to
Section 3.03(b)(1).

Limited Partners and Investor General Partners, including the Managing General
Partner and its Affiliates to the extent, if any, they purchase Units, shall
serve as Participants.

3.02. PARTICIPANTS.

3.02(a). LIMITED PARTNER AT FORMATION. Atlas America, Inc., as Original Limited
Partner, has acquired one Unit and has made a Capital Contribution of $100. On
the admission of one or more Limited Partners, the Partnership shall return to
the Original Limited Partner its Capital Contribution and shall reacquire its
Unit. The Original Limited Partner shall then cease to be a Limited Partner in
the Partnership with respect to that Unit.

3.02(b). OFFERING OF INTERESTS. The Partnership is authorized to admit to the
Partnership at the Initial Closing Date, any Interim Closing Date(s), and the
Offering Termination Date additional Participants whose Subscription Agreements
are accepted by the Managing General Partner if, after the admission of the
additional Participants, the total Units sold do not exceed the maximum number
of Units set forth in Section 3.03(c)(1).

3.02(c). ADMISSION OF PARTICIPANTS. No action or consent by the Participants
shall be required for the admission of additional Participants pursuant to this
Agreement.

All subscribers' funds shall be held in an interest bearing account or accounts
by an independent escrow holder and shall not be released to the Partnership
until the receipt and acceptance of the minimum amount of subscription proceeds
set forth in Section 3.03(c)(2). Thereafter, subscriptions may be paid directly
to the Partnership account.

3.03. SUBSCRIPTIONS TO THE PARTNERSHIP.

3.03(a). SUBSCRIPTIONS BY PARTICIPANTS.

3.03(a)(1). SUBSCRIPTION PRICE AND MINIMUM SUBSCRIPTION. The subscription price
of a Unit in the Partnership shall be $10,000, except as set forth below, and
shall be designated on each Participant's Subscription Agreement and payable as
set forth in Section 3.05(b)(1). The minimum subscription per Participant shall
be one Unit ($10,000). Larger subscriptions shall be accepted in $1,000
increments, beginning with $11,000, $12,000, etc.

Notwithstanding the foregoing, the subscription price for:

     (i)  the Managing General Partner, its officers, directors, and Affiliates,
          and Participants who buy Units through the officers and directors of
          the Managing General Partner, shall be reduced by an amount equal to
          the 2.5% Dealer-Manager fee, the 7% Sales Commission and the .5%
          reimbursement of the Selling Agents' bona fide due diligence expenses,
          which shall not be paid with respect to those sales; and

     (ii) Registered Investment Advisors and their clients, and Selling Agents
          and their registered representatives and principals, shall be reduced
          by an amount equal to the 7% Sales Commission, which shall not be paid
          with respect to those sales.

No more than 5% of the total Units in the Partnership shall be sold with the
discounts described above.

3.03(a)(2). EFFECT OF SUBSCRIPTION. Execution of a Subscription Agreement shall
serve as an agreement by the Participant to be bound by each and every term of
this Agreement.


                                       11

<PAGE>

3.03(b). OPTIONAL SUBSCRIPTIONS FOR UNITS BY MANAGING GENERAL PARTNER.

3.03(b)(1). MANAGING GENERAL PARTNER'S OPTIONAL SUBSCRIPTIONS FOR UNITS. In
addition to the Managing General Partner's required Capital Contributions under
Section 3.04(a), the Managing General Partner may subscribe for up to 5% of the
total Units sold in the Partnership under the provisions of Section 3.03(a) and
its subsections, and, subject to the limitations on voting rights set forth in
Section 4.03(c)(3), to that extent shall be deemed to be a Participant in the
Partnership for all purposes under this Agreement.

3.03(b)(2). EFFECT OF AND EVIDENCING SUBSCRIPTION. The Managing General Partner
has executed a Managing General Partner Signature Page which:

     (i)  evidences the Managing General Partner's required Capital
          Contributions under Section 3.04(a); and

     (ii) may be amended, from time-to-time, to reflect the amount of any
          optional subscriptions for Units as a Participant under Section
          3.03(b)(1).

Execution of the Managing General Partner Signature Page serves as an agreement
by the Managing General Partner to be bound by each and every term of this
Agreement.

3.03(c). MAXIMUM AND MINIMUM NUMBER OF UNITS.

3.03(c)(1). MAXIMUM NUMBER OF UNITS. The maximum number of Units may not exceed
20,000 Units, which is up to $200,000,000 of cash subscription proceeds,
excluding the subscription discounts permitted under Section 3.03(a)(1).
Notwithstanding the foregoing, the maximum number of Units in all of the
partnerships in the Atlas America Public #16-2007 Program, in the aggregate,
shall not exceed 20,000 Units which is up to $200,000,000 of cash subscription
proceeds excluding the subscription discounts permitted under Section
3.03(a)(1).

3.03(c)(2). MINIMUM NUMBER OF UNITS. The minimum number of Units shall equal at
least 200 Units, but in any event not less than the number of Units that
provides the Partnership with cash subscription proceeds of $2,000,000,
excluding the subscription discounts permitted under Section 3.03(a)(1).

If subscriptions for the minimum number of Units have not been received and
accepted at the Offering Termination Date, then all monies deposited by
subscribers shall be promptly returned to them. They shall receive interest
earned on their subscription proceeds from the date the monies were deposited in
escrow through the date of refund, without deduction for any fees.

The partnership may break escrow and begin its drilling activities, in the
Managing General Partner's sole discretion, on receipt and acceptance of the
minimum subscription proceeds.

3.03(d). ACCEPTANCE OF SUBSCRIPTIONS.

3.03(d)(1). DISCRETION BY THE MANAGING GENERAL PARTNER. Acceptance of
subscriptions is discretionary with the Managing General Partner. The Managing
General Partner may reject any subscription for any reason it deems appropriate.

3.03(d)(2). TIME PERIOD IN WHICH TO ACCEPT SUBSCRIPTIONS. Subscriptions shall be
accepted or rejected by the Managing General Partner within 30 days of their
receipt. If a subscription is rejected, then all of the subscriber's funds shall
be returned to the subscriber promptly, with interest earned and without
deduction for any fees.

3.03(d)(3). ADMISSION TO THE PARTNERSHIP. The Participants shall be admitted to
the Partnership as follows:

     (i)  not later than 15 days after the release from the escrow account of
          Participants' subscription proceeds to the Partnership; or


                                       12

<PAGE>

     (ii) if a Participant's subscription proceeds are received by the
          Partnership after the close of the escrow account, then not later than
          the last day of the calendar month in which his Subscription Agreement
          was accepted by the Managing General Partner.

3.04. CAPITAL CONTRIBUTIONS OF THE MANAGING GENERAL PARTNER.

3.04(a). MANAGING GENERAL PARTNER'S REQUIRED CAPITAL CONTRIBUTIONS. The Managing
General Partner, as a general partner and not as a Participant, is required to
pay the costs or make the other required Capital Contributions charged to it
under this Agreement, including contributing to the Partnership the Leases which
will be drilled by the Partnership on the terms set forth in Section 4.01(a)(4),
in an amount equal to not less than 25%, in the aggregate, of all Capital
Contributions to the Partnership, at the time the costs are required to be paid
by the Partnership, but no later than December 31, 2008.

3.04(b). ON LIQUIDATION THE MANAGING GENERAL PARTNER MUST CONTRIBUTE DEFICIT
BALANCE IN ITS CAPITAL ACCOUNT. The Managing General Partner shall contribute to
the Partnership any deficit balance in its Capital Account on the occurrence of
either of the following events:

     (i)  the liquidation of the Partnership; or

     (ii) the liquidation of the Managing General Partner's interest in the
          Partnership.

This shall be determined after taking into account all adjustments for the
Partnership's taxable year during which the liquidation occurs, other than
adjustments made pursuant to this requirement, by the end of the taxable year in
which the liquidation occurs or, if later, within 90 days after the date of the
liquidation.

3.04(c). MANAGING GENERAL PARTNER'S PARTNERSHIP INTEREST FOR CAPITAL
CONTRIBUTIONS. The interest of the Managing General Partner, as Managing General
Partner and not as a Participant, in the capital and profits of the Partnership
is fully vested and nonforfeitable as of the date of the formation of the
Partnership and is in consideration for, and is the only consideration for, its
required Capital Contributions to the Partnership.

3.04(d). MANAGING GENERAL PARTNER'S RIGHT TO ASSIGN ITS PARTNERSHIP INTEREST.
Subject to Section 5.01(b)(4)(a) regarding the Managing General Partner's
subordination obligation, the Managing General Partner has the right at any
time, in its discretion, without the consent of the Participants, and without
affecting the allocation of costs and revenues to the Participants or the
Managing General Partner's voting rights under this Agreement, to sell,
contribute, exchange or otherwise transfer all or any portion of its interest as
Managing General Partner or as a Participant (if it purchases Units) in the
Partnership, or any interest therein to an Affiliate of the Managing General
Partner. In that event, except as otherwise may be permitted under this
Agreement, if the Affiliated transferee of the Managing General Partner's
transferred interest in the Partnership does not become a substituted Managing
General Partner in the Partnership, the Affiliated transferee, as a partner in
the Partnership for tax purposes only, shall have the right to receive the share
of the Partnership's profits, losses, income, gains, deductions, credits and
depletion allowances, or items thereof, and cash distributions and returns of
capital (including, but not limited to, cash distributions and returns of
capital on dissolution and liquidation of the Partnership) to which the Managing
General Partner would otherwise be entitled under this Agreement with respect to
its transferred interest in the Partnership.

Subject to the foregoing, the transfer of the Managing General Partner's
interest in the Partnership to any of its Affiliates may be made on any terms
and conditions as the Managing General Partner determines, in its discretion,
and the Partnership and the Participants shall have no right to receive or
otherwise share in any consideration received by the Managing General Partner
from its Affiliates for the transfer of the Managing General Partner's interest
in the Partnership.

No transfer of the Managing General Partner's interest in the Partnership to its
Affiliates under this Section 3.04(d) shall require an accounting by the
Managing General Partner or the Partnership to the Participants.


                                       13

<PAGE>

3.05. PAYMENT OF SUBSCRIPTIONS.

3.05(a). MANAGING GENERAL PARTNER'S SUBSCRIPTIONS. The Managing General Partner
shall pay any optional subscription under Section 3.03(b)(1) as set forth in
Section 3.05(b)(1).

3.05(b). PARTICIPANT SUBSCRIPTIONS AND ADDITIONAL CAPITAL CONTRIBUTIONS OF THE
INVESTOR GENERAL PARTNERS.

3.05(b)(1). PAYMENT OF SUBSCRIPTION AGREEMENTS. A Participant shall pay the
subscription amount designated on his Subscription Agreement 100% in cash at the
time of subscribing. A Participant shall receive interest on the amount he pays
from the time his subscription proceeds are deposited in the escrow account, or
a Partnership account after the minimum number of Units have been received as
provided in Section 3.06(b), until the Offering Termination Date.

3.05(b)(2). ADDITIONAL REQUIRED CAPITAL CONTRIBUTIONS OF THE INVESTOR GENERAL
PARTNERS. Investor General Partners must make Capital Contributions to the
Partnership when called by the Managing General Partner, in addition to their
subscription amounts, for their pro rata share of any Partnership obligations
and liabilities which are recourse to the Investor General Partners and are
represented by their ownership of Units before the conversion of Investor
General Units to Limited Partner Units under Section 6.01(b).

3.05(b)(3). DEFAULT PROVISIONS. The failure of an Investor General Partner to
timely make a required additional Capital Contribution under this section
results in his personal liability to the other Investor General Partners for the
amount in default. The remaining Investor General Partners, in proportion to
their respective number of Units, must pay the defaulting Investor General
Partner's share of Partnership liabilities and obligations called for by the
Managing General Partner. In that event, the remaining Investor General
Partners:

     (i)   shall have a first and preferred lien on the defaulting Investor
           General Partner's interest in the Partnership to secure payment of
           the amount in default plus interest at the legal rate;

     (ii)  shall be entitled to receive 100% of the defaulting Investor General
           Partner's cash distributions, in proportion to their respective
           number of Units, until the amount in default is recovered in full
           plus interest at the legal rate; and

     (iii) may commence legal action to collect the amount due plus interest at
           the legal rate.

3.06. PARTNERSHIP FUNDS.

3.06(a). FIDUCIARY DUTY. The Managing General Partner has a fiduciary
responsibility for the safekeeping and use of all funds and assets of the
Partnership, whether or not in the Managing General Partner's possession or
control. The Managing General Partner shall not employ, or permit another to
employ, the funds and assets of the Partnership in any manner except for the
exclusive benefit of the Partnership.

Neither this Agreement nor any other agreement between the Managing General
Partner and the Partnership shall contractually limit any fiduciary duty owed to
the Participants by the Managing General Partner under applicable law, except as
provided in Sections 4.01, 4.02, 4.03, 4.04, 4.05 and 4.06 of this Agreement.

3.06(b). SPECIAL ACCOUNT AFTER THE RECEIPT OF THE MINIMUM PARTNERSHIP
SUBSCRIPTIONS. Following the receipt of the minimum number of Units and breaking
escrow, the funds of the Partnership shall be held in a separate
interest-bearing account maintained for the Partnership and shall not be
commingled with funds of any other entity.

3.06(c). INVESTMENT.

3.06(c)(1). INVESTMENTS IN OTHER ENTITIES. Partnership funds shall not be
invested in the securities of another person except in the following instances:

     (i)   investments in Working Interests or undivided Lease interests made in
           the ordinary course of the Partnership's business;


                                       14

<PAGE>

     (ii)  temporary investments made as set forth in Section 3.06(c)(2);

     (iii) multi-tier arrangements meeting the requirements of Section
           4.03(d)(15);

     (iv)  investments involving less than 5% of the Partnership's subscription
           proceeds which are a necessary and incidental part of a property
           acquisition transaction; and

     (v)   investments in entities established solely to limit the Partnership's
           liabilities associated with the ownership or operation of property or
           equipment, provided that duplicative fees and expenses shall be
           prohibited.

3.06(c)(2). PERMISSIBLE INVESTMENTS BEFORE INVESTMENT IN PARTNERSHIP ACTIVITIES.
After the Initial Closing Date and until proceeds from the offering are invested
in the Partnership's operations, the proceeds may be temporarily invested in
income producing short-term, highly liquid investments, in which there is
appropriate safety of principal, such as U.S. Treasury Bills.

                                   ARTICLE IV
                              CONDUCT OF OPERATIONS

4.01. ACQUISITION OF LEASES.

4.01(a). ASSIGNMENT TO PARTNERSHIP.

4.01(a)(1). IN GENERAL. The Managing General Partner shall select, acquire and
assign or cause to have assigned to the Partnership full or partial interests in
Leases, by any method customary in the natural gas and oil industry, subject to
the terms and conditions set forth below.

The Partnership and the other partnerships in the Atlas America Public #16-2007
Program may acquire and develop interests in Leases covering one or more of the
same Prospects, in the Managing General Partner's discretion.

The Partnership shall acquire only Leases reasonably expected to meet the stated
purposes of the Partnership. No Leases shall be acquired for the purpose of a
subsequent sale, Farmout, or other disposition unless the acquisition is made
after a well has been drilled to a depth sufficient to indicate that the
acquisition would be in the Partnership's best interest.

4.01(a)(2). FEDERAL AND STATE LEASES. The Partnership is authorized to acquire
Leases on federal and state lands.

4.01(a)(3). MANAGING GENERAL PARTNER'S DISCRETION AS TO TERMS AND BURDENS OF
ACQUISITION. Subject to the provisions of Section 4.03(d) and its subsections,
the acquisitions of Leases or other property may be made under any terms and
obligations, including any limitations as to the Horizons to be assigned to the
Partnership and subject to any burdens as the Managing General Partner deems
necessary in its sole discretion.

4.01(a)(4). COST OF LEASES. All Leases shall be:

     (i)  contributed to the Partnership by the Managing General Partner or its
          Affiliates; and

     (ii) credited towards the Managing General Partner's required Capital
          Contribution set forth in Section 3.04(a) at the Cost of the Lease,
          unless the Managing General Partner has cause to believe that Cost is
          materially more than the fair market value of the property, in which
          case the credit for the contribution must be made at a price not in
          excess of the fair market value.

A determination of fair market value must be supported by an appraisal from an
Independent Expert.

4.01(a)(5). THE MANAGING GENERAL PARTNER, OPERATOR OR THEIR AFFILIATES' RIGHTS
IN THE REMAINDER INTERESTS. Subject to the provisions of Section 4.03(d) and its
subsections, to the extent the Partnership does not acquire a full interest in a
Lease from the Managing General Partner or its Affiliates, the remainder of the
interest in the Lease may be held by the Managing General Partner or its
Affiliates. They may either:


                                       15

<PAGE>

     (i)  retain and exploit the remaining interest for their own account; or

     (ii) sell or otherwise dispose of all or a part of the remaining interest.

Profits from the exploitation and/or disposition of their retained interests in
the Leases shall be for the benefit of the Managing General Partner or its
Affiliates to the exclusion of the Partnership and the Participants.

4.01(a)(6). NO BREACH OF DUTY. Subject to the provisions of Section 4.03 and its
subsections, acquisition of Leases from the Managing General Partner, the
Operator or their Affiliates shall not be considered a breach of any obligation
owed by them to the Partnership or the Participants.

4.01(b). NO OVERRIDING ROYALTY INTERESTS. Neither the Managing General Partner,
the Operator nor any Affiliate shall retain any Overriding Royalty Interest on
the Leases acquired by the Partnership.

4.01(c). TITLE AND NOMINEE ARRANGEMENTS.

4.01(c)(1). LEGAL TITLE. Legal title to all Leases acquired by the Partnership
shall be held on a permanent basis in the name of the Partnership. However,
Partnership properties may be held temporarily in the name of:

     (i)   the Managing General Partner;

     (ii)  the Operator;

     (iii) their Affiliates; or

     (iv)  in the name of any nominee designated by the Managing General Partner
           to facilitate the acquisition of the properties.

4.01(c)(2). MANAGING GENERAL PARTNER'S DISCRETION. The Managing General Partner
shall take the steps which are necessary in its best judgment to render title to
the Leases to be acquired by the Partnership acceptable for the purposes of the
Partnership. The Managing General Partner shall be free, however, to use its own
best judgment in waiving title requirements.

The Managing General Partner shall not be liable to the Partnership or to the
other parties for any mistakes of judgment; nor shall the Managing General
Partner be deemed to be making any warranties or representations, express or
implied, as to the validity or merchantability of the title to the Leases
assigned to the Partnership or the extent of the interest covered thereby except
as otherwise provided in the Drilling and Operating Agreement.

4.01(c)(3). COMMENCEMENT OF OPERATIONS. The Partnership shall not begin
operations on its Leases unless the Managing General Partner is satisfied that
necessary title requirements have been satisfied.

4.02. CONDUCT OF OPERATIONS.

4.02(a). IN GENERAL. The Managing General Partner shall establish a program of
operations for the Partnership. Subject to the limitations contained in Article
III of this Agreement concerning the maximum Capital Contribution which can be
required of a Limited Partner, the Managing General Partner, the Limited
Partners, and the Investor General Partners agree to participate in the program
so established by the Managing General Partner.

4.02(b). MANAGEMENT. Subject to any restrictions contained in this Agreement,
the Managing General Partner shall exercise full control over all operations of
the Partnership.

4.02(c). GENERAL POWERS OF THE MANAGING GENERAL PARTNER.

4.02(c)(1). IN GENERAL. Subject to the provisions of Section 4.03 and its
subsections, and to any authority that may be granted the Operator under Section
4.02(c)(3)(b), the Managing General Partner shall have full authority to do all
things deemed necessary or


                                       16

<PAGE>

desirable by it in the conduct of the business of the Partnership. Without
limiting the generality of the foregoing, the Managing General Partner is
expressly authorized to engage in:

     (i)    the making of all determinations of which Leases, wells and
            operations will be participated in by the Partnership, which
            includes:

            (a)  which Leases are developed;

            (b)  which Leases are abandoned; or

            (c)  which Leases are sold or assigned to other parties, including
                 other investor ventures organized by the Managing General
                 Partner, the Operator, or any of their Affiliates;

     (ii)   the negotiation and execution on any terms deemed desirable in its
            sole discretion of any contracts, conveyances, or other instruments,
            considered useful to the conduct of the operations or the
            implementation of the powers granted it under this Agreement,
            including, without limitation:

            (a)  the making of agreements for the conduct of operations,
                 including agreements and financial instruments relating to
                 hedging the Partnership's natural gas and oil;

            (b)  the exercise of any options, elections, or decisions under any
                 such agreements; and

            (c)  the furnishing of equipment, facilities, supplies and material,
                 services, and personnel;

     (iii)  the exercise, on behalf of the Partnership or the parties, as the
            Managing General Partner in its sole judgment deems best, of all
            rights, elections and options granted or imposed by any agreement,
            statute, rule, regulation, or order;

     (iv)   the making of all decisions concerning the desirability of payment,
            and the payment or supervision of the payment, of all delay rentals
            and shut-in and minimum or advance royalty payments;

     (v)    the selection of full or part-time employees and outside consultants
            and contractors and the determination of their compensation and
            other terms of employment or hiring;

     (vi)   the maintenance of insurance for the benefit of the Partnership and
            the parties as it deems necessary, but in no event less in amount or
            type than the following:

            (a)  worker's compensation insurance in full compliance with the
                 laws of the Commonwealth of Pennsylvania and any other
                 applicable state laws;

            (b)  liability insurance, including automobile, which has a
                 $1,000,000 combined single limit for bodily injury and property
                 damage in any one accident or occurrence and in the aggregate;
                 and

            (c)  liability and excess liability insurance as to bodily injury
                 and property damage with combined limits of $50,000,000 during
                 drilling operations and thereafter, per occurrence or accident
                 and in the aggregate, which includes $1,000,000 of seepage,
                 pollution and contamination insurance which protects and
                 defends the insured against property damage or bodily injury
                 claims from third-parties, other than a co-owner of the Working
                 Interest, alleging seepage, pollution or contamination damage
                 resulting from a pollution incident. The excess liability
                 insurance, which is for general liability only, shall be in
                 place and effective no later than the date drilling operations
                 begin and, for purposes of satisfying this requirement, the
                 Partnership shall have the benefit of the Managing General
                 Partner's $50,000,000 liability insurance on the same basis as
                 the Managing General Partner and its other Affiliates,
                 including the Managing General Partner's other Programs;


                                       17

<PAGE>

     (vii)  the use of the funds and revenues of the Partnership, and the
            borrowing on behalf of, and the loan of money to, the Partnership,
            on any terms it sees fit, for any purpose, including without
            limitation:

            (a)  the conduct or financing, in whole or in part, of the drilling
                 and other activities of the Partnership;

            (b)  the conduct of additional operations; and

            (c)  the repayment of any borrowings or loans used initially to
                 finance these operations or activities;

     (viii) the disposition, hypothecation, sale, exchange, release, surrender,
            reassignment or abandonment of any or all assets of the Partnership,
            including without limitation, the Leases, wells, equipment and
            production therefrom, provided that the sale of all or substantially
            all of the assets of the Partnership shall only be made as provided
            in Section 4.03(d)(6);

     (ix)   the formation of any further limited or general partnership, tax
            partnership, joint venture, or other relationship which it deems
            desirable with any parties who it, in its sole discretion, selects,
            including any of its Affiliates;

     (x)    the control of any matters affecting the rights and obligations of
            the Partnership, including:

            (a)  the employment of attorneys to advise and otherwise represent
                 the Partnership;

            (b)  the conduct of litigation and incurring other legal expenses;
                 and

            (c)  the settlement of claims and litigation;

     (xi)   the operation of producing wells drilled on the Leases or on a
            Prospect which includes any part of the Leases;

     (xii)  the exercise of the rights granted to it under the power of attorney
            created under this Agreement; and

     (xiii) the incurring of all costs and the making of all expenditures in any
            way related to any of the foregoing.

4.02(c)(2). SCOPE OF POWERS. The Managing General Partner's powers shall extend
to any operation participated in by the Partnership or affecting its Leases, or
other property or assets, irrespective of whether or not the Managing General
Partner is designated operator of the operation by any outside persons
participating therein.

4.02(c)(3). DELEGATION OF AUTHORITY.

4.02(c)(3)(a). IN GENERAL. The Managing General Partner may subcontract and
delegate all or any part of its duties under this Agreement to any entity chosen
by it, including an entity Affiliated with it, which party shall have the same
powers in the conduct of the duties as would the Managing General Partner. The
delegation, however, shall not relieve the Managing General Partner of its
responsibilities under this Agreement.

4.02(c)(3)(b). DELEGATION TO OPERATOR. The Managing General Partner is
specifically authorized to delegate any or all of its duties to the Operator by
executing the Drilling and Operating Agreement. This delegation shall not
relieve the Managing General Partner of its responsibilities under this
Agreement.

In no event shall any consideration received for operator services be in excess
of competitive rates or duplicative of any consideration or reimbursements
received under this Agreement. The Managing General Partner may not benefit by
interpositioning itself between the Partnership and the actual provider of
operator services.

4.02(c)(4). RELATED PARTY TRANSACTIONS. Subject to the provisions of Section
4.03 and its subsections, any transaction which the Managing General Partner is
authorized to enter into on behalf of the Partnership under the authority
granted in this section


                                       18

<PAGE>

and its subsections, may be entered into by the Managing General Partner with
itself or with any other general partner, the Operator, or any of their
Affiliates.

4.02(d). ADDITIONAL POWERS. In addition to the powers granted the Managing
General Partner under Section 4.02(c) and its subsections or elsewhere in this
Agreement, the Managing General Partner, when specified, shall have the
following additional express powers.

4.02(d)(1). DRILLING CONTRACTS. All Partnership Wells shall be drilled under the
Drilling and Operating Agreement for an amount equal to the sum of the following
items:

     (i)   the Cost of permits, supplies, materials, equipment, and all other
           items used in the drilling and completion of a well provided by
           third-parties, or if the foregoing items are provided by Affiliates
           of the Managing General Partner, then those items will be charged at
           competitive rates;

     (ii)  fees for third-party services;

     (iii) fees for services provided by the Managing General Partner's
           Affiliates, which will be charged at competitive rates;

     (iv)  an administration and oversight fee of $15,000 per well, which will
           be charged to the Participants as part of each well's Intangible
           Drilling Costs and the portion of equipment costs paid by the
           Participants; and

     (v)   a mark-up in an amount equal to 15% of the sum of (i), (ii), (iii)
           and (iv), above, for the Managing General Partner's services as
           general drilling contractor.

The Managing General Partner or its Affiliates, as drilling contractor, may not
receive a rate that is not competitive with the rates charged by unaffiliated
contractors in the same geographic region, enter into a turnkey drilling
contract with the Partnership, profit by drilling in contravention of its
fiduciary obligations to the Partnership, or benefit by interpositioning itself
between the Partnership and the actual provider of drilling contractor services.

4.02(d)(2). POWER OF ATTORNEY.

4.02(d)(2)(a). IN GENERAL. Each Participant appoints the Managing General
Partner his true and lawful attorney-in-fact for him and in his name, place, and
stead and for his use and benefit, from time to time:

     (i)  to create, prepare, complete, execute, file, swear to, deliver,
          endorse, and record any and all documents, certificates, government
          reports, or other instruments as may be required by law, or are
          necessary to amend this Agreement as authorized under the terms of
          this Agreement, or to qualify the Partnership as a limited partnership
          or partnership in commendam and to conduct business under the laws of
          any jurisdiction in which the Managing General Partner elects to
          qualify the Partnership or conduct business; and

     (ii) to create, prepare, complete, execute, file, swear to, deliver,
          endorse and record any and all instruments, assignments, security
          agreements, financing statements, certificates, and other documents as
          may be necessary from time to time to implement the borrowing powers
          granted under this Agreement.

4.02(d)(2)(b). FURTHER ACTION. Each Participant authorizes the attorney-in-fact
to take any further action which the attorney-in-fact considers necessary or
advisable in connection with any of the foregoing powers and rights granted the
Managing General Partner under this section and its subsections. Each party
acknowledges that the power of attorney granted under Section 4.02(d)(2)(a):

     (i)  is a special power of attorney coupled with an interest and is
          irrevocable; and

     (ii) shall survive the assignment by the Participant of the whole or a
          portion of his Units; except when the assignment is of all of the
          Participant's Units and the purchaser, transferee, or assignee of the
          Units is admitted as a successor Participant, the power of attorney
          shall survive the delivery of the assignment for


                                       19

<PAGE>

          the sole purpose of enabling the attorney-in-fact to execute,
          acknowledge, and file any agreement, certificate, instrument or
          document necessary to effect the substitution.

4.02(d)(2)(c). POWER OF ATTORNEY TO OPERATOR. The Managing General Partner is
hereby authorized to grant a Power of Attorney to the Operator on behalf of the
Partnership.

4.02(e). BORROWINGS AND USE OF PARTNERSHIP REVENUES.

4.02(e)(1). POWER TO BORROW OR USE PARTNERSHIP REVENUES.

4.02(e)(1)(a). IN GENERAL. If additional funds over the Participants' Capital
Contributions are needed for Partnership operations, then the Managing General
Partner may:

     (i)  use Partnership revenues for such purposes; or

     (ii) the Managing General Partner and its Affiliates may advance the
          necessary funds to the Partnership under Section 4.03(d)(8)(b),
          although they are not obligated to advance the funds to the
          Partnership.

4.02(e)(1)(b). LIMITATION ON BORROWING. Partnership borrowings, other than
credit transactions on open account customary in the industry to obtain goods
and services, shall be subject to the following limitations:

     (i)  the borrowings must be without recourse to the Investor General
          Partners and the Limited Partners except as otherwise provided in this
          Agreement; and

     (ii) the amount that may be borrowed at any one time may not exceed an
          amount equal to 5% of the Partnership's subscription proceeds.

4.02(f). TAX MATTERS PARTNER.

4.02(f)(1). DESIGNATION OF TAX MATTERS PARTNER. The Managing General Partner is
hereby designated the Tax Matters Partner of the Partnership under Section
6231(a)(7) of the Code. The Managing General Partner is authorized to act in
this capacity on behalf of the Partnership and the Participants and to take any
action, including settlement or litigation, which it in its sole discretion
deems to be in the best interest of the Partnership.

4.02(f)(2). COSTS INCURRED BY TAX MATTERS PARTNER. Costs incurred by the Tax
Matters Partner shall be considered a Direct Cost of the Partnership.

4.02(f)(3). NOTICE TO PARTICIPANTS OF IRS PROCEEDINGS. The Tax Matters Partner
shall notify all of the Participants of any administrative or other legal
proceedings involving the Partnership and the IRS or any other taxing authority,
and thereafter shall furnish all of the Participants periodic reports at least
quarterly on the status of the proceedings.

4.02(f)(4). PARTICIPANT RESTRICTIONS. Each Participant agrees as follows:

     (i)   he will not file the statement described in Section 6224(c)(3)(B) of
           the Code prohibiting the Managing General Partner as the Tax Matters
           Partner for the Partnership from entering into a settlement on his
           behalf with respect to partnership items, as that term is defined in
           Section 6231(a)(3) of Code, of the Partnership;

     (ii)  he will not form or become and exercise any rights as a member of a
           group of Partners having a 5% or greater interest in the profits of
           the Partnership under Section 6223(b)(2) of the Code; and

     (iii) the Managing General Partner is authorized to file a copy of this
           Agreement, or pertinent portions of this Agreement, with the IRS
           under Section 6224(b) of the Code if necessary to perfect the waiver
           of rights under this subsection.


                                       20

<PAGE>

4.03. GENERAL RIGHTS AND OBLIGATIONS OF THE PARTICIPANTS AND RESTRICTED AND
PROHIBITED TRANSACTIONS.

4.03(a)(1). LIMITED LIABILITY OF LIMITED PARTNERS. Limited Partners shall not be
bound by the obligations of the Partnership other than as provided under the
Delaware Revised Uniform Limited Partnership Act. Limited Partners shall not be
personally liable for any debts of the Partnership or any of the obligations or
losses of the Partnership beyond the subscription amount designated on the
Subscription Agreement executed by each respective Limited Partner unless:

     (i)  they also subscribe to the Partnership as Investor General Partners;
          or

     (ii) in the case of the Managing General Partner, it purchases Limited
          Partner Units.

4.03(a)(2). NO MANAGEMENT AUTHORITY OF PARTICIPANTS. Participants, other than
the Managing General Partner if it buys Units, shall have no power over the
conduct of the affairs of the Partnership. No Participant, other than the
Managing General Partner if it buys Units, shall take part in the management of
the business of the Partnership, or have the power to sign for or to bind the
Partnership.

4.03(b). REPORTS AND DISCLOSURES.

4.03(b)(1). ANNUAL REPORTS AND FINANCIAL STATEMENTS. Beginning with the calendar
year in which the Partnership had its Offering Termination Date, the Partnership
shall provide each Participant an annual report within 120 days after the close
of that calendar year, and beginning with the following calendar year, a report
within 75 days after the end of the first six months of its calendar year,
containing except as otherwise indicated, at least the information set forth
below:

     (i)   Audited financial statements of the Partnership, including a balance
           sheet and statements of income, cash flow, and Partners' equity,
           which shall be prepared on an accrual basis in accordance with
           generally accepted accounting principles with a reconciliation with
           respect to information furnished for income tax purposes and
           accompanied by an auditor's report containing an opinion of an
           independent public accountant selected by the Managing General
           Partner stating that his audit was made in accordance with generally
           accepted auditing standards and that in his opinion the financial
           statements present fairly the financial position, results of
           operations, partners' equity, and cash flows in accordance with
           generally accepted accounting principles. Semiannual reports are not
           required to be audited.

     (ii)  A summary itemization, by type and/or classification of the total
           fees and compensation, including any nonaccountable, fixed payment
           reimbursements for Administrative Costs and Operating Costs, paid by,
           or on behalf of, the Partnership to the Managing General Partner, the
           Operator, and their Affiliates.

           Also, the independent certified public accountant shall provide
           written attestation annually, which will be included in the annual
           report, that the method used to make allocations of the Partnership's
           Administrative Costs was consistent with the method described in
           Section 4.04(a)(2)(c) of this Agreement and that the total amount of
           Administrative Costs allocated did not materially exceed the amounts
           actually incurred by the Managing General Partner in providing
           administrative services to, or on behalf of, the Partnership as
           described in Section 4.04(a)(2)(c), including administrative services
           provided to the Partnership by the Managing General Partner's
           Affiliates or independent third-parties at the sole expense of the
           Managing General Partner. If the Managing General Partner
           subsequently decides to allocate Administrative Costs in a manner
           different from that described in Section 4.04(a)(2)(c) of this
           Agreement, then the change must be reported to the Participants
           together with an explanation of the reason for the change and the
           basis used for determining the reasonableness of the new allocation
           method.

     (iii) A description of each Prospect in which the Partnership owns an
           interest, including:

           (a)  the cost, location, and number of acres under Lease; and

           (b)  the Working Interest owned in the Prospect by the Partnership.


                                       21

<PAGE>

           Succeeding reports, however, must only contain material changes, if
           any, regarding the Prospects.

     (iv)  A list of the wells drilled or abandoned by the Partnership during
           the period of the report, indicating:

           (a)  whether each of the wells has or has not been completed;

           (b)  a statement of the cost of each well completed or abandoned; and

           (c)  justification for wells abandoned after production has begun.

     (v)   A description of all Farmouts, farmins, and joint ventures, made
           during the period of the report, including:

           (a)  the Managing General Partner's justification for the
                arrangement; and

           (b)  a description of the material terms.

     (vi)  A schedule reflecting:

           (a)  the total Partnership costs;

           (b)  the costs paid by the Managing General Partner and the costs
                paid by the Participants;

           (c)  the total Partnership revenues;

           (d)  the revenues received or credited to the Managing General
                Partner and the revenues received and credited to the
                Participants; and

           (e)  a reconciliation of the expenses and revenues in accordance with
                the provisions of Article V.

Additionally, on request the Managing General Partner will provide the
information specified by Form 10-Q (if such report is required to be filed with
the SEC) within 45 days after the close of each quarterly fiscal period.

4.03(b)(2). TAX INFORMATION. The Partnership shall, by March 15 of each year,
prepare, or supervise the preparation of, and transmit to each Participant the
information needed for the Participant to file the following:

     (i)   his federal income tax return;

     (ii)  any required state income tax return; and

     (iii) any other reporting or filing requirements imposed by any
           governmental agency or authority.

4.03(b)(3). RESERVE REPORT. Beginning with the second calendar year after the
Offering Termination Date and every year thereafter, the Partnership shall
provide to each Participant the following:

     (i)   a summary of the computation of the Partnership's total natural gas
           and oil Proved Reserves;

     (ii)  a summary of the computation of the present worth of the reserves
           determined using:

           (a)  a discount rate of 10%;

           (b)  a constant price for the oil; and

           (c)  basing the price of natural gas on the existing natural gas
                contracts;

     (iii) a statement of each Participant's interest in the reserves; and


                                       22

<PAGE>

     (iv)  an estimate of the time required for the extraction of the reserves
           with a statement that because of the time period required to extract
           the reserves the present value of revenues to be obtained in the
           future is less than if immediately receivable.

The reserve computations shall be based on engineering reports prepared by the
Managing General Partner and reviewed by an Independent Expert.

Also, if any event reduces the Partnership's Proved Reserves by 10% or more,
excluding a reduction of reserves as a result of normal production, sales of
reserves, or natural gas or oil price changes, then a computation and estimate
of the amount of the reduction in reserves must be sent to each Participant
within 90 days after the Managing General Partner determines that such a
reduction in reserves has occurred.

4.03(b)(4). COST OF REPORTS. The cost of all reports described in this Section
4.03(b) shall be paid by the Partnership as Direct Costs.

4.03(b)(5). PARTICIPANT ACCESS TO RECORDS. The Participants and/or their
representatives shall be permitted access to all Partnership records, provided
that access to the list of Participants shall be subject to Section 4.03(b)(7)
below. Subject to the foregoing, a Participant may inspect and copy any of the
Partnership's records after giving adequate notice to the Managing General
Partner at any reasonable time.

Notwithstanding the foregoing, the Managing General Partner may keep logs, well
reports, and other drilling and operating data confidential for reasonable
periods of time. The Managing General Partner may release information concerning
the operations of the Partnership to the sources that are customary in the
industry or required by rule, regulation, or order of any regulatory body.

4.03(b)(6). REQUIRED LENGTH OF TIME TO HOLD RECORDS. The Managing General
Partner must maintain and preserve during the term of the Partnership and for
six years thereafter all accounts, books and other relevant documents which
include:

     (i)  a record that a Participant meets the suitability standards
          established in connection with an investment in the Partnership; and

     (ii) any appraisal of the fair market value of the Leases as set forth in
          Section 4.01(a)(4), along with associated supporting information, or
          fair market value of any producing property as set forth in Section
          4.03(d)(3).

4.03(b)(7). PARTICIPANT LISTS. The following provisions apply regarding access
to the list of Participants:

     (i)   an alphabetical list of the names, addresses, and business telephone
           numbers of the Participants along with the number of Units held by
           each of them (the "Participant List") must be maintained as a part of
           the Partnership's books and records and be available for inspection
           by any Participant or his designated agent at the home office of the
           Partnership on the Participant's request;

     (ii)  the Participant List must be updated at least quarterly to reflect
           changes in the information contained in the Participant List;

     (iii) a copy of the Participant List must be mailed to any Participant
           requesting the Participant List within 10 days of the written
           request, printed in alphabetical order on white paper, and in a
           readily readable type size in no event smaller than 10-point type and
           a reasonable charge for copy work will be charged by the Partnership;

     (iv)  the purposes for which a Participant may request a copy of the
           Participant List include, without limitation, matters relating to
           Participant's voting rights under this Agreement and the exercise of
           Participant's rights under the federal proxy laws; and

     (v)   if the Managing General Partner neglects or refuses to exhibit,
           produce, or mail a copy of the Participant List as requested, the
           Managing General Partner shall be liable to any Participant
           requesting the list for the


                                       23

<PAGE>

          costs, including attorneys fees, incurred by that Participant for
          compelling the production of the Participant List, and for actual
          damages suffered by any Participant by reason of the refusal or
          neglect. It shall be a defense that the actual purpose and reason for
          the request for inspection or for a copy of the Participant List is to
          secure the list of Participants or other information for the purpose
          of selling the list or information or copies of the list, or of using
          the same for a commercial purpose other than in the interest of the
          applicant as a Participant relative to the affairs of the Partnership.
          The Managing General Partner will require the Participant requesting
          the Participant List to represent in writing that the list was not
          requested for a commercial purpose unrelated to the Participant's
          interest in the Partnership. The remedies provided under this
          subsection to Participants requesting copies of the Participant List
          are in addition to, and shall not in any way limit, other remedies
          available to Participants under federal law or the laws of any state.

4.03(b)(8). STATE FILINGS. Concurrently with their transmittal to Participants,
and as required, the Managing General Partner shall file a copy of each report
provided for in this Section 4.03(b) with:

     (i)   the California Commissioner of Corporations;

     (ii)  the Arizona Corporation Commission;

     (iii) the Alabama Securities Commission; and

     (iv)  the securities commissions of other states which request the report.

4.03(c). MEETINGS OF PARTICIPANTS.

4.03(c)(1). PROCEDURE FOR A PARTICIPANT MEETING.

4.03(c)(1)(a). MEETINGS MAY BE CALLED BY MANAGING GENERAL PARTNER OR
PARTICIPANTS. Meetings of the Participants may be called as follows:

     (i)   by the Managing General Partner; or

     (ii)  by Participants whose Units equal 10% or more of the total Units for
           any matters on which Participants may vote.

The call for a meeting by the Participants as described above shall be deemed to
have been made on receipt by the Managing General Partner of a written request
from holders of the requisite percentage of Units stating the purpose(s) of the
meeting.

4.03(c)(1)(b). NOTICE REQUIREMENT. The Managing General Partner shall deposit in
the United States mail within 15 days after the receipt of the request, written
notice to all Participants of the meeting and the purpose of the meeting. The
meeting shall be held on a date not less than 30 days nor more than 60 days
after the date of the mailing of the notice, at a reasonable time and place.

Notwithstanding the foregoing, the date for notice of the meeting may be
extended for a period of up to 60 days if, in the opinion of the Managing
General Partner, the additional time is necessary to permit preparation of proxy
or information statements or other documents required to be delivered in
connection with the meeting by the SEC or other regulatory authorities.

4.03(c)(1)(c). MAY VOTE BY PROXY. Participants shall have the right to vote at
any Participant meeting either:

     (i)  in person; or

     (ii) by proxy.

4.03(c)(2). SPECIAL VOTING RIGHTS. At the request of Participants whose Units
equal 10% or more of the total Units, the Managing General Partner shall call
for a vote by Participants. Each Unit is entitled to one vote on all matters,
and each


                                       24

<PAGE>

fractional Unit is entitled to that fraction of one vote equal to the fractional
interest in the Unit. Participants whose Units equal a majority of the total
Units may, without the concurrence of the Managing General Partner or its
Affiliates, vote to:

     (i)   dissolve the Partnership;

     (ii)  remove the Managing General Partner and elect a new Managing General
           Partner;

     (iii) elect a new Managing General Partner if the Managing General Partner
           elects to withdraw from the Partnership;

     (iv)  remove the Operator and elect a new Operator;

     (v)   approve or disapprove the sale of all or substantially all of the
           assets of the Partnership;

     (vi)  cancel any contract for services with the Managing General Partner,
           the Operator, or their Affiliates without penalty on 60 days notice;
           and

     (vii) amend this Agreement; provided however:

           (a)  any amendment may not increase the duties or liabilities of any
                Participant or the Managing General Partner or increase or
                decrease the profit or loss sharing or required Capital
                Contribution of any Participant or the Managing General Partner
                without the approval of the Participant or the Managing General
                Partner, respectively; and

           (b)  any amendment may not affect the classification of Partnership
                income and loss for federal income tax purposes without the
                unanimous approval of all Participants.

4.03(c)(3). RESTRICTIONS ON MANAGING GENERAL PARTNER'S VOTING RIGHTS. With
respect to Units owned by the Managing General Partner or its Affiliates, the
Managing General Partner and its Affiliates may vote or consent on all matters
other than the following:

     (i)  the matters set forth in Section 4.03(c)(2)(ii) and (iv) above; or

     (ii) any transaction between the Partnership and the Managing General
          Partner or its Affiliates.

In determining the requisite percentage in interest of Units necessary to
approve any Partnership matter on which the Managing General Partner and its
Affiliates may not vote or consent, any Units owned by the Managing General
Partner and its Affiliates shall not be included.

4.03(c)(4). RESTRICTIONS ON LIMITED PARTNER VOTING RIGHTS. The exercise by the
Limited Partners of the rights granted Participants under Section 4.03(c),
except for the special voting rights granted Participants under Section
4.03(c)(2), shall be subject to the prior legal determination that the grant or
exercise of the powers will not adversely affect the limited liability of
Limited Partners. Notwithstanding the foregoing, if in the opinion of counsel to
the Partnership the legal determination is not necessary under Delaware law to
maintain the limited liability of the Limited Partners, then it shall not be
required. A legal determination under this paragraph may be made either pursuant
to:

     (i)  an opinion of counsel, the counsel being independent of the
          Partnership and selected on the vote of Limited Partners whose Units
          equal a majority of the total Units held by Limited Partners; or

     (ii) a declaratory judgment issued by a court of competent jurisdiction.

The Investor General Partners may exercise the rights granted to the
Participants whether or not the Limited Partners can participate in the vote if
the Investor General Partners represent the requisite percentage of Units
necessary to take the action.


                                       25

<PAGE>

4.03(d). TRANSACTIONS WITH THE MANAGING GENERAL PARTNER.

4.03(d)(1). TRANSFER OF EQUAL PROPORTIONATE INTEREST. When the Managing General
Partner or an Affiliate (excluding another Program in which the interest of the
Managing General Partner or its Affiliates is substantially similar to or less
than their interest in the Partnership) sells, transfers or conveys any natural
gas, oil or other mineral interests or property to the Partnership, it must, at
the same time, sell, transfer or convey to the Partnership an equal
proportionate interest in all its other property in the same Prospect.
Notwithstanding, a Prospect shall be deemed to consist of the drilling or
spacing unit on which the well will be drilled by the Partnership, which is the
minimum area permitted by state law or local practice on which one well may be
drilled, if the following two conditions are met:

     (i)  the geological feature to which the well will be drilled contains
          Proved Reserves; and

     (ii) the drilling or spacing unit protects against drainage.

With respect to a Prospect located in Ohio, Pennsylvania and New York on which a
well will be drilled by the Partnership to test the Clinton/Medina geological
formation or the Mississippian and/or Upper Devonian Sandstone reservoirs, and
with respect to a Prospect located in Anderson, Campbell, Morgan, Roane and
Scott Counties, Tennessee on which a well will be drilled to test the
Mississippian carbonate or Devonian Shale reservoirs, a Prospect shall be deemed
to consist of the drilling and spacing unit if it meets the test in the
preceding sentence. Additionally, for a period of five years after the drilling
of the Partnership Well neither the Managing General Partner nor its Affiliates
may drill any well:

     (i)  to the Clinton/Medina geological formation, if the well would be
          within 1,650 feet of an existing Partnership Well in Pennsylvania or
          within 1,000 feet of an existing Partnership Well in Ohio; or

     (ii) to the Mississippian and/or Upper Devonian Sandstone reservoirs in
          Fayette, Greene and Westmoreland Counties, Pennsylvania, if the will
          would be within 1,000 feet from a producing Partnership Well, although
          the Partnership may drill a new well or re-enter an existing well
          which is closer than 1,000 feet to a plugged and abandoned well.

If the Partnership abandons its interest in a well, then the restrictions
described above shall continue for one year following the abandonment.

If the area constituting the Partnership's Prospect is subsequently enlarged to
encompass any area in which the Managing General Partner or an Affiliate
(excluding another Program in which the interest of the Managing General Partner
or its Affiliates is substantially similar to or less than their interest in the
Partnership) owns a separate property interest and the activities of the
Partnership were material in establishing the existence of Proved Undeveloped
Reserves that are attributable to the separate property interest, then the
separate property interest or a portion thereof must be sold, transferred, or
conveyed to the Partnership as set forth in this section and Sections 4.01(a)(4)
and 4.03(d)(2).

Notwithstanding the foregoing, Prospects drilled to the Clinton/Medina
geological formation, the Mississippian and/or Upper Devonian Sandstone
reservoirs, the Mississippian carbonate or Devonian Shale reservoirs, or any
other formation or reservoir shall not be enlarged or contracted if the Prospect
was limited to the drilling or spacing unit because the well was being drilled
to Proved Reserves in the geological formation and the drilling or spacing unit
protected against drainage.

4.03(d)(2). TRANSFER OF LESS THAN THE MANAGING GENERAL PARTNER'S AND ITS
AFFILIATES' ENTIRE INTEREST. A sale, transfer or a conveyance to the Partnership
of less than all of the ownership of the Managing General Partner or an
Affiliate (excluding another Program in which the interest of the Managing
General Partner or its Affiliates is substantially similar to or less than their
interest in the Partnership) in any Prospect shall not be made unless:

     (i)   the interest retained by the Managing General Partner or the
           Affiliate is a proportionate Working Interest;

     (ii)  the respective obligations of the Managing General Partner or its
           Affiliates and the Partnership are substantially the same after the
           sale of the interest by the Managing General Partner or its
           Affiliates; and


                                       26

<PAGE>

     (iii) the Managing General Partner's interest in revenues does not exceed
           the amount proportionate to its retained Working Interest.

This section does not prevent the Managing General Partner or its Affiliates
from subsequently dealing with their retained interest as they may choose with
unaffiliated parties or Affiliated partnerships.

4.03(d)(3). LIMITATIONS ON SALE OF UNDEVELOPED AND DEVELOPED LEASES TO THE
MANAGING GENERAL PARTNER. Other than another Program managed by the Managing
General Partner and its Affiliates as set forth in Sections 4.03(d)(5) and
4.03(d)(9), the Managing General Partner and its Affiliates shall not receive a
Farmout or purchase any undeveloped Leases from the Partnership other than at
the higher of Cost or fair market value.

The Managing General Partner and its Affiliates, other than an Affiliated Income
Program, shall not purchase any producing natural gas or oil property from the
Partnership unless:

     (i)   the sale is in connection with the liquidation of the Partnership; or

     (ii)  the Managing General Partner's well supervision fees under the
           Drilling and Operating Agreement for the well have exceeded the net
           revenues of the well, determined without regard to the Managing
           General Partner's well supervision fees for the well, for a period of
           at least three consecutive months.

Under both (i) and (ii) above, the sale must be at fair market value supported
by an appraisal of an Independent Expert selected by the Managing General
Partner.

4.03(d)(4). LIMITATIONS ON ACTIVITIES OF THE MANAGING GENERAL PARTNER AND ITS
AFFILIATES ON LEASES ACQUIRED BY THE PARTNERSHIP. During a period of five years
after the Offering Termination Date of the Partnership, if the Managing General
Partner or any of its Affiliates (excluding another Program in which the
interest of the Managing General Partner or its Affiliates is substantially
similar to or less than their interest in the Partnership) proposes to acquire
an interest from an unaffiliated person in a Prospect in which the Partnership
possesses an interest or in a Prospect in which the Partnership's interest has
been terminated without compensation within one year preceding the proposed
acquisition, then the following conditions shall apply:

     (i)  if the Managing General Partner or the Affiliate (excluding another
          Program in which the interest of the Managing General Partner or its
          Affiliates is substantially similar to or less than their interest in
          the Partnership) does not currently own property in the Prospect
          separately from the Partnership, then neither the Managing General
          Partner nor the Affiliate shall be permitted to purchase an interest
          in the Prospect; and

     (ii) if the Managing General Partner or the Affiliate (excluding another
          Program in which the interest of the Managing General Partner or its
          Affiliates is substantially similar to or less than their interest in
          the Partnership) currently owns a proportionate interest in the
          Prospect separately from the Partnership, then the interest to be
          acquired shall be divided between the Partnership and the Managing
          General Partner or the Affiliate in the same proportion as is the
          other property in the Prospect. Provided, however, if cash or
          financing is not available to the Partnership to enable it to complete
          a purchase of the additional interest to which it is entitled, then
          neither the Managing General Partner nor the Affiliate shall be
          permitted to purchase any additional interest in the Prospect.

4.03(d)(5). TRANSFER OF LEASES BETWEEN AFFILIATED LIMITED PARTNERSHIPS. The
transfer of an undeveloped Lease from the Partnership to another drilling
Program sponsored or managed by the Managing General Partner or its Affiliates
must be made at fair market value if the undeveloped Lease has been held by the
Partnership for more than two years. Otherwise, if the Managing General Partner
deems it to be in the best interest of the Partnership, the transfer may be made
at Cost.

An Affiliated Income Program may purchase a producing natural gas and oil
property from the Partnership at any time at:


                                       27

<PAGE>

     (i)   fair market value as supported by an appraisal from an Independent
           Expert if the property has been held by the Partnership for more than
           six months or the Partnership has made significant expenditures have
           been made in connection with the property; or

     (ii)  Cost, as adjusted for intervening operations, if the Managing General
           Partner deems it to be in the best interest of the Partnership.

However, these prohibitions shall not apply to joint ventures or Farmouts among
Affiliated partnerships, provided that:

     (i)   the respective obligations and revenue sharing of all parties to the
           transaction are substantially the same; and

     (ii)  the compensation arrangement or any other interest or right of either
           the Managing General Partner or its Affiliates is the same in each
           Affiliated partnership or if different, the aggregate compensation of
           the Managing General Partner or the Affiliate is reduced to reflect
           the lower compensation arrangement.

4.03(d)(6). SALE OF ALL ASSETS. The sale of all or substantially all of the
assets of the Partnership, including without limitation, Leases, wells,
equipment and production therefrom, shall be made only with the consent of
Participants whose Units equal a majority of the total Units.

4.03(d)(7). SERVICES.

4.03(d)(7)(a). COMPETITIVE RATES. The Managing General Partner and any Affiliate
shall not render to the Partnership any oil field, equipage, or other services
nor sell or lease to the Partnership any equipment or related supplies unless:

     (i)   the person is engaged, independently of the Partnership and as an
           ordinary and ongoing business, in the business of rendering the
           services or selling or leasing the equipment and supplies to a
           substantial extent to other persons in the natural gas and oil
           industry in addition to the partnerships in which the Managing
           General Partner or an Affiliate has an interest; and

     (ii)  the compensation, price, or rental therefor is competitive with the
           compensation, price, or rental of other persons in the area engaged
           in the business of rendering comparable services or selling or
           leasing comparable equipment and supplies which could reasonably be
           made available to the Partnership.

If the person is not engaged in such a business, then the compensation, price or
rental shall be the Cost of the services, equipment or supplies to the person or
the competitive rate which could be obtained in the area, whichever is less.

4.03(d)(7)(b). IF NOT DISCLOSED IN THE PROSPECTUS OR THIS AGREEMENT, THEN
SERVICES BY THE MANAGING GENERAL PARTNER MUST BE DESCRIBED IN A SEPARATE
CONTRACT AND CANCELABLE. Any services for which the Managing General Partner or
an Affiliate is to receive compensation, other than those described in this
Agreement or the Prospectus, shall be set forth in a written contract which
precisely describes the services to be rendered and all compensation to be paid.
These contracts shall be cancelable without penalty on 60 days written notice by
Participants whose Units equal a majority of the total Units.

4.03(d)(8). LOANS.

4.03(d)(8)(a). NO LOANS FROM THE PARTNERSHIP. No loans or advances shall be made
by the Partnership to the Managing General Partner or its Affiliates.

4.03(d)(8)(b). LOANS TO THE PARTNERSHIP. Neither the Managing General Partner
nor any Affiliate shall loan money to the Partnership if the interest to be
charged exceeds either:

     (i)   the Managing General Partner's or the Affiliate's interest cost; or

     (ii)  that which would be charged to the Partnership, without reference to
           the Managing General Partner's or the Affiliate's financial abilities
           or guarantees, by unrelated lenders, on comparable loans for the same
           purpose.


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<PAGE>

Neither the Managing General Partner nor any Affiliate shall receive points or
other financing charges or fees, regardless of the amount, although the actual
amount of the charges incurred by them from third-party lenders may be
reimbursed to the Managing General Partner or the Affiliate.

4.03(d)(9). FARMOUTS. The Managing General Partner shall not enter into a
Farmout to avoid its paying its share of costs related to drilling a well on an
undeveloped Lease. The Partnership shall not Farmout an undeveloped Lease or
well activity to the Managing General Partner or its Affiliates except as set
forth in Section 4.03(d)(3). Notwithstanding, this restriction shall not apply
to Farmouts between the Partnership and another partnership managed by the
Managing General Partner or its Affiliates, either separately or jointly,
provided that the respective obligations and revenue sharing of all parties to
the transactions are substantially the same and the compensation arrangement or
any other interest or right of the Managing General Partner or its Affiliates is
the same in each partnership, or, if different, the aggregate compensation of
the Managing General Partner and its Affiliates is reduced to reflect the lower
compensation agreement.

The Partnership may Farmout an undeveloped lease or well activity only if the
Managing General Partner, exercising the standard of a prudent operator,
determines that:

     (i)   the Partnership lacks the funds to complete the oil and gas
           operations on the Lease or well and cannot obtain suitable financing;

     (ii)  drilling on the Lease or the intended well activity would concentrate
           excessive funds in one location, creating undue risks to the
           Partnership;

     (iii) the Leases or well activity have been downgraded by events occurring
           after assignment to the Partnership so that development of the Leases
           or well activity would not be desirable; or

     (iv)  the best interests of the Partnership would be served.

If the Partnership Farmouts a Lease or well activity, the Managing General
Partner must retain on behalf of the Partnership the economic interests and
concessions as a reasonably prudent oil and gas operator would or could retain
under the circumstances prevailing at the time, consistent with industry
practices.

4.03(d)(10). NO COMPENSATING BALANCES. Neither the Managing General Partner nor
any Affiliate shall use the Partnership's funds as compensating balances for its
own benefit.

4.03(d)(11). FUTURE PRODUCTION. Neither the Managing General Partner nor any
Affiliate shall commit the future production of a well developed by the
Partnership exclusively for its own benefit.

4.03(d)(12). MARKETING ARRANGEMENTS. Subject to Section 4.06(c), all benefits
from marketing arrangements or other relationships affecting the property of the
Managing General Partner or its Affiliates and the Partnership shall be fairly
and equitably apportioned according to the respective interests of each in the
property. The Managing General Partner shall treat all wells in a geographic
area equally concerning to whom and at what price the Partnership's natural gas
and oil will be sold and to whom and at what price the natural gas and oil of
other natural gas and oil Programs which the Managing General Partner has
sponsored or will sponsor will be sold. For example, each seller of natural gas
and oil in a given area will be paid a weighted average selling price for all
natural gas and oil sold in that geographic area. The Managing General Partner,
in its sole discretion, shall determine what constitutes a geographic area.

4.03(d)(13). ADVANCE PAYMENTS. Advance payments by the Partnership to the
Managing General Partner and its Affiliates are prohibited except when advance
payments are required to secure the tax benefits of prepaid Intangible Drilling
Costs for a business purpose as set forth in the Drilling and Operating
Agreement.

4.03(d)(14). NO REBATES. No rebates or give-ups may be received by the Managing
General Partner or any Affiliate nor may the Managing General Partner or any
Affiliate participate in any reciprocal business arrangements that would
circumvent the provisions of this section.


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<PAGE>

4.03(d)(15). PARTICIPATION IN OTHER PARTNERSHIPS. If the Partnership
participates in other partnerships or joint ventures (multi-tier arrangements),
then the terms of any of these arrangements shall not result in the
circumvention of any of the requirements or prohibitions contained in this
Agreement, including the following:

     (i)   there shall be no duplication or increase in Organization and
           Offering Costs, the Managing General Partner's compensation,
           Partnership expenses or other fees and costs;

     (ii)  there shall be no substantive alteration in the fiduciary and
           contractual relationship between the Managing General Partner and the
           Participants; and

     (iii) there shall be no diminishment in the voting rights of the
           Participants.

4.03(d)(16). ROLL-UP LIMITATIONS.

4.03(d)(16)(a). REQUIREMENT FOR APPRAISAL AND ITS ASSUMPTIONS. In connection
with a proposed Roll-Up, an appraisal of all Partnership assets shall be
obtained from a competent Independent Expert. If the appraisal will be included
in a prospectus used to offer securities of a Roll-Up Entity, then the appraisal
shall be filed with the SEC and the Administrator as an exhibit to the
registration statement for the offering. Thus, an issuer using the appraisal
shall be subject to liability for violation of Section 11 of the Securities Act
of 1933 and comparable provisions under state law for any material
misrepresentations or material omissions in the appraisal.

Partnership assets shall be appraised on a consistent basis. The appraisal shall
be based on all relevant information, including current reserve estimates
prepared as set forth in Section 4.03(b)(3), and shall indicate the value of the
Partnership's assets as of a date immediately before the announcement of the
proposed Roll-Up transaction. The appraisal shall assume an orderly liquidation
of the Partnership's assets over a 12-month period.

The terms of the engagement of the Independent Expert shall clearly state that
the engagement is for the benefit of the Partnership and the Participants. A
summary of the independent appraisal, indicating all material assumptions
underlying the appraisal, shall be included in a report to the Participants in
connection with a proposed Roll-Up.

4.03(d)(16)(b). RIGHTS OF PARTICIPANTS WHO VOTE AGAINST PROPOSAL. In connection
with a proposed Roll-Up, Participants who vote "no" on the proposal shall be
offered the choice of:

     (i)  accepting the securities of the Roll-Up Entity offered in the proposed
          Roll-Up; or

     (ii) one of the following:

          (a)  remaining as Participants in the Partnership and preserving their
               Units in the Partnership on the same terms and conditions as
               existed previously; or

          (b)  receiving cash in an amount equal to the Participants' pro rata
               share of the appraised value of the net assets of the Partnership
               based on their respective number of Units.

4.03(d)(16)(c). NO ROLL-UP IF DIMINISHMENT OF VOTING RIGHTS. The Partnership
shall not participate in any proposed Roll-Up which, if approved, would result
in the diminishment of any Participant's voting rights under the Roll-Up
Entity's chartering agreement. In no event shall the democracy rights of
Participants in the Roll-Up Entity be less than those provided for under
Sections 4.03(c)(1) and 4.03(c)(2). If the Roll-Up Entity is a corporation, then
the democracy rights of Participants shall correspond to the democracy rights
provided for in this Agreement to the greatest extent possible.

4.03(d)(16)(d). NO ROLL-UP IF ACCUMULATION OF SHARES WOULD BE IMPEDED. The
Partnership shall not participate in any proposed Roll-Up transaction which
includes provisions that would operate to materially impede or frustrate the
accumulation of shares by any purchaser of the securities of the Roll-Up Entity,
except to the minimum extent necessary to preserve the tax status of the Roll-Up
Entity. The Partnership shall not participate in any proposed Roll-Up
transaction which would limit the ability of a Participant to exercise the
voting rights of its securities of the Roll-Up Entity on the basis of the number
of Units held by that Participant.


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<PAGE>

4.03(d)(16)(e). NO ROLL-UP IF ACCESS TO RECORDS WOULD BE LIMITED. The
Partnership shall not participate in a Roll-Up in which Participants' rights of
access to the records of the Roll-Up Entity would be less than those provided
for under Sections 4.03(b)(5), 4.03(b)(6) and 4.03(b)(7).

4.03(d)(16)(f). COST OF ROLL-UP. The Partnership shall not participate in any
proposed Roll-Up transaction in which any of the costs of the transaction would
be borne by the Partnership if Participants whose Units equal 66% of the total
Units do not vote to approve the proposed Roll-Up.

4.03(d)(16)(g). ROLL-UP APPROVAL. The Partnership shall not participate in a
Roll-Up transaction unless the Roll-Up transaction is approved by Participants
whose Units equal 66% of the total Units.

4.03(d)(17). DISCLOSURE OF BINDING AGREEMENTS. Any agreement or arrangement
which binds the Partnership must be disclosed in the Prospectus.

4.03(d)(18). TRANSACTIONS MUST BE FAIR AND REASONABLE. Neither the Managing
General Partner nor any Affiliate shall sell, transfer, or convey any property
to or purchase any property from the Partnership, directly or indirectly, except
under transactions that are fair and reasonable, nor take any action with
respect to the assets or property of the Partnership which does not primarily
benefit the Partnership.

4.04. DESIGNATION, COMPENSATION AND REMOVAL OF MANAGING GENERAL PARTNER AND
REMOVAL OF OPERATOR.

4.04(a). MANAGING GENERAL PARTNER.

4.04(a)(1). TERM OF SERVICE. Except as otherwise provided in this Agreement,
Atlas shall serve as the Managing General Partner of the Partnership until
either it:

     (i)  is removed pursuant to Section 4.04(a)(3); or

     (ii) withdraws pursuant to Section 4.04(a)(3)(f).

4.04(a)(2). COMPENSATION OF MANAGING GENERAL PARTNER. In addition to the
compensation set forth in Sections 4.01(a)(4) and 4.02(d)(1), the Managing
General Partner shall receive the compensation set forth in Sections
4.04(a)(2)(b) through 4.04(a)(2)(g).

4.04(a)(2)(a). CHARGES MUST BE NECESSARY AND REASONABLE. Charges by the Managing
General Partner for goods and services must be fully supportable as to:

     (i)  the necessity of the goods and services; and

     (ii) the reasonableness of the amount charged.

All actual and necessary expenses incurred by the Partnership may be paid out of
the Partnership's subscription proceeds and revenues.

4.04(a)(2)(b). DIRECT COSTS. The Managing General Partner and its Affiliates
shall be reimbursed for all Direct Costs. Direct Costs, however, shall be billed
directly to and paid by the Partnership to the extent practicable.

4.04(a)(2)(c). ADMINISTRATIVE COSTS. The Managing General Partner shall receive
a nonaccountable, fixed payment reimbursement for its Administrative Costs of
$75 per well per month. The nonaccountable, fixed payment reimbursement of $75
per well per month shall be subject to the following:

     (i)   it shall not be increased in amount during the term of the
           Partnership;

     (ii)  it shall be proportionately reduced to the extent the Partnership
           acquires less than 100% of the Working Interest in the well;


                                       31

<PAGE>

     (iii) it shall be the entire payment to reimburse the Managing General
           Partner for the Partnership's Administrative Costs; and

     (iv)  it shall not be received for plugged or abandoned wells.

4.04(a)(2)(d). GAS GATHERING. The Managing General Partner, not acting as a
Partner, shall be responsible for gathering and transporting the natural gas
produced by the Partnership to interstate pipeline systems, local distribution
companies, and/or end-users in the area (the "gathering services"). In providing
the gathering services, the Managing General Partner may use the gathering
system owned by Atlas Pipeline Partners, as described in the Prospectus, and
gathering systems owned by independent third-parties and/or Affiliates of Atlas
America other than Atlas Pipeline Partners.

The Partnership shall pay a gathering fee directly to the Managing General
Partner at competitive rates for the gathering services. The gathering fee paid
by the Partnership to the Managing General Partner may be increased from
time-to-time by the Managing General Partner, in its sole discretion, but may
not increase beyond competitive rates as determined by the Managing General
Partner. Currently, the Managing General Partner has determined that the
competitive rate is an amount equal to 10% of the gross sales price received by
the Partnership for its natural gas in each of its primary or secondary areas as
described in the Prospectus. Gross sales price means the price that is actually
received, adjusted to take into account proceeds received or payments made
pursuant to hedging arrangements. The payment of a competitive fee to the
Managing General Partner for its gathering services shall be subject to the
following conditions:

     (i)   If the Partnership's natural gas production is gathered and
           transported through the gathering system owned by Atlas Pipeline
           Partners, then the Managing General Partner shall apply its gathering
           fee towards the related gathering fee obligation of Atlas America,
           Inc., Resource Energy, LLC, and Viking Resources LLC (the "Atlas
           Entities") under their agreement with Atlas Pipeline Partners as
           described in the Prospectus.

     (ii)  If a third-party gathering system is used by the Partnership, then
           the Managing General Partner shall pay a portion or all of the
           gathering fee it receives from the Partnership to the third-party
           gathering the natural gas. The Managing General Partner may retain
           the excess of any gathering fees it receives from the Partnership
           over the payments it makes to third-party gas gatherers. If the
           third-party's gathering system charges more than an amount equal to
           10% of the gross sales price, then the Managing General Partner's
           gathering fee charged to the Partnership shall be the actual
           transportation and compression fees charged by the third-party
           gathering system with respect to the Partnership's natural gas in the
           area.

     (iii) If both a third-party gathering system and the Atlas Pipeline
           Partners gathering system (or a gas gathering system owned by an
           affiliate of Atlas America other than Atlas Pipeline Partners) are
           used by the Partnership, then the Managing General Partner shall
           receive an amount equal to 10% of the gross sales price plus the
           amount charged by the third-party gathering system. For purposes of
           illustration, but not limitation, the Partnership will deliver
           natural gas produced from certain wells drilled by the Partnership in
           the Upper Devonian Sandstone Reservoirs in the McKean County,
           Pennsylvania area into a gathering system, a segment of which will be
           provided by Atlas Pipeline Partners and a segment of which will be
           provided by a third-party. The Managing General Partner will receive
           a gathering fee composed of $.35 per mcf for transportation and
           compression, which may be increased from time-to-time, that the
           Managing General Partner will pay to the third-party gathering the
           natural gas, and a gathering fee equal to 10% of the gross sales
           price of the natural gas.

With respect to the Knox project and natural gas produced from the Mississippian
and Devonian Shale Reservoirs in Anderson, Campbell, Morgan, Roane and Scott
Counties, Tennessee as described in the Prospectus, if the Coalfield Pipeline
does not have sufficient capacity to compress and transport the natural gas
produced from the Partnership's wells as determined by Atlas America, then Atlas
America or an Affiliate other than Atlas Pipeline Partners may construct an
additional gathering system and/or enhancements to the Coalfield Pipeline. On
completion of the construction, Atlas America will transfer its ownership in the
additional gathering system and/or enhancements to the owners of Coalfield
Pipeline, which will then pay Atlas America an amount equal to $.12 per mcf of
natural gas transported through the newly constructed and/or enhanced gathering
system. Coalfield Pipeline will pay this amount of $.12 per mcf to Atlas America
from its gathering and compression fees charged to the Partnership.


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<PAGE>

4.04(a)(2)(e). DEALER-MANAGER FEE. Subject to Section 3.03(a)(1), the
Dealer-Manager shall receive on each Unit sold to investors:

     (i)   a 2.5% Dealer-Manager fee;

     (ii)  a 7% Sales Commission; and

     (iii) an up to .5% reimbursement of the Selling Agents' bona fide due
           diligence expenses.

4.04(a)(2)(f). DRILLING AND OPERATING AGREEMENT. The Managing General Partner
and its Affiliates shall receive compensation as set forth in the Drilling and
Operating Agreement.

4.04(a)(2)(g). OTHER TRANSACTIONS. The Managing General Partner and its
Affiliates may enter into transactions pursuant to Section 4.03(d)(7) with the
Partnership and shall be entitled to compensation under that section.

4.04(a)(3). REMOVAL OF MANAGING GENERAL PARTNER.

4.04(a)(3)(a). MAJORITY VOTE REQUIRED TO REMOVE THE MANAGING GENERAL PARTNER.
The Managing General Partner may be removed at any time on 60 days' advance
written notice to the outgoing Managing General Partner by the affirmative vote
of Participants whose Units equal a majority of the total Units.

If the Participants vote to remove the Managing General Partner from the
Partnership, then Participants must elect by an affirmative vote of Participants
whose Units equal a majority of the total Units either to:

     (i)  dissolve, wind-up, and terminate the Partnership; or

     (ii) continue as a successor limited partnership under all the terms of
          this Partnership Agreement as provided in Section 7.01(c).

If the Participants elect to continue as a successor limited partnership, then
the Managing General Partner shall not be removed until a substituted Managing
General Partner has been selected by an affirmative vote of Participants whose
Units equal a majority of the total Units and installed as such.

4.04(a)(3)(b). VALUATION OF MANAGING GENERAL PARTNER'S INTEREST IN THE
PARTNERSHIP. If the Managing General Partner is removed, then its interest in
the Partnership shall be determined by appraisal by a qualified Independent
Expert. The Independent Expert shall be selected by mutual agreement between the
removed Managing General Partner and the incoming Managing General Partner. The
appraisal shall take into account an appropriate discount, to reflect the risk
of recovering natural gas and oil reserves, which shall not be less than that
used to calculate the presentment price in the most recent presentment offer
under Section 6.03, if any.

The cost of the appraisal shall be borne equally by the removed Managing General
Partner and the Partnership.

4.04(a)(3)(c). INCOMING MANAGING GENERAL PARTNER'S OPTION TO PURCHASE. The
incoming Managing General Partner shall have the option to purchase 20% of the
removed Managing General Partner's interest in the Partnership as Managing
General Partner, but not as a Participant, for the value determined by the
Independent Expert.

4.04(a)(3)(d). METHOD OF PAYMENT. The method of payment for the removed Managing
General Partner's interest must be fair and protect the solvency and liquidity
of the Partnership. The method of payment shall be as follows:

     (i)  when the termination is voluntary, the method of payment shall be a
          non-interest bearing unsecured promissory note with principal payable,
          if at all, from distributions which the Managing General Partner
          otherwise would have received under this Agreement had the Managing
          General Partner not been terminated; and


                                       33

<PAGE>

     (ii) when the termination is involuntary, the method of payment shall be an
          interest bearing unsecured promissory note coming due in no less than
          five years with equal installments each year. The interest rate shall
          be that charged on comparable loans.

4.04(a)(3)(e). TERMINATION OF CONTRACTS. At the time of its removal, the removed
Managing General Partner shall cause, to the extent it is legally possible to do
so, its successor to be transferred or assigned all of its rights, obligations
and interests as Managing General Partner of the Partnership in contracts
entered into by it on behalf of the Partnership. In any event, the removed
Managing General Partner shall cause all of its rights, obligations and
interests as Managing General Partner of the Partnership in any such contract to
terminate at the time of its removal.

Notwithstanding any other provision in this Agreement, the Partnership or the
successor Managing General Partner shall not:

     (i)   be a party to any natural gas supply agreement that the Managing
           General Partner or its Affiliates enters into with a third-party;

     (ii)  have any rights pursuant to such natural gas supply agreement; or

     (iii) receive any interest in the Managing General Partner's and its
           Affiliates' pipeline or gathering system or compression facilities.

4.04(a)(3)(f). THE MANAGING GENERAL PARTNER'S RIGHT TO VOLUNTARILY WITHDRAW. At
any time beginning 10 years after the Offering Termination Date and the
Partnership's primary drilling activities, the Managing General Partner may
voluntarily withdraw as Managing General Partner on giving 120 days' written
notice of withdrawal to the Participants. If the Managing General Partner
withdraws, then the following conditions shall apply:

     (i)  the Managing General Partner's interest in the Partnership shall be
          determined as described in Section 4.04(a)(3)(b) above with respect to
          removal; and

     (ii) the interest shall be distributed to the Managing General Partner as
          described in Section 4.04(a)(3)(d)(i) above.

Any successor Managing General Partner shall have the option to purchase 20% of
the withdrawing Managing General Partner's interest in the Partnership at the
value determined as described above with respect to removal.

4.04(a)(3)(g). RIGHT OF MANAGING GENERAL PARTNER TO HYPOTHECATE ITS INTERESTS.
The Managing General Partner shall have the authority without the consent of the
Participants and without affecting the allocation of costs and revenues received
or incurred under this Agreement, to hypothecate, pledge, or otherwise encumber,
on any terms it chooses for its own general purposes, either:

     (i)  its Partnership interest; or

     (ii) an undivided interest in the assets of the Partnership equal to or
          less than its respective interest as Managing General Partner in the
          revenues of the Partnership.

All repayments of these borrowings and costs, interest or other charges related
to the borrowings shall be borne and paid separately by the Managing General
Partner. In no event shall the repayments, costs, interest, or other charges
related to the borrowing be charged to the account of the Participants.

4.04(a)(3)(h). THE MANAGING GENERAL PARTNER'S RIGHT TO WITHDRAW PROPERTY
INTEREST. The Managing General Partner shall have the right to withdraw a
property interest held by the Partnership in the form of a Working Interest in
the Partnership's Wells equal to or less than its respective interest as
Managing General Partner in the revenues of the Partnership if:

     (i)  the withdrawal is necessary to satisfy the bona fide request of its
          creditors; or

     (ii) the withdrawal is approved by Participants whose Units equal a
          majority of the total Units.


                                       34

<PAGE>

If the Managing General Partner withdraws a property interest from the
Partnership as described above, then the Managing General Partner shall:

     (i)  pay the expenses of withdrawing; and

     (ii) fully indemnify the Partnership against any additional expenses which
          may result from the withdrawal of its property interest, including
          insuring that a greater amount of Direct Costs or Administrative Costs
          is not allocated to the Participants.

4.04(a)(4). REMOVAL OF OPERATOR. The Operator may be removed and a new Operator
may be substituted at any time on 60 days advance written notice to the outgoing
Operator by the Managing General Partner acting on behalf of the Partnership on
the affirmative vote of Participants whose Units equal a majority of the total
Units.

The Operator shall not be removed until a substituted Operator has been selected
by an affirmative vote of Participants whose Units equal a majority of the total
Units and installed as such.

4.05. INDEMNIFICATION AND EXONERATION.

4.05(a)(1). STANDARDS FOR THE MANAGING GENERAL PARTNER NOT INCURRING LIABILITY
TO THE PARTNERSHIP OR PARTICIPANTS. The Managing General Partner, the Operator,
and their Affiliates shall not have any liability whatsoever to the Partnership,
or to any Participant for any loss suffered by the Partnership or the
Participants which arises out of any action or inaction of the Managing General
Partner, the Operator, or their Affiliates if:

     (i)   the Managing General Partner, the Operator, and their Affiliates
           determined in good faith that the course of conduct was in the best
           interest of the Partnership;

     (ii)  the Managing General Partner, the Operator, and their Affiliates were
           acting on behalf of, or performing services for, the Partnership; and

     (iii) the course of conduct did not constitute negligence or misconduct of
           the Managing General Partner, the Operator, or their Affiliates.

4.05(a)(2). STANDARDS FOR MANAGING GENERAL PARTNER INDEMNIFICATION. The Managing
General Partner, the Operator, and their Affiliates shall be indemnified by the
Partnership against any losses, judgments, liabilities, expenses, and amounts
paid in settlement of any claims sustained by them in connection with the
Partnership, provided that:

     (i)   the Managing General Partner, the Operator, and their Affiliates
           determined in good faith that the course of conduct which caused the
           loss or liability was in the best interest of the Partnership;

     (ii)  the Managing General Partner, the Operator, and their Affiliates were
           acting on behalf of, or performing services for, the Partnership; and

     (iii) the course of conduct was not the result of negligence or misconduct
           of the Managing General Partner, the Operator, or their Affiliates.

Provided, however, payments arising from such indemnification or agreement to
hold harmless are recoverable only out of the following:

     (i)  the Partnership's tangible net assets, which include its revenues; and

     (ii) any insurance proceeds from the types of insurance for which the
          Managing General Partner, the Operator and their Affiliates may be
          indemnified under this Agreement.

4.05(a)(3). STANDARDS FOR SECURITIES LAW INDEMNIFICATION. Notwithstanding
anything to the contrary contained in this section, the Managing General
Partner, the Operator, and their Affiliates and any person acting as a
broker/dealer with respect


                                       35

<PAGE>

to the offer or sale of the Units, shall not be indemnified for any losses,
liabilities or expenses arising from or out of an alleged violation of federal
or state securities laws by such party unless:

     (i)   there has been a successful adjudication on the merits of each count
           involving alleged securities law violations as to the particular
           indemnitee;

     (ii)  the claims have been dismissed with prejudice on the merits by a
           court of competent jurisdiction as to the particular indemnitee; or

     (iii) a court of competent jurisdiction approves a settlement of the claims
           against a particular indemnitee and finds that indemnification of the
           settlement and the related costs should be made, and the court
           considering the request for indemnification has been advised of the
           position of the SEC, the Massachusetts Securities Division, and any
           state securities regulatory authority in which plaintiffs claim they
           were offered or sold Units with respect to the issue of
           indemnification for violation of securities laws.

4.05(a)(4). STANDARDS FOR ADVANCEMENT OF FUNDS TO THE MANAGING GENERAL PARTNER
AND INSURANCE. The advancement of Partnership funds to the Managing General
Partner, the Operator, or their Affiliates for legal expenses and other costs
incurred as a result of any legal action for which indemnification is being
sought from the Partnership is permissible only if the Partnership has adequate
funds available and the following conditions are satisfied:

     (i)   the legal action relates to acts or omissions with respect to the
           performance of duties or services on behalf of the Partnership;

     (ii)  the legal action is initiated by a third-party who is not a
           Participant, or the legal action is initiated by a Participant and a
           court of competent jurisdiction specifically approves the
           advancement; and

     (iii) the Managing General Partner or its Affiliates undertake to repay the
           advanced funds to the Partnership, together with the applicable legal
           rate of interest thereon, in cases in which such party is found not
           to be entitled to indemnification.

The Partnership shall not bear the cost of that portion of insurance which
insures the Managing General Partner, the Operator, or their Affiliates for any
liability for which they could not be indemnified pursuant to Sections
4.05(a)(1) and 4.05(a)(2).

4.05(b). LIABILITY OF PARTNERS. Under the Delaware Revised Uniform Limited
Partnership Act, the Investor General Partners are liable jointly and severally
for all liabilities and obligations of the Partnership. Notwithstanding the
foregoing, as among themselves, the Investor General Partners agree that each
shall be solely and individually responsible only for his pro rata share of the
liabilities and obligations of the Partnership based on his respective number of
Units.

In addition, the Managing General Partner agrees to use its corporate assets to
indemnify each of the Investor General Partners against all Partnership related
liabilities which exceed the Investor General Partner's interest in the
undistributed net assets of the Partnership and insurance proceeds, if any.
Further, the Managing General Partner agrees to indemnify each Investor General
Partner against any personal liability as a result of the unauthorized acts of
another Investor General Partner.

If the Managing General Partner provides indemnification, then each Investor
General Partner who has been indemnified shall transfer and subrogate his rights
for contribution from or against any other Investor General Partner to the
Managing General Partner.

4.05(c). ORDER OF PAYMENT OF CLAIMS. Claims shall be paid as follows:

     (i)   first, out of any insurance proceeds;

     (ii)  second, out of Partnership assets and revenues; and

     (iii) last, by the Managing General Partner as provided in Sections
           3.05(b)(2) and (3) and 4.05(b).


                                       36

<PAGE>

No Limited Partner shall be required to reimburse the Managing General Partner,
the Operator, their Affiliates, or the Investor General Partners for any
liability in excess of his agreed Capital Contribution, except:

     (i)  for a liability resulting from the Limited Partner's unauthorized
          participation in management of the Partnership; or

     (ii) from some other breach by the Limited Partner of this Agreement.

4.05(d). AUTHORIZED TRANSACTIONS ARE NOT DEEMED TO BE A BREACH. No transaction
entered into or action taken by the Partnership, or by the Managing General
Partner, the Operator, or their Affiliates, which is authorized by this
Agreement shall be deemed a breach of any obligation owed by the Managing
General Partner, the Operator, or their Affiliates to the Partnership or the
Participants.

4.06. OTHER ACTIVITIES.

4.06(a). THE MANAGING GENERAL PARTNER MAY PURSUE OTHER NATURAL GAS AND OIL
ACTIVITIES FOR ITS OWN ACCOUNT. The Managing General Partner, the Operator, and
their Affiliates are now engaged, and will engage in the future, for their own
account and for the account of others, including other investors, in all aspects
of the natural gas and oil business. This includes without limitation, the
evaluation, acquisition, and sale of producing and nonproducing Leases, and the
exploration for and production of natural gas, oil and other minerals.

The Managing General Partner is required to devote only so much of its time to
the Partnership as it determines in its sole discretion, but consistent with its
fiduciary duties, is necessary to manage the affairs of the Partnership. Except
as expressly provided to the contrary in this Agreement, and subject to
fiduciary duties, the Managing General Partner, the Operator, and their
Affiliates may do the following:

     (i)   continue their activities, or initiate further such activities,
           individually, jointly with others, or as a part of any other limited
           or general partnership, tax partnership, joint venture, or other
           entity or activity to which they are or may become a party, in any
           locale and in the same fields, areas of operation or prospects in
           which the Partnership may likewise be active;

     (ii)  reserve partial interests in Leases being assigned to the Partnership
           or any other interests not expressly prohibited by this Agreement;

     (iii) deal with the Partnership as independent parties or through any other
           entity in which they may be interested;

     (iv)  conduct business with the Partnership as set forth in this Agreement;
           and

     (v)   participate in such other investor operations, as investors or
           otherwise.

The Managing General Partner and its Affiliates shall not be required to permit
the Partnership or the Participants to participate in or share in any profits or
other benefits from any of the other operations in which the Managing General
Partner and its Affiliates may be interested as permitted under this section.
However, except as otherwise provided in this Agreement, the Managing General
Partner and its Affiliates may pursue business opportunities that are consistent
with the Partnership's investment objectives for their own account only after
they have determined that the opportunity either:

     (i)  cannot be pursued by the Partnership because of insufficient funds; or

     (ii) it is not appropriate for the Partnership under the existing
          circumstances.

4.06(b). MANAGING GENERAL PARTNER MAY MANAGE MULTIPLE PARTNERSHIPS. The Managing
General Partner or its Affiliates may manage multiple Programs simultaneously.

4.06(c). PARTNERSHIP HAS NO INTEREST IN NATURAL GAS CONTRACTS OR PIPELINES AND
GATHERING SYSTEMS. Notwithstanding any other provision in this Agreement, the
Partnership shall not:


                                       37

<PAGE>

     (i)  be a party to any natural gas supply agreement that the Managing
          General Partner, the Operator, or their Affiliates enter into with a
          third-party or have any rights pursuant to such natural gas supply
          agreement; or

     (ii) receive any interest in the Managing General Partner's, the
          Operator's, and their Affiliates' pipeline or gathering system or
          compression facilities.

                                    ARTICLE V
                      PARTICIPATION IN COSTS AND REVENUES,
                  CAPITAL ACCOUNTS, ELECTIONS AND DISTRIBUTIONS

5.01. PARTICIPATION IN COSTS AND REVENUES. Except as otherwise provided in this
Agreement, costs and revenues of the Partnership shall be charged and credited
to the Managing General Partner and the Participants as set forth in this
section and its subsections.

5.01(a). COSTS. Costs shall be charged as set forth below.

5.01(a)(1). ORGANIZATION AND OFFERING COSTS. Organization and Offering Costs
shall be charged 100% to the Managing General Partner. For purposes of sharing
in revenues under Section 5.01(b)(4), the Managing General Partner shall be
credited with Organization and Offering Costs paid by it and for services
provided by it as Organization Costs up to an amount equal to 15% of the
Partnership's subscription proceeds. Any Organization and Offering Costs paid
and/or provided in services by the Managing General Partner in excess of this
amount shall not be credited towards the Managing General Partner's required
Capital Contribution or revenue share set forth in Section 5.01(b)(4). The
Managing General Partner's credit for services provided to the Partnership as
Organization Costs shall be determined based on generally accepted accounting
principles.

5.01(a)(2). INTANGIBLE DRILLING COSTS. Ninety percent (90%) of the Partnership's
subscription proceeds received from the Participants shall be used to pay 100%
of the Intangible Drilling Costs.

5.01(a)(3). TANGIBLE COSTS. Ten percent (10%) of the Partnership's subscription
proceeds received from the Participants shall be used by the Partnership to pay
Tangible Costs. All remaining Tangible Costs in excess of an amount equal to 10%
of the Partnership's subscription proceeds shall be charged 100% to the Managing
General Partner.

5.01(a)(4). OPERATING COSTS, DIRECT COSTS, ADMINISTRATIVE COSTS AND ALL OTHER
COSTS. Operating Costs, Direct Costs, Administrative Costs, and all other
Partnership costs not specifically allocated shall be charged to the parties in
the same ratio as the related production revenues are being credited.

5.01(a)(5). ALLOCATION OF INTANGIBLE DRILLING COSTS AND TANGIBLE COSTS AT
PARTNERSHIP CLOSINGS. Intangible Drilling Costs and the Participants' share of
Tangible Costs of a well or wells to be drilled and completed with the proceeds
of a Partnership closing shall be charged 100% to the Participants who are
admitted to the Partnership in that closing and shall not be reallocated to take
into account other Partnership closings.

Although the subscription proceeds received by the Partnership in each closing
may be used to pay the costs of drilling different wells, 90% of each
Participant's subscription proceeds shall be applied to Intangible Drilling
Costs and 10% of each Participant's subscription proceeds shall be applied to
Tangible Costs regardless of when the Participant subscribes for his Units or is
admitted to the Partnership.

5.01(a)(6). LEASE COSTS. The Leases shall be contributed to the Partnership by
the Managing General Partner as set forth in Section 4.01(a)(4).

5.01(b). REVENUES. Revenues shall be credited as set forth below.

5.01(b)(1). ALLOCATION OF REVENUES ON DISPOSITION OF PROPERTY. If the parties'
Capital Accounts are adjusted to reflect the simulated depletion of a natural
gas or oil property of the Partnership, then the portion of the total amount
realized by the Partnership on the taxable disposition of the property that
represents recovery of its simulated tax basis in the property shall be
allocated to the parties in the same proportion as the aggregate adjusted tax
basis of the property was allocated to the


                                       38

<PAGE>

parties or their predecessors in interest. If the parties' Capital Accounts are
adjusted to reflect the actual depletion of a natural gas or oil property of the
Partnership, then the portion of the total amount realized by the Partnership on
the taxable disposition of the property that equals the parties' aggregate
remaining adjusted tax basis in the property shall be allocated to the parties
in proportion to their respective remaining adjusted tax bases in the property.
Thereafter, any excess shall be allocated to the Managing General Partner in an
amount equal to the difference between the fair market value of the Lease at the
time it was contributed to the Partnership and its simulated or actual adjusted
tax basis at that time. Finally, any excess shall be credited as provided in
Section 5.01(b)(4), below.

In the event of the Partnership's sale of developed natural gas and oil
properties with equipment on the properties, the Managing General Partner may
make any reasonable allocation of the sales proceeds between the equipment and
the Leases.

5.01(b)(2). INTEREST. Interest earned on each Participant's subscription
proceeds before the Offering Termination Date under Section 3.05(b)(1) shall be
credited to the accounts of the respective subscribers who paid the subscription
proceeds to the Partnership. The interest shall be paid to the Participants not
later than the Partnership's first cash distribution from operations.

After the Offering Termination Date and until proceeds from the offering are
invested in the Partnership's natural gas and oil operations, any interest
income from temporary investments shall be allocated pro rata to the
Participants providing the subscription proceeds.

All other interest income, including interest earned on the deposit of
production revenues, shall be credited as provided in Section 5.01(b)(4), below.

5.01(b)(3). SALE OR DISPOSITION OF EQUIPMENT. Proceeds from the sale or
disposition of equipment shall be credited to the parties charged with the costs
of the equipment in the ratio in which the costs were charged.

5.01(b)(4). OTHER REVENUES. Subject to Section 5.01(b)(4)(a), the Managing
General Partner and the Participants shall share in all other Partnership
revenues in the same percentage as their respective Capital Contribution bears
to the Partnership's total Capital Contributions, except that the Managing
General Partner shall receive an additional 7% of Partnership revenues. However,
the Managing General Partner's total revenue share shall not exceed 40% of
Partnership revenues. For example, if the Managing General Partner contributes
25% of the Partnership's total Capital Contributions and the Participants
contribute 75% of the Partnership's total Capital Contributions, then the
Managing General Partner would receive 32% of the Partnership revenues and the
Participants would receive 68% of the Partnership revenues. On the other hand,
if the Managing General Partner contributes 35% of the Partnership's total
Capital Contributions and the Participants contribute 65% of the Partnership's
total Capital Contributions, then the Managing General Partner would receive 40%
of the Partnership revenues, not 42%, because its revenue share cannot exceed
40% of Partnership revenues, and the Participants would receive 60% of
Partnership revenues.

5.01(b)(4)(a). SUBORDINATION. The Managing General Partner shall subordinate up
to 50% of its share of Partnership Net Production Revenues to the receipt by
Participants of cash distributions from the Partnership equal to $1,000 per Unit
(which is 10% of $10,000 per Unit) regardless of the actual subscription price
they paid for their Units, in each of the Partnership's first five 12-month
periods of operations as set forth below. In this regard:

     (i)   the aggregate 60-month subordination period shall begin with the
           first cash distribution from operations to the Participants;

     (ii)  subsequent subordination distributions, if any, shall be determined
           and made at the time of each subsequent distribution of revenues to
           the Participants; and

     (iii) the Managing General Partner shall not subordinate more than 50% of
           its share of Partnership Net Production Revenues in any 12-month
           subordination period.

The Managing General Partner's subordination obligation shall be determined by:


                                       39

<PAGE>

     (i)  carrying forward to subsequent 12-month subordination periods the
          amount, if any, by which cumulative cash distributions to
          Participants, including any subordination payments, are less than:

          (a)  $1,000 per Unit (10% of $10,000 per Unit) in the first 12-month
               period;

          (b)  $2,000 per Unit (20% of $10,000 per Unit) in the second 12-month
               period;

          (c)  $3,000 per Unit (30% of $10,000 per Unit) in the third 12-month
               period; or

          (d)  $4,000 per Unit (40% of $10,000 per Unit) in the fourth 12-month
               period (no carry forward is required if the Participant's
               cumulative cash distributions are less than $5,000 per Unit (50%
               of $10,000 per Unit) in the fifth 12-month period, because the
               Managing General Partner's subordination obligation terminates on
               the expiration of the fifth 12-month period); and

     (ii) reimbursing the Managing General Partner for any previous
          subordination payments to the extent cumulative cash distributions to
          Participants, including any subordination payments, would exceed:

          (a)  $1,000 per Unit (10% of $10,000 per Unit) in the first 12-month
               period;

          (b)  $2,000 per Unit (20% of $10,000 per Unit) in the second 12-month
               period;

          (c)  $3,000 per Unit (30% of $10,000 per Unit) in the third 12-month
               period;

          (d)  $4,000 per Unit (40% of $10,000 per Unit) in the fourth 12-month
               period; or

          (e)  $5,000 per Unit (50% of $10,000 per Unit) in the fifth 12-month
               period.

The Managing General Partner's subordination obligation also shall be subject to
the following conditions:

     (i)   the subordination obligation may be prorated in the Managing General
           Partner's discretion (e.g. in the case of a monthly distribution, the
           Managing General Partner shall not have any subordination obligation
           if the cumulative monthly distributions to Participants equal $83.33
           per Unit (8.333% of $1,000 per Unit) or more, assuming there are no
           subordination distributions owed for any preceding period);

     (ii)  the Managing General Partner shall not be required to return
           Partnership distributions previously received by it, even though a
           subordination obligation arises after the distributions;

     (iii) subject to the foregoing provisions of this section, only Partnership
           revenues in the current distribution period shall be debited or
           credited to the Managing General Partner as may be necessary to
           provide, to the extent possible, subordination distributions to the
           Participants and reimbursements to the Managing General Partner;

     (iv)  no subordination distributions to the Participants or reimbursements
           to the Managing General Partner shall be made after the expiration of
           the fifth 12-month subordination period; and

     (v)   subordination payments to the Participants shall be subject to any
           lien or priority granted by the Managing General Partner to its
           lenders pursuant to agreements either entered into by the Managing
           General Partner before the subordination obligation arose or entered
           into or renewed by the Managing General Partner after the
           subordination obligation arose.

5.01(b)(5). COMMINGLING OF REVENUES FROM ALL PARTNERSHIP WELLS. The revenues
from all Partnership wells shall be commingled, so regardless of when a
Participant subscribes for Units or is admitted to the Partnership, he will
share in the Partnership's revenues from all of its wells on the same basis as
the other Participants.


                                       40

<PAGE>

5.01(c). ALLOCATIONS.

5.01(c)(1). ALLOCATIONS AMONG PARTICIPANTS. Except as provided otherwise in this
Agreement, costs (other than Intangible Drilling Costs and Tangible Costs) and
revenues charged or credited to the Participants as a group, which includes all
revenue credited to the Participants under Section 5.01(b)(4), shall be
allocated among the Participants, including the Managing General Partner to the
extent of any optional subscription for Units under Section 3.03(b)(1), in the
ratio of their respective Units based on $10,000 per Unit regardless of the
actual subscription price paid by a Participant for his Units.

Intangible Drilling Costs and Tangible Costs charged to the Participants as a
group shall be allocated among the Participants, including the Managing General
Partner to the extent of any optional subscription for Units under Section
3.03(b)(1), in the ratio of the subscription amount designated on their
respective Subscription Agreements rather than the number of their respective
Units.

5.01(c)(2). COSTS AND REVENUES NOT DIRECTLY ALLOCABLE TO A PARTNERSHIP WELL.
Costs and revenues not directly allocable to a particular Partnership Well or
additional operation shall be allocated among the Partnership Wells or
additional operations in any manner the Managing General Partner in its
reasonable discretion, shall select, and shall then be charged or credited in
the same manner as costs or revenues directly applicable to the Partnership Well
or additional operation are being charged or credited.

5.01(c)(3). MANAGING GENERAL PARTNER'S DISCRETION IN MAKING ALLOCATIONS FOR
FEDERAL INCOME TAX PURPOSES. In determining the proper method of allocating
charges or credits among the parties, allocating any item of income, gain, loss,
deduction or credit pursuant to new laws or new IRS or judicial interpretations
of existing law, allocating any other item that is not otherwise specifically
allocated in this Agreement or is subsequently determined by the Managing
General Partner to be clearly inconsistent with a party's economic interest in
the Partnership, or making any other allocations under this Agreement, the
Managing General Partner may adopt any method of allocation that it selects, in
its sole discretion, after consultation with the Partnership's legal counsel or
accountants. Any new allocation provisions shall be made in a manner that is
consistent with the parties' economic interests in the Partnership and will
result in the most favorable aggregate consequences to the Participants that
are, as nearly as possible, consistent with the original allocations described
in this Agreement.

5.02. CAPITAL ACCOUNTS AND ALLOCATIONS THERETO.

5.02(a). CAPITAL ACCOUNTS FOR EACH PARTY TO THIS AGREEMENT. A single, separate
Capital Account shall be established for each party, regardless of the number of
interests owned by the party, the class of the interests and the time or manner
in which the interests were acquired.

5.02(b). CHARGES AND CREDITS.

5.02(b)(1). GENERAL STANDARD. Except as otherwise provided in this Agreement,
the Capital Account of each party shall be determined and maintained in
accordance with Treas. Reg. Section 1.704-l(b)(2)(iv) and shall be increased by:

     (i)   the amount of money contributed by him to the Partnership;

     (ii)  the fair market value of property contributed by him to the
           Partnership, without regard to Section 7701(g) of the Code, net of
           liabilities secured by the contributed property that the Partnership
           is considered to assume or take subject to under Section 752 of the
           Code; and

     (iii) allocations to him of Partnership income and gain, or items thereof,
           including income and gain exempt from tax and income and gain
           described in Treas. Reg. Section 1.704-l(b)(2)(iv)(g), but excluding
           income and gain described in Treas. Reg. Section 1.704-l(b)(4)(i);

and shall be decreased by:

     (iv)  the amount of money distributed to him by the Partnership;


                                       41

<PAGE>

     (v)   the fair market value of property distributed to him by the
           Partnership, without regard to Section 7701(g) of the Code, net of
           liabilities secured by the distributed property that he is considered
           to assume or take subject to under Section 752 of the Code;

     (vi)  allocations to him of Partnership expenditures described in
           Section 705(a)(2)(B) of the Code; and

     (vii) allocations to him of Partnership loss and deduction, or items
           thereof, including loss and deduction described in Treas. Reg.
           Section 1.704-l(b)(2)(iv)(g), but excluding items described in (vi)
           above, and loss or deduction described in Treas. Reg. Section
           1.704-l(b)(4)(i) or (iii).

5.02(b)(2). EXCEPTION. If Treas. Reg. Section 1.704-l(b)(2)(iv) fails to provide
guidance, Capital Account adjustments shall be made in a manner that:

     (i)   maintains equality between the aggregate governing Capital Accounts
           of the parties and the amount of Partnership capital reflected on the
           Partnership's balance sheet, as computed for book purposes;

     (ii)  is consistent with the underlying economic arrangement of the
           parties; and

     (iii) is based, wherever practicable, on federal tax accounting principles.

5.02(c). PAYMENTS TO THE MANAGING GENERAL PARTNER. The Capital Account of the
Managing General Partner shall be reduced by payments to it pursuant to Section
4.04(a)(2) only to the extent of the Managing General Partner's distributive
share of any Partnership deduction, loss, or other downward Capital Account
adjustment resulting from the payments. Also, in the event, and to the extent,
that the Managing General Partner is treated under the Code as having been
transferred an interest in the Partnership in connection with the performance of
services for the Partnership (whether before or after the formation of the
Partnership):

     (i)   any resulting compensation income shall be allocated 100% to the
           Managing General Partner;

     (ii)  any associated increase in Capital Accounts shall be credited 100% to
           the Managing General Partner; and

     (iii) any associated deduction to which the Partnership is entitled shall
           be allocated 100% to the Managing General Partner.

5.02(d). DISCRETION OF MANAGING GENERAL PARTNER IN THE METHOD OF MAINTAINING
CAPITAL ACCOUNTS. Notwithstanding any other provisions of this Agreement, the
method of maintaining Capital Accounts may be changed from time to time, in the
discretion of the Managing General Partner, to take into consideration Section
704 and other provisions of the Code and the related rules, regulations and
interpretations as may exist from time to time.

5.02(e). REVALUATIONS OF PROPERTY. In the discretion of the Managing General
Partner the Capital Accounts of the parties may be increased or decreased to
reflect a revaluation of Partnership property, including intangible assets such
as goodwill, on a property-by-property basis except as otherwise permitted under
Section 704(c) of the Code and the regulations thereunder, on the Partnership's
books, in accordance with Treas. Reg. Section 1.704-l(b)(2)(iv)(f).

5.02(f). AMOUNT OF BOOK ITEMS. In cases where Section 704(c) of the Code or
Section 5.02(e) applies, Capital Accounts shall be adjusted in accordance with
Treas. Reg. Section 1.704-l(b)(2)(iv)(g) for allocations of depreciation,
depletion, amortization and gain and loss, as computed for book purposes, with
respect to the property.

5.03. ALLOCATION OF INCOME, DEDUCTIONS AND CREDITS.

5.03(a). IN GENERAL.

5.03(a)(1). DEDUCTIONS ARE ALLOCATED TO PARTY CHARGED WITH EXPENDITURE. To the
extent permitted by law and except as otherwise provided in this Agreement, all
deductions and credits, including, but not limited to, intangible drilling and
development costs and depreciation, shall be allocated to the party who has been
charged with the expenditure giving rise to


                                       42

<PAGE>

the deductions and credits; and to the extent permitted by law, these parties
shall be entitled to the deductions and credits in computing taxable income or
tax liabilities to the exclusion of any other party. Also, any Partnership
deductions that would be nonrecourse deductions if they were not attributable to
a loan made or guaranteed by the Managing General Partner or its Affiliates
shall be allocated to the Managing General Partner to the extent required by
law.

5.03(a)(2). INCOME AND GAIN ALLOCATED IN ACCORDANCE WITH REVENUES. Except as
otherwise provided in this Agreement, all items of income and gain, including
gain on disposition of assets, shall be allocated in accordance with the related
revenue allocations set forth in Section 5.01(b) and its subsections.

5.03(b). TAX BASIS OF EACH PROPERTY. Subject to Section 704(c) of the Code, the
tax basis of each oil and gas property for computation of cost depletion and
gain or loss on disposition shall be allocated and reallocated when necessary
based on the capital interest in the Partnership as to the property and the
capital interest in the Partnership for this purpose as to each property shall
be considered to be owned by the parties in the ratio in which the expenditure
giving rise to the tax basis of the property has been charged as of the end of
the year.

5.03(c). GAIN OR LOSS ON OIL AND GAS PROPERTIES. Each party shall separately
compute its gain or loss on the disposition of each natural gas and oil property
in accordance with the provisions of Section 613A(c)(7)(D) of the Code, and the
calculation of the gain or loss shall consider the party's adjusted basis in his
property interest computed as provided in Section 5.03(b) and the party's
allocable share of the amount realized from the disposition of the property.

5.03(d). GAIN ON DEPRECIABLE PROPERTY. Gain from each sale or other disposition
of depreciable property shall be allocated to each party whose share of the
proceeds from the sale or other disposition exceeds its contribution to the
adjusted basis of the property in the ratio that the excess bears to the sum of
the excesses of all parties having an excess.

5.03(e). LOSS ON DEPRECIABLE PROPERTY. Loss from each sale, abandonment or other
disposition of depreciable property shall be allocated to each party whose
contribution to the adjusted basis of the property exceeds its share of the
proceeds from the sale, abandonment or other disposition in the proportion that
the excess bears to the sum of the excesses of all parties having an excess.

5.03(f). ALLOCATION IF RECAPTURE TREATED AS ORDINARY INCOME. Any recapture
treated as an increase in ordinary income by reason of Sections 1245, 1250 or
1254 of the Code shall be allocated to the parties in the amounts in which the
recaptured items were previously allocated to them; provided that to the extent
recapture allocated to any party is in excess of the party's gain from the
disposition of the property, the excess shall be allocated to the other parties
but only to the extent of the other parties' gain from the disposition of the
property.

5.03(g). TAX CREDITS. If a Partnership expenditure, whether or not deductible,
that gives rise to a tax credit in a Partnership taxable year also gives rise to
valid allocations of Partnership loss or deduction, or other downward Capital
Account adjustments, for the year, then the parties' interests in the
Partnership with respect to the credit, or the cost giving rise thereto, shall
be in the same proportion as the parties' respective distributive shares of the
loss or deduction, and adjustments. If Partnership receipts, whether or not
taxable, that give rise to a tax credit, including a marginal well production
credit under Section 45I of the Code, in a Partnership taxable year also give
rise to valid allocations of Partnership income or gain, or other upward Capital
Account adjustments, for the year, then the parties' interests in the
Partnership with respect to the credit, or the Partnership's receipts or
production of natural gas and oil production giving rise thereto, shall be in
the same proportion as the parties' respective shares of the Partnership's
production revenues from the sales of its natural gas and oil production as
provided in Section 5.01(b)(4).

5.03(h). DEFICIT CAPITAL ACCOUNTS AND QUALIFIED INCOME OFFSET. Notwithstanding
any provision of this Agreement to the contrary, an allocation of loss or
deduction which would result in a party having a deficit Capital Account balance
as of the end of the taxable year to which the allocation relates, if charged to
the party, to the extent the Participant is not required to restore the deficit
to the Partnership, taking into account:

     (i)   adjustments that, as of the end of the year, reasonably are expected
           to be made to the party's Capital Account for depletion allowances
           with respect to the Partnership's natural gas and oil properties;


                                       43

<PAGE>

     (ii)  allocations of loss and deduction that, as of the end of the year,
           reasonably are expected to be made to the party under Sections
           704(e)(2) and 706(d) of the Code and Treas. Reg. Section
           1.751-1(b)(2)(ii); and

     (iii) distributions that, as of the end of the year, reasonably are
           expected to be made to the party to the extent they exceed offsetting
           increases to the party's Capital Account, assuming for this purpose
           that the fair market value of Partnership property equals its
           adjusted tax basis, that reasonably are expected to occur during or
           prior to the Partnership taxable years in which the distributions
           reasonably are expected to be made;

shall be charged to the Managing General Partner. Further, the Managing General
Partner shall be credited with an additional amount of Partnership income or
gain equal to the amount of the loss or deduction as quickly as possible to the
extent that the chargeback does not cause or increase deficit balances in the
parties' Capital Accounts which are not required to be restored to the
Partnership.

Notwithstanding any provision of this Agreement to the contrary, if a party
unexpectedly receives an adjustment, allocation, or distribution described in
(i), (ii), or (iii) above, or any other distribution, which causes or increases
a deficit balance in the party's Capital Account which is not required to be
restored to the Partnership, the party shall be allocated items of income and
gain, consisting of a pro rata portion of each item of Partnership income,
including gross income and gain for the year, in an amount and manner sufficient
to eliminate the deficit balance as quickly as possible.

5.03(i). MINIMUM GAIN CHARGEBACK. To the extent there is a net decrease during a
Partnership taxable year in the minimum gain attributable to a Partner
nonrecourse debt, then any Partner with a share of the minimum gain attributable
to the debt at the beginning of the year shall be allocated items of Partnership
income and gain in accordance with Treas. Reg. Section 1.704-2(i).

5.03(j). PARTNERS' ALLOCABLE SHARES. Except as otherwise provided in this
Agreement, each party's allocable share of Partnership income, gain, loss,
deductions and credits shall be determined by using any method prescribed or
permitted by the Secretary of the Treasury by regulations or other guidelines
and selected by the Managing General Partner which takes into account the
varying interests of the parties in the Partnership during the taxable year. In
the absence of those regulations or guidelines, except as otherwise provided in
this Agreement, the allocable share shall be based on actual income, gain, loss,
deductions and credits economically accrued each day during the taxable year in
proportion to each party's varying interest in the Partnership on each day
during the taxable year.

5.03(k). CONTINGENT INCOME. Subject to Section 5.04(d), if it is determined that
any taxable income results to any party by reason of its entitlement to a share
of capital of the Partnership, or a share of profits or revenues of the
Partnership before the profit or revenue has been realized by the Partnership,
the resulting deduction, as well as any resulting gain, shall not enter into
Partnership net income or loss, but shall be separately allocated to that party.

5.04. ELECTIONS.

5.04(a). ELECTION TO DEDUCT INTANGIBLE COSTS. The Partnership's federal income
tax return shall be made in accordance with an election under the option granted
by the Code to deduct intangible drilling and development costs.

5.04(b). NO ELECTION OUT OF SUBCHAPTER K. No election shall be made by the
Partnership, any Partner, or the Operator for the Partnership to be excluded
from the application of the partnership provisions of the Code, including
Subchapter K of Chapter 1 of Subtitle A of the Code.

5.04(c). Section 754 ELECTION. In the event of the transfer of an interest in
the Partnership, or on the death of an individual party hereto, or in the event
of the distribution of property to any party, the Managing General Partner may
choose for the Partnership to file an election in accordance with the applicable
Treasury Regulations to cause the basis of the Partnership's assets to be
adjusted for federal income tax purposes as provided by Sections 734 and 743 of
the Code.

5.04(d). Section 83 ELECTION. The Partnership, the Managing General Partner and
each Participant hereby agree to be legally bound by the provisions of this
Section 5.04(d) and further agree that, in the Managing General Partner's sole
discretion, the Partnership


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<PAGE>

and all of its Partners may elect a safe harbor under which the fair market
value of a Partnership interest that is transferred in connection with the
performance of services is treated as being equal to the liquidation value of
that interest for transfers on or after the date final regulations providing the
safe harbor are published in the Federal Register. If the Managing General
Partner determines that the Partnership and all of its Partners will elect the
safe harbor, which determination may be made solely in the best interests of the
Managing General Partner, the Partnership, the Managing General Partner and each
Participant further agree that:

     (i)   the Partnership shall be authorized and directed to elect the safe
           harbor;

     (ii)  the Partnership and each of its Partners (including any Person to
           whom a Partnership interest is transferred in connection with the
           performance of services) shall comply with all requirements of the
           safe harbor with respect to all Partnership interests transferred in
           connection with the performance of services while the election
           remains effective; and

     (iii) the Managing General Partner, in its sole discretion, may cause the
           Partnership to terminate the safe harbor election, which
           determination may be made in the sole interests of the Managing
           General Partner.

5.05. DISTRIBUTIONS.

5.05(a). IN GENERAL.

5.05(a)(1). MONTHLY REVIEW OF ACCOUNTS. The Managing General Partner shall
review the accounts of the Partnership at least monthly to determine whether
cash distributions are appropriate and the amount to be distributed, if any.

5.05(a)(2). DISTRIBUTIONS. The Partnership shall distribute funds to the
Managing General Partner and the Participants allocated to their respective
accounts that the Managing General Partner deems unnecessary for the Partnership
to retain.

5.05(a)(3). NO BORROWINGS. In no event shall funds be advanced or borrowed by
the Partnership for distributions to the Managing General Partner and the
Participants if the amount of the distributions would exceed the Partnership's
accrued and received revenues for the previous four quarters, less paid and
accrued Operating Costs with respect to the revenues. The determination of
revenues and costs shall be made in accordance with generally accepted
accounting principles, consistently applied.

5.05(a)(4). DISTRIBUTIONS TO THE MANAGING GENERAL PARTNER. Cash distributions
from the Partnership to the Managing General Partner shall only be made as
follows:

     (i)  in conjunction with distributions to Participants; and

     (ii) out of funds properly allocated to the Managing General Partner's
          account.

5.05(a)(5). RESERVE. At any time after one year from the date each Partnership
Well is placed into production, the Managing General Partner shall have the
right to deduct each month from the Partnership's net sales proceeds from the
sale of the natural gas and oil production from each of its productive wells up
to $200 per well for the purpose of establishing a fund to cover the estimated
costs of plugging and abandoning the well. All of these funds shall be deposited
in a separate interest bearing account for the benefit of the Partnership, and
the total amount so retained and deposited shall not exceed the Managing General
Partner's reasonable estimate of the costs to plug and abandon the well.

5.05(b). DISTRIBUTION OF UNCOMMITTED SUBSCRIPTION PROCEEDS. Any subscription
proceeds not expended or committed for expenditure, as evidenced by a written
agreement, by the Partnership within 12 months of the Offering Termination Date,
except necessary operating capital, shall be distributed to the Participants in
the ratio that the subscription amount designated on each Participant's
Subscription Agreement bears to the total subscription amounts designated on all
of the Participants' Subscription Agreements, as a return of capital. The
Managing General Partner shall reimburse the Participants for the selling or
other offering expenses, if any, allocable to the return of capital.


                                       45

<PAGE>

For purposes of this subsection, "committed for expenditure" shall mean
contracted for, actually earmarked for or allocated by the Managing General
Partner to the Partnership's drilling operations, and "necessary operating
capital" shall mean those funds which, in the opinion of the Managing General
Partner, should remain on hand to assure continuing operation of the
Partnership.

5.05(c). DISTRIBUTIONS ON WINDING UP. On the winding up of the Partnership
distributions shall be made as provided in Section 7.02.

5.05(d). INTEREST AND RETURN OF CAPITAL. No party shall under any circumstances
be entitled to any interest on amounts retained by the Partnership. Each
Participant shall look only to his share of distributions, if any, from the
Partnership for a return of his Capital Contribution.

                                   ARTICLE VI
                                TRANSFER OF UNITS

6.01. TRANSFERABILITY OF UNITS. A Participant's transfer of a portion or all his
Units, or any interest in his Units, is subject to all of the provisions of this
Article VI. For purposes of this Article VI, the term "transfer" shall include
any sale, exchange, gift, assignment, pledge, mortgage, hypothecation,
redemption or other form of transfer of a Unit, or any interest in a Unit, by a
Participant (which may include the Managing General Partner or its Affiliates,
if they purchase Units) or by operation of law, including any transfers of Units
which a Participant presents to the Managing General Partner for purchase under
Section 6.03.

6.01(a). RIGHTS OF ASSIGNEE. Unless a transferee of a Participant's Unit becomes
a substitute Participant with respect to that Unit in accordance with the
provisions of Section 6.02(a)(3)(a), he shall not be entitled to any of the
rights granted to a Participant under this Agreement, other than the right to
receive all or part of the share of the profits, losses, income, gains,
deductions, credits and depletion allowances, or items thereof, and cash
distributions or returns of capital to which his transferor would otherwise be
entitled under this Agreement.

6.01(b). CONVERSION OF INVESTOR GENERAL PARTNER UNITS TO LIMITED PARTNER UNITS.

6.01(b)(1). AUTOMATIC CONVERSION. After all of the Partnership Wells have been
drilled and completed, as determined by the Managing General Partner, the
Managing General Partner shall file an amended certificate of limited
partnership with the Secretary of State of the State of Delaware for the purpose
of converting the Investor General Partner Units to Limited Partner Units.

6.01(b)(2). INVESTOR GENERAL PARTNERS SHALL HAVE CONTINGENT LIABILITY. On
conversion the Investor General Partners shall be Limited Partners entitled to
limited liability; however, they shall remain liable to the Partnership for any
additional Capital Contribution required for their proportionate share of any
Partnership obligation or liability arising before the conversion of their Units
as provided in Section 3.05(b)(2).

6.01(b)(3). CONVERSION SHALL NOT AFFECT ALLOCATIONS. The conversion shall not
affect the allocation to any Participant of any item of Partnership income,
gain, loss, deduction or credit or other item of special tax significance other
than Partnership liabilities, if any. Further, the conversion shall not affect
any Participant's interest in the Partnership's natural gas and oil properties
and unrealized receivables.

6.01(b)(4). RIGHT TO CONVERT IF REDUCTION OF INSURANCE. Notwithstanding the
foregoing, the Managing General Partner shall notify all Participants at least
30 days before the effective date of any material adverse change in the
Partnership's insurance coverage. If the insurance coverage is to be materially
reduced, then the Investor General Partners shall have the right to convert
their Units into Limited Partner Units before the reduction by giving written
notice to the Managing General Partner.

6.02. SPECIAL RESTRICTIONS ON TRANSFERS OF UNITS BY PARTICIPANTS.

6.02(a). IN GENERAL. Transfers of Units by Participants are subject to the
following general conditions:


                                       46

<PAGE>

     (i)   except as provided by operation of law:

           (a) only whole Units may be transferred unless the Participant owns
               less than a whole Unit, in which case his entire fractional
               interest must be transferred; and

           (b) Units may not be transferred to a person who is under the age of
               18 or incompetent (unless an attorney-in-fact, guardian,
               custodian or conservator has been appointed to handle the affairs
               of that person) without the Managing General Partner's consent;

     (ii)  the costs and expenses associated with the transfer must be paid by
           the assignor Participant;

     (iii) the transfer documents must be in a form satisfactory to the Managing
           General Partner; and

     (iv)  the terms of the transfer must not contravene those of this
           Agreement.

Transfers of Units by Participants are subject to the following additional
restrictions set forth in Sections 6.02(a)(1) and 6.02(a)(2).

6.02(a)(1). TAX LAW RESTRICTIONS. Subject to transfers permitted by Section 6.03
and transfers by operation of law, no transfer of a Unit by a Participant shall
be made which, in the opinion of counsel to the Partnership, would result in the
Partnership being either:

     (i)  terminated for tax purposes under Section 708 of the Code; or

     (ii) treated as a "publicly-traded" partnership for purposes of Section
          469(k) of the Code.

6.02(a)(2). SECURITIES LAWS RESTRICTION. Subject to transfers permitted by
Section 6.03 and transfers by operation of law, no Unit shall be transferred by
a Participant unless there is either:

     (i)  an effective registration of the Unit under the Securities Act of
          1933, as amended, and qualification under applicable state securities
          laws; or

     (ii) an opinion of counsel acceptable to the Managing General Partner that
          the registration and qualification of the Unit is not required, unless
          this requirement is waived by the Managing General Partner.

Transfers of Units by Participants are also subject to any conditions contained
in the Subscription Agreement and Exhibit (B) to the Prospectus.

6.02(a)(3). SUBSTITUTE PARTICIPANT.

6.02(a)(3)(a). PROCEDURE TO BECOME SUBSTITUTE PARTICIPANT. Subject to Sections
6.02(a)(1) and 6.02(a)(2), a transferee of a Participant's Unit shall become a
substitute Participant entitled to all the rights of a Participant if, and only
if:

     (i)   the transferor gives the transferee the right;

     (ii)  the transferee pays to the Partnership all costs and expenses
           incurred by the Partnership in connection with the substitution; and

     (iii) the transferee executes and delivers the instruments necessary to
           establish that a legal transfer has taken place and to confirm the
           agreement of the transferee to be bound by all of the terms of this
           Agreement, in a form acceptable to the Managing General Partner.

6.02(a)(3)(b). RIGHTS OF SUBSTITUTE PARTICIPANT. A substitute Participant shall
be entitled to all of the rights attributable to full ownership of the assigned
Units including the right to vote.


                                       47

<PAGE>

6.02(b). EFFECT OF TRANSFER.

6.02(b)(1). AMENDMENT OF RECORDS. The Partnership shall amend its records at
least once each calendar quarter to effect the substitution of substitute
Participants.

Any transfer of a Unit by a Participant which is permitted under this Article
VI, when the transferee does not become a substitute Participant, shall be
effective as follows:

     (i)  midnight of the last day of the calendar month in which it is made; or

     (ii) at the Managing General Partner's election, 7:00 A.M. of the following
          day.

6.02(b)(2). A TRANSFER OF UNITS DOES NOT RELIEVE THE TRANSFEROR OF CERTAIN
COSTS. No transfer of a Unit by a Participant, including a transfer of less than
all of a Participant's Units or the transfer of a Participant's Units to more
than one party, shall relieve the transferor of its responsibility for its
proportionate part of any expenses, obligations and liabilities under this
Agreement related to the Units so transferred, whether arising before or after
the transfer.

6.02(b)(3). A TRANSFER OF UNITS DOES NOT REQUIRE A PARTNERSHIP ACCOUNTING. No
transfer of a Unit by a Participant shall require an accounting of the
Partnership. Also, no transfer of a Unit shall grant rights under this
Agreement, including the exercise of any elections, as between the transferring
Participant and the Partnership, the Managing General Partner and the remaining
Participants to more than one Person unanimously designated by the transferee(s)
of the Unit, and, if he has retained an interest in the transferred Unit, the
transferor of the Unit.

6.02(b)(4). REQUIRED NOTICE TO MANAGING GENERAL PARTNER OF TRANSFER OF UNITS.
Until the Managing General Partner receives from the transferring Participant a
written notice in a form acceptable to the Managing General Partner that
designates the transferee(s) of a Unit, the Managing General Partner shall
continue to account only to the Person to whom it was furnishing notices
pursuant to Section 8.01 and its subsections before the purported transfer of
the Unit. This party shall continue to exercise all rights under this Agreement
applicable to the Units owned by the purported transferor of the Unit.

6.03. PRESENTMENT.

6.03(a). IN GENERAL. Participants shall have the right to present their Units to
the Managing General Partner for purchase subject to the conditions and
limitations set forth in this Section 6.03. A Participant, however, is not
obligated to present his Units for purchase.

The Managing General Partner shall not be obligated to purchase more than 5% of
the total outstanding Units in any calendar year and this 5% limit may not be
waived. The Managing General Partner shall not purchase less than one Unit
unless the lesser amount represents the Participant's entire interest in the
Partnership, however, the Managing General Partner may waive this limitation.

A Participant may present his Units in writing to the Managing General Partner
every year beginning with the fifth calendar year after the Offering Termination
Date subject to the following conditions:

     (i)   the presentment request must be made by the Participant within 120
           days of the reserve report described in Section 4.03(b)(3);

     (ii)  in accordance with Treas. Reg. Section 1.7704-1(f), the purchase may
           not be made until at least 60 calendar days after the Participant
           notifies the Partnership in writing of the Participant's intention to
           exercise the presentment right; and

     (iii) the purchase shall not be considered effective until the presentment
           price has been paid to the Participant in cash to the Participant.

6.03(b). REQUIREMENT FOR INDEPENDENT PETROLEUM CONSULTANT. The amount of the
presentment price attributable to Partnership reserves shall be determined based
on the last reserve report of the Partnership prepared by the Managing General


                                       48

<PAGE>

Partner and reviewed by an Independent Expert. The Managing General Partner
shall estimate the present worth of future net revenues attributable to the
Partnership's interest in the Proved Reserves as described in Section
4.03(b)(3)(ii). The calculation of the presentment price shall be made as set
forth in Section 6.03(c).

6.03(c). CALCULATION OF PRESENTMENT PRICE. The presentment price shall be based
on the Partnership's net assets and liabilities and shall be allocated pro rata
to each Participant in the ratio that his number of Units bears to the total
number of Units. Subject to the foregoing, the presentment price shall include
the sum of the following Partnership items:

     (i)   an amount based on 70% of the present worth of future net revenues
           from the Proved Reserves determined as described in Section 6.03(b);

     (ii)  cash on hand;

     (iii) prepaid expenses and accounts receivable less a reasonable amount for
           doubtful accounts; and

     (iv)  the estimated market value of all assets that are not separately
           specified above, determined in accordance with standard industry
           valuation procedures.

There shall be deducted from the foregoing sum the following Partnership items:

     (i)  an amount equal to all debts, obligations, and other liabilities,
          including accrued expenses; and

     (ii) any distributions made to the Participants between the date of the
          presentment request and the date the presentment price is paid to the
          selling Participant. However, if any amount of those cash
          distributions to the Participant by the Partnership was derived from
          the sale of natural gas, oil or other mineral production, or of a
          producing property owned by the Partnership, after the date of the
          presentment request, for purposes of determining the reduction of the
          presentment price the amount of those cash distributions shall be
          discounted using the same rate used to take into account the risk
          factors employed to determine the present worth of the Partnership's
          Proved Reserves.

6.03(d). FURTHER ADJUSTMENT MAY BE ALLOWED. The presentment price may be further
adjusted by the Managing General Partner for estimated changes therein from the
date of the report to the date of payment of the presentment price to the
Selling Participant because of the following:

     (i)  the production or sales of, or additions to, reserves and lease and
          well equipment, sale or abandonment of Leases, and similar matters
          occurring before the date of the presentment request; and

     (ii) any of the following occurring before payment of the presentment price
          to the selling Participant:

          (a)  changes in well performance;

          (b)  increases or decreases in the market price of natural gas, oil or
               other minerals;

          (c)  revisions to regulations relating to the importing of
               hydrocarbons;

          (d)  changes in income, ad valorem, and other tax laws, such as
               material variations in the provisions for depletion; and

          (e)  similar matters.

6.03(e). SELECTION BY LOT. If less than all of the Units presented at any time
are to be purchased, then the Participants whose Units are to be purchased will
be selected by lot.

The Managing General Partner's obligation to purchase Units presented may be
discharged for its benefit by a third-party or an Affiliate. The Units of the
selling Participant shall be transferred to the party who pays for it. A selling
Participant shall


                                       49

<PAGE>

be required to deliver an executed assignment of his Units, in a form
satisfactory to the Managing General Partner, together with any other
documentation as the Managing General Partner may reasonably request.

6.03(f). NO OBLIGATION OF THE MANAGING GENERAL PARTNER TO ESTABLISH A RESERVE.
The Managing General Partner shall have no obligation to establish any reserve
to satisfy the presentment feature under this section.

6.03(g). SUSPENSION OF PRESENTMENT FEATURE. The Managing General Partner may
suspend this presentment feature by so notifying Participants at any time if it
determines in its sole discretion that it:

     (i)  does not have sufficient cash flow; or

     (ii) is unable to borrow funds for this purpose on terms it deems
          reasonable.

In addition, the presentment feature may be conditioned, in the Managing General
Partner's sole discretion, on the Managing General Partner's receipt of an
opinion of counsel that the transfers will not cause the Partnership to be
treated as a "publicly traded partnership" under the Code.

The Managing General Partner shall hold the purchased Units for its own account
and not for resale.

6.04. REDEMPTION OF UNITS FROM NON-CITIZEN ASSIGNEES. If the Partnership, the
Managing General Partner or any of its Affiliates become subject to federal,
state or local laws or regulations that, in the reasonable determination of the
Managing General Partner, create a substantial risk of cancellation or
forfeiture of any property that they have an interest in because of the
nationality, citizenship or other related status of any Participant or assignee
of a Participant's Units, the Partnership may redeem, on 30 days' advance notice
to the Participant, the Participant's Units or the Units held by the assignee of
a Participant, at a reasonable redemption price per Unit as determined by the
Managing General Partner in its sole discretion.

                                   ARTICLE VII
                      DURATION, DISSOLUTION, AND WINDING UP

7.01. DURATION.

7.01(a). FIFTY YEAR TERM. The Partnership shall continue in existence for a term
of 50 years from the effective date of this Agreement unless sooner terminated
as set forth below.

7.01(b). TERMINATION. The Partnership shall terminate following the occurrence
of:

     (i)  a Final Terminating Event; or

     (ii) any event that causes the dissolution of a limited partnership under
          the Delaware Revised Uniform Limited Partnership Act.

7.01(c). CONTINUANCE OF PARTNERSHIP EXCEPT ON FINAL TERMINATING EVENT. Other
than the occurrence of a Final Terminating Event, the Partnership or any
successor limited partnership shall not be wound up, but shall be continued by
the parties and their respective successors as a successor limited partnership
under all of the terms of this Agreement. The successor limited partnership
shall succeed to all of the assets of the Partnership. As used throughout this
Agreement, the term "Partnership" shall include the successor limited
partnership and the parties to the successor limited partnership.

7.02. DISSOLUTION AND WINDING UP.

7.02(a). FINAL TERMINATING EVENT. On the occurrence of a Final Terminating Event
the affairs of the Partnership shall be wound up and there shall be distributed
to each of the parties its Distribution Interest in the remaining Partnership
assets.

7.02(b). TIME OF LIQUIDATING DISTRIBUTION. To the extent practicable and in
accordance with sound business practices in the judgment of the Managing General
Partner, liquidating distributions shall be made by:


                                       50

<PAGE>

     (i)  the end of the taxable year in which liquidation occurs, determined
          without regard to Section 706(c)(2)(A) of the Code; or

     (ii) if later, within 90 days after the date of the liquidation.

Notwithstanding, the following amounts are not required to be distributed within
the foregoing time periods so long as the withheld amounts are distributed as
soon as practical:

     (i)  amounts withheld for reserves reasonably required for liabilities of
          the Partnership; and

     (ii) installment obligations owed to the Partnership.

7.02(c). IN-KIND DISTRIBUTIONS. The Managing General Partner shall not be
obligated to offer in-kind property distributions to the Participants, but may
do so, in its discretion. Any in-kind property distributions to the Participants
shall be made to a liquidating trust or similar entity for the benefit of the
Participants, unless at the time of the distribution:

     (i)  the Managing General Partner offers the individual Participants the
          election of receiving in-kind property distributions and the
          Participants accept the offer after being advised of the risks
          associated with direct ownership; or

     (ii) there are alternative arrangements in place which assure the
          Participants that they will not, at any time, be responsible for the
          operation or disposition of Partnership properties.

If the Managing General Partner has not received a Participant's consent within
30 days after the Managing General Partner mailed the request for consent, then
it shall be presumed that the Participant has refused to give his consent.

7.02(d). SALE IF NO CONSENT. Any Partnership asset which would otherwise be
distributed in-kind to a Participant, except for the failure or refusal of the
Participant to give his written consent to the distribution, may instead be sold
by the Managing General Partner at the best price reasonably obtainable from an
independent third-party, who is not an Affiliate of the Managing General
Partner, or to the Managing General Partner itself or its Affiliates, including
an Affiliated Income Program, at fair market value as determined by an
Independent Expert selected by the Managing General Partner.

                                  ARTICLE VIII
                            MISCELLANEOUS PROVISIONS

8.01. NOTICES.

8.01(a). METHOD. Any notice required under this Agreement shall be:

     (i)  in writing; and

     (ii) given by mail or delivered by an overnight delivery company (although
          one-day delivery is not required) addressed to the party to receive
          the notice at the address designated in Section 1.03.

If there is a transfer of Units under this Agreement, no notice to the
transferee shall be required, nor shall the transferee have any rights under
this Agreement, until notice of the transfer has been given to the Managing
General Partner.

Any transfer of Units under this Agreement shall not increase the Managing
General Partner's or the Partnership's duty to give notice. If there is a
transfer of Units under this Agreement to more than one party, then notice to
any owner of any interest in the Units shall be notice to all of the owners of
the Units.

8.01(b). CHANGE IN ADDRESS. The address of any party to this Agreement may be
changed by notice as follows:

     (i)  to the Participants, if there is a change of address by the Managing
          General Partner; or


                                       51

<PAGE>

     (ii) to the Managing General Partner, if there is a change of address by a
          Participant.

8.01(c). TIME NOTICE DEEMED GIVEN. If the notice is given by the Managing
General Partner, then the notice shall be considered given, and any applicable
time shall run, from the date the notice is placed in the mail or delivered to
the overnight delivery company.

If the notice is given by any Participant, then the notice shall be considered
given and any applicable time shall run from the date the notice is received.

8.01(d). EFFECTIVENESS OF NOTICE. Any notice to a party other than the Managing
General Partner, including a notice requiring concurrence or nonconcurrence,
shall be effective, and any failure to respond binding, irrespective of the
following:

     (i)  whether or not the notice is actually received; or

     (ii) any disability or death on the part of the noticee, even if the
          disability or death is known to the party giving the notice.

8.01(e). FAILURE TO RESPOND. Except pursuant to Section 7.02(c) or when this
Agreement expressly requires affirmative approval of a Participant, any
Participant who fails to respond in writing within the time specified to a
request by the Managing General Partner as set forth below, for approval of, or
concurrence in, a proposed action shall be conclusively deemed to have approved
the action. Except pursuant to Section 7.02(c), when this Agreement expressly
requires affirmative approval of a Participant, the Managing General Partner
shall send a first request and the time period for the Participant's written
response shall not be less than 15 business days from the date of mailing of the
request. If the Participant does not respond in writing to the first request,
then the Managing General Partner shall send a second request. If the
Participant does not respond in writing to the second request within seven
calendar days from the date of mailing the second request, then the Participant
shall be conclusively deemed to have approved the action.

8.02. TIME. Time is of the essence of each part of this Agreement.

8.03. APPLICABLE LAW. The terms and provisions of this Agreement shall be
construed under the laws of the State of Delaware, other than its conflict of
law provisions, however, this section shall not be deemed to limit causes of
action for alleged violations of federal or state securities law to the laws of
the State of Delaware. Neither this Agreement nor the Subscription Agreement
shall require mandatory venue or mandatory arbitration of any or all claims by
Participants against the Sponsor.

8.04. AGREEMENT IN COUNTERPARTS. This Agreement may be executed in counterpart
and shall be binding on all of the parties executing this or similar agreements
from and after the date of execution by each party.

8.05. AMENDMENT.

8.05(a). PROCEDURE FOR AMENDMENT. No changes in this Agreement shall be binding
unless:

     (i)  proposed in writing by the Managing General Partner, and adopted with
          the consent of Participants whose Units equal a majority of the total
          Units; or

     (ii) proposed in writing by Participants whose Units equal 10% or more of
          the total Units and approved by an affirmative vote of Participants
          whose Units equal a majority of the total Units.

8.05(b). CIRCUMSTANCES UNDER WHICH THE MANAGING GENERAL PARTNER ALONE MAY AMEND.
The Managing General Partner is authorized to amend this Agreement and its
exhibits without the consent of Participants in any way deemed necessary or
desirable by it to do any or all of the following:

     (i)   add, or substitute in the case of an assigning party, additional
           Participants;


                                       52

<PAGE>

     (ii)  enhance the tax benefits of the Partnership to the parties and amend
           the allocation provisions of this Agreement as provided in
           Section 5.01(c)(3);

     (iii) satisfy any requirements, conditions, guidelines, options, or
           elections contained in any opinion, directive, order, ruling, or
           regulation of the SEC, the IRS, or any other federal or state agency,
           or in any federal or state statute, compliance with which it deems to
           be in the best interest of the Partnership; or

     (iv)  cure any ambiguity, correct or supplement any provision of this
           Agreement that may be inconsistent with any other provision of this
           Agreement, or add any provision to this Agreement with respect to
           matters, events or issues arising under this Agreement that is not
           inconsistent with the other provisions of this Agreement.

Notwithstanding the foregoing, no amendment materially and adversely affecting
the interests or rights of Participants shall be made without the consent of the
Participants whose interests or rights will be so affected.

8.06. ADDITIONAL PARTNERS. Each Participant consents to the admission to the
Partnership of additional Participants as the Managing General Partner, in its
discretion, chooses to admit.

8.07. LEGAL EFFECT. This Agreement shall be binding on and inure to the benefit
of the parties, their heirs, devisees, personal representatives, successors and
assigns, and shall run with the interests subject to this Agreement. The terms
"Partnership," "Limited Partner," "Investor General Partner," "Participant,"
"Partner," "Managing General Partner," "Operator," or "parties" shall equally
apply to any successor limited partnership, and any heir, devisee, personal
representative, successor or assign of a party.

IN WITNESS WHEREOF, the parties hereto set their hands as of the ________ day of
___________________, 2007.

ATLAS:                                  ATLAS RESOURCES, LLC
                                        Managing General Partner


                                        By:
                                            ------------------------------------


                                       53

<PAGE>

                                  EXHIBIT (I-A)

                                     FORM OF
                     MANAGING GENERAL PARTNER SIGNATURE PAGE

<PAGE>

                                  EXHIBIT (I-A)
                     MANAGING GENERAL PARTNER SIGNATURE PAGE

Attached to and made a part of the AMENDED AND RESTATED CERTIFICATE AND
AGREEMENT OF LIMITED PARTNERSHIP of ATLAS AMERICA PUBLIC #16-2007(A) L.P.

The undersigned agrees:

     1.   to serve as the Managing General Partner of ATLAS AMERICA PUBLIC
          #16-2007(A) L.P. (the "Partnership"), and hereby executes, swears to,
          and agrees to all the terms of the Partnership Agreement;

     2.   to pay the required subscription of the Managing General Partner under
          Section 3.04(a) of the Partnership Agreement; and

     3.   to subscribe to the Partnership as follows:

          (a)  $___________________ [________] Unit(s)] under Section 3.03(b)(1)
               of the Partnership Agreement as a Limited Partner; or

          (b)  $___________________ [________] Unit(s)] under Section 3.03(b)(1)
               of the Partnership Agreement as an Investor General Partner.

MANAGING GENERAL PARTNER:

Atlas Resources, LLC                    Address:


By:
    ---------------------------------   311 Rouser Road
                                        Moon Township, Pennsylvania 15108

ACCEPTED this ________ day of __________________,  2007.

                                        ATLAS RESOURCES, LLC
                                        MANAGING GENERAL PARTNER


                                        By:
                                            ------------------------------------

<PAGE>

                                  EXHIBIT (I-B)

                                     FORM OF
                             SUBSCRIPTION AGREEMENT

<PAGE>

<TABLE>
<S>                                    <C>                                               <C>
                                   ATLAS AMERICA PUBLIC #16-2007(A) L.P.

----------------------------------------------------------------------------------------------------------
                                          SUBSCRIPTION AGREEMENT
----------------------------------------------------------------------------------------------------------

I, the undersigned, hereby offer to purchase Units of Atlas America Public #16-2007(A) L.P. in the amount
set forth on the Signature Page of this Subscription Agreement and on the terms described in the current
Prospectus for Atlas America Public #16-2007 Program, as supplemented or amended from time to time. I
acknowledge and agree that my execution of this Subscription Agreement also constitutes my execution of
the Agreement of Limited Partnership (the "Partnership Agreement") the form of which is attached as
Exhibit (A) to the Prospectus and I agree to be bound by all of the terms and conditions of the
Partnership Agreement if my subscription is accepted by Atlas Resources, LLC, the Managing General
Partner. I understand and agree that I may not assign this offer, nor may it be withdrawn after it has
been accepted by the Managing General Partner. I hereby irrevocably constitute and appoint the Managing
General Partner, and its duly authorized agents, my agent and attorney-in-fact, in my name, place and
stead, to make, execute, acknowledge, swear to, file, record and deliver the Agreement of Limited
Partnership and any certificates related thereto. I further understand that following the Signature Page
there are certain representations, warranties and covenants which I must make before the Managing General
Partner will accept my subscription.

----------------------------------------------------------------------------------------------------------
                                 SIGNATURE PAGE OF SUBSCRIPTION AGREEMENT
----------------------------------------------------------------------------------------------------------

I, the undersigned, agree to purchase _____________ Units at $10,000 per Unit in ATLAS AMERICA PUBLIC
#16-2007(A) L.P. (the "Partnership") as (check one):

                                                              SUBSCRIPTION AMOUNT

     [_] INVESTOR GENERAL PARTNER                             $__________________________

     [_] LIMITED PARTNER                                      (____________________# Units)

INSTRUCTIONS

----------------------------------------------------------------------------------------------------------
Make your check payable to: "Atlas America Public #16-2007(A) L.P., Escrow Agent, National City Bank of
PA." Minimum Subscription: one Unit ($10,000). Additional Subscriptions in $1,000 increments. If you are
an individual investor you must personally sign this Signature Page and provide the information requested
below. Wire instructions available upon request.
----------------------------------------------------------------------------------------------------------

Subscriber (All individual investors must personally sign this Signature Page.)

NAME OF TRUST, CORPORATION, LLC, PARTNERSHIP: NAME ______________________________________________________
(ENCLOSE SUPPORTING DOCUMENTS.) IF A PARTNERSHIP, CORPORATION OR TRUST, THEN THE MEMBERS, STOCKHOLDERS OR
BENEFICIARIES THEREOF ARE CITIZENS OF _________________________.

Tax I. D. No.: ____________________________________   Home Address (Do not use P.O. Box)

___________________________________________________   ____________________________________________________
Print Name                                            ____________________________________________________
                                                      ____________________________________________________
X
---------------------------------------------------
Signature

                                                      SEE THE ATTACHED "DISTRIBUTIONS NOT TO ADDRESS OF
                                                      RECORD FOR ELECTRONIC AND ALTERNATE ADDRESS
Tax I. D. No.: ____________________________________   INFORMATION.

___________________________________________________
Print Name

X
---------------------------------------------------
Signature

I received my final prospectus on _________________

(CHECK ONE): OWNERSHIP OF THE UNITS-   [_] Tenants-in-Common                             [_] Partnership
                                       [_] Joint Tenancy with Right of Survivorship      [_] C Corporation
                                       [_] Individual                                    [_] S Corporation
                                       [_] Community Property with Survivorship Rights   [_] Trust
                                       [_] Limited Liability Company                     [_] Other
</TABLE>


                                        1

<PAGE>

<TABLE>
<S>                                    <C>                                               <C>
Date: _____________________

My Telephone No.: Home ____________________________   Business ___________________________________________

My E-mail Address: ________________________________

(CHECK ONE):                      [_] I am at least twenty-one years of age   [_] I am not twenty-one
                                                                                  years of age

(CHECK ONE): I am a:              [_] Calendar Year Taxpayer                  [_] Fiscal Year Taxpayer

(CHECK IF APPLICABLE): I am a:    [_] Farmer (2/3 or more of my gross income in 2005 or 2004 is from
                                      farming)

----------------------------------------------------------------------------------------------------------
             TO BE COMPLETED BY REGISTERED REPRESENTATIVE (FOR COMMISSION AND OTHER PURPOSES)
----------------------------------------------------------------------------------------------------------

I hereby represent that I have discharged my affirmative obligations under Rule 2810(b)(2)(B) and
(b)(3)(D) of the NASD's Conduct Rules and specifically have obtained information from the above-named
subscriber concerning his/her age, net worth, annual income, federal income tax bracket, investment
objectives, investment portfolio, and other financial information and have determined that an investment
in the Partnership is suitable for such subscriber, that such subscriber is or will be in a financial
position to realize the benefits of this investment, and that such subscriber has a fair market net worth
sufficient to sustain the risks for this investment. I have also informed the subscriber of all pertinent
facts relating to the liquidity and marketability of an investment in the Partnership, of the risks of
unlimited liability regarding an investment as an Investor General Partner, and of the passive loss
limitations for tax purposes of an investment as a Limited Partner.

___________________________________________________   ____________________________________________________
Name of Registered Representative and CRD Number      Name of Broker/Dealer

___________________________________________________   ____________________________________________________
Signature of Registered Representative                Broker/Dealer CRD Number

Registered Representative Office Address:             Broker/Dealer Facsimile Number: ____________________

___________________________________________________   Broker/Dealer E-mail Address: ______________________

___________________________________________________

Phone Number: _____________________________________

Facsimile Number: _________________________________

E-mail Address: ___________________________________

___________________________________________________

Company Name (if other than Broker/Dealer Name)

NOTICE TO BROKER-DEALER:

Send SUBSCRIPTION DOCUMENTS completed and signed with CHECK MADE PAYABLE TO: "ATLAS AMERICA PUBLIC
#16-2007(A) L.P., ESCROW AGENT, NATIONAL CITY BANK OF PA" to:

Mr. Justin Atkinson
Anthem Securities, Inc.
311 Rouser Road
P.O. Box 926
Moon Township, Pennsylvania 15108-0926
(412) 262-1680
(412) 262-7430 (FAX)

WIRE TRANSFERS are available. Please contact Ms. Tammy Patterson at (412) 262-1680 for information.

----------------------------------------------------------------------------------------------------------
                              TO BE COMPLETED BY THE MANAGING GENERAL PARTNER
----------------------------------------------------------------------------------------------------------

ACCEPTED THIS __________ day                          ATLAS RESOURCES, LLC,
of ______________________, 2007                       MANAGING GENERAL PARTNER


                                                      By:
                                                          ------------------------------------------------
</TABLE>


                                        2

<PAGE>

In order to induce the Managing General Partner to accept this subscription, I
hereby represent, warrant, covenant and agree as follows:

INVESTOR'S   CO-INVESTOR'S
 INITIALS       INITIALS
----------   -------------

_____        _____           I have received the Prospectus.

_____        _____           I (other than if I am a Minnesota or Maine
                             resident) recognize and understand that before this
                             offering there has been no public market for the
                             Units and it is unlikely that after the offering
                             there will be any such market, the transferability
                             of the Units is restricted, and in case of
                             emergency or other change in circumstances I cannot
                             expect to be able to readily liquidate my
                             investment in the Units.

_____        _____           I am purchasing the Units for my own account, for
                             investment purposes and not for the account of
                             others, and with no present intention of reselling
                             them.

_____        _____           If an individual, I am a citizen of the United
                             States of America and at least twenty-one years of
                             age.

_____        _____           If a partnership, corporation or trust, then I am
                             at least twenty-one years of age and empowered and
                             duly authorized under a governing document, trust
                             instrument, charter, certificate of incorporation,
                             by-law provision or the like to enter into this
                             Subscription Agreement and to perform the
                             transactions contemplated by the Prospectus,
                             including its exhibits.

_____        _____           I (other than if I am a Minnesota or Maine
                             resident) understand that if I am an Investor
                             General Partner, then I will have unlimited joint
                             and several liability for Partnership obligations
                             and liabilities including amounts in excess of my
                             subscription to the extent the obligations and
                             liabilities exceed the Partnership's insurance
                             proceeds, the Partnership's assets, and
                             indemnification by the Managing General Partner.
                             Also, the insurance may be inadequate to cover
                             these liabilities and there is no insurance
                             coverage for certain claims.

_____        _____           I (other than if I am a Minnesota or Maine
                             resident) understand that if I am a Limited
                             Partner, then I may only use my Partnership losses
                             to the extent of my net passive income from passive
                             activities in the year, with any excess losses
                             being deferred.

_____        _____           I (other than if I am a Minnesota or Maine
                             resident) understand that no state or federal
                             governmental authority has made any finding or
                             determination relating to the fairness for public
                             investment of the Units and no state or federal
                             governmental authority has recommended or endorsed
                             or will recommend or endorse the Units.

_____        _____           I (other than if I am a Minnesota or Maine
                             resident) understand that the Selling Agent or
                             registered representative is required to inform me
                             and the other potential investors of all pertinent
                             facts relating to the Units, including the
                             following: the risks involved in the offering,
                             INCLUDING the speculative nature of the investment
                             and the speculative nature of drilling for natural
                             gas and oil; the financial hazards involved in the
                             offering, including the risk of losing my entire
                             investment; the lack of liquidity of my investment;
                             the restrictions on transferability of my Units;
                             the background of the Managing General Partner and
                             the Operator; the tax consequences of my
                             investment; and the unlimited joint and several
                             liability of the Investor General Partners.


                                       3

<PAGE>

To meet the suitability requirements for an investment in your state, please
check and initial either (a), (b), (c) or (d) depending on your state of
residence and whether you are buying limited partner units or investor general
partner units. Also, initial (e) if you are a fiduciary and you meet the
requirement.

INVESTOR'S   CO-INVESTOR'S
 INITIALS       INITIALS
----------   -------------

_____        _____           (a)  IF I PURCHASE LIMITED PARTNER UNITS AND I AM A
                                  RESIDENT OF:

                                  o    ALABAMA,

                                  o    ALASKA,

                                  o    ARIZONA,

                                  o    ARKANSAS,

                                  o    COLORADO,

                                  o    CONNECTICUT,

                                  o    DELAWARE,

                                  o    DISTRICT OF COLUMBIA,

                                  o    FLORIDA,

                                  o    GEORGIA,

                                  o    HAWAII,

                                  o    IDAHO,

                                  o    ILLINOIS,

                                  o    INDIANA,

                                  o    IOWA,

                                  o    KANSAS,

                                  o    KENTUCKY,

                                  o    LOUISIANA,

                                  o    MAINE,

                                  o    MARYLAND,

                                  o    MASSACHUSETTS,

                                  o    MINNESOTA,

                                  o    MISSISSIPPI,

                                  o    MISSOURI,

                                  o    MONTANA,

                                  o    NEBRASKA,

                                  o    NEVADA,

                                  o    NEW MEXICO

                                  o    NEW YORK,

                                  o    NORTH DAKOTA,

                                  o    OKLAHOMA,

                                  o    OREGON,

                                  o    PENNSYLVANIA,

                                  o    RHODE ISLAND,

                                  o    SOUTH CAROLINA,

                                  o    SOUTH DAKOTA,

                                  o    TENNESSEE,

                                  o    TEXAS,

                                  o    UTAH,

                                  o    VERMONT,

                                  o    VIRGINIA,

                                  o    WASHINGTON

                                  o    WEST VIRGINIA,

                                  o    WISCONSIN, OR

                                  o    WYOMING,

                                  then I must have either: a minimum net worth
                                  of $225,000, exclusive of home, home
                                  furnishings, and automobiles, or a minimum net
                                  worth of $60,000, exclusive of home, home
                                  furnishings, and automobiles, and had during
                                  the last tax year or estimate that I will have
                                  during the current tax year "taxable income"
                                  as defined in Section 63 of the Internal
                                  Revenue Code of at least $60,000, without
                                  regard to an investment in the partnership. In
                                  addition, if I am a resident of PENNSYLVANIA,
                                  then I must not make an investment in a
                                  partnership which is in excess of 10% of my
                                  net worth, exclusive of home, home furnishings
                                  and automobiles. Finally, if I am a resident
                                  of KANSAS, it is recommended by the Office of
                                  the Kansas Securities Commissioner that I
                                  should limit my investment in the partnership
                                  and substantially similar programs to no more
                                  than 10% of my net worth, excluding home,
                                  furnishings and automobiles.

_____        _____           (b)  IF I PURCHASE LIMITED PARTNER UNITS AND I AM A
                                  RESIDENT OF:

                                  o    CALIFORNIA,

                                  o    MICHIGAN,

                                  o    NEW HAMPSHIRE,

                                  o    NEW JERSEY,

                                  o    NORTH CAROLINA, OR

                                  o    OHIO,

                                  THEN I REPRESENT THAT I AM AWARE OF AND MEET
                                  THAT STATE'S QUALIFICATIONS AND SUITABILITY
                                  STANDARDS SET FORTH IN EXHIBIT (B) TO THE
                                  PROSPECTUS.


                                       4

<PAGE>

INVESTOR'S   CO-INVESTOR'S
 INITIALS       INITIALS
----------   -------------

_____        _____           (c)  IF I PURCHASE INVESTOR GENERAL PARTNER UNITS
                                  AND I AM A RESIDENT OF:

                                  o    ALASKA,

                                  o    COLORADO,

                                  o    CONNECTICUT,

                                  o    DELAWARE,

                                  o    DISTRICT OF COLUMBIA,

                                  o    FLORIDA,

                                  o    GEORGIA,

                                  o    HAWAII,

                                  o    IDAHO,

                                  o    ILLINOIS,

                                  o    LOUISIANA,

                                  o    MARYLAND,

                                  o    MONTANA,

                                  o    NEBRASKA,

                                  o    NEVADA,

                                  o    NEW YORK,

                                  o    NORTH DAKOTA,

                                  o    RHODE ISLAND,

                                  o    SOUTH CAROLINA,

                                  o    UTAH,

                                  o    VIRGINIA,

                                  o    WEST VIRGINIA,

                                  o    WISCONSIN, OR

                                  o    WYOMING,

                                  then I must have either: a net worth of at
                                  least $225,000, exclusive of home, furnishings
                                  and automobiles, or a net worth, exclusive of
                                  home, furnishings and automobiles, of at least
                                  $60,000, and had during the last tax year, or
                                  estimate that I will have during the current
                                  tax year, "taxable income" as defined in
                                  Section 63 of the Code of at least $60,000,
                                  without regard to an investment in the
                                  Partnership.

_____        _____           (d)  IF I PURCHASE INVESTOR GENERAL PARTNER UNITS
                                  AND I AM A RESIDENT OF:

                                  o    ALABAMA,

                                  o    ARIZONA,

                                  o    ARKANSAS,

                                  o    CALIFORNIA,

                                  o    INDIANA,

                                  o    IOWA,

                                  o    KANSAS,

                                  o    KENTUCKY,

                                  o    MAINE,

                                  o    MASSACHUSETTS,

                                  o    MICHIGAN,

                                  o    MINNESOTA,

                                  o    MISSISSIPPI,

                                  o    MISSOURI,

                                  o    NEW HAMPSHIRE,

                                  o    NEW JERSEY,

                                  o    NEW MEXICO,

                                  o    NORTH CAROLINA,

                                  o    OHIO,

                                  o    OKLAHOMA,

                                  o    OREGON,

                                  o    PENNSYLVANIA,

                                  o    SOUTH DAKOTA,

                                  o    TENNESSEE,

                                  o    TEXAS,

                                  o    VERMONT OR

                                  o    WASHINGTON,

                                  THEN I REPRESENT THAT I AM AWARE OF AND MEET
                                  THAT STATE'S QUALIFICATIONS AND SUITABILITY
                                  STANDARDS SET FORTH IN EXHIBIT (B) TO THE
                                  PROSPECTUS.

_____        _____           (e)  If I am a fiduciary, then I am purchasing for
                                  a person or entity having the appropriate
                                  income and/or net worth specified in (a), (b),
                                  (c) or (d) above.

THE ABOVE REPRESENTATIONS DO NOT CONSTITUTE A WAIVER OF ANY RIGHTS THAT I MAY
HAVE UNDER THE ACTS ADMINISTERED BY THE SEC OR BY ANY STATE REGULATORY AGENCY
ADMINISTERING STATUTES BEARING ON THE SALE OF SECURITIES.

Pennsylvania Income Tax Election
Unless you elect to opt out by checking the box below, the Partnership will file
an annual Pennsylvania income tax return on your behalf and withhold and pay
Pennsylvania income taxes from your share of its distributions.

     / /   I elect to opt out of the Partnership filing and paying Pennsylvania
           income taxes on my behalf because I will have Pennsylvania income
           from sources other than the Partnereship.



                                       5

<PAGE>

INSTRUCTIONS TO INVESTOR

You are required to execute your own Subscription Agreement and the Managing
General Partner will not accept any Subscription Agreement that has been
executed by someone other than you unless the person has been given your legal
power of attorney to sign on your behalf, and you meet all of the conditions in
the Prospectus and this Subscription Agreement. In the case of sales to
fiduciary accounts, the minimum standards set forth in the Prospectus and this
Subscription Agreement must be met by the beneficiary, the fiduciary account, or
by the donor or grantor who directly or indirectly supplies the funds to
purchase the Partnership Units if the donor or grantor is the fiduciary.

Your execution of the Subscription Agreement constitutes your binding offer to
buy Units in the Partnership. Once you subscribe you may withdraw your
subscription only by providing the Managing General Partner with written notice
of your withdrawal before your subscription is accepted by the Managing General
Partner. The Managing General Partner has the discretion to refuse to accept
your subscription without liability to you. Subscriptions will be accepted or
rejected by the Partnership within 30 days of their receipt. If your
subscription is rejected, then all of your funds will be returned to you
immediately. If your subscription is accepted before the first closing, then you
will be admitted as a Participant not later than 15 days after the release from
escrow of the investors' funds to the Partnership. If your subscription is
accepted after the first closing, then you will be admitted into the Partnership
not later than the last day of the calendar month in which your subscription was
accepted by the Partnership.

The Managing General Partner will not complete a sale of Units to you and send
you a confirmation of purchase until at least five business days after the date
you receive a final Prospectus.

NOTICE TO CALIFORNIA RESIDENTS: This offering deviates in certain respects from
various requirements of Title 10 of the California Administrative Code. These
deviations include, but are not limited to the following: the definition of
Prospect in the Prospectus, unlike Rule 260.140.127.2(b) and Rule
260.140.121(1), does not require enlarging or contracting the size of the area
on the basis of geological data in all cases. If I am a resident of California,
I acknowledge the receipt of California Rule 260.141.11 set forth in Exhibit (B)
to the Prospectus.


                                       6
<PAGE>

                                    SECTION D

                        TO BE COMPLETED BY ALL INVESTORS

     TAXPAYER IDENTIFICATION NUMBER CERTIFICATION - CHECK THE FIRST BOX BELOW,
     UNLESS YOU ARE A FOREIGN INVESTOR OR YOU ARE INVESTING AS A U.S. GRANTOR
     TRUST.

     NOTE: IF THERE IS A CHANGE IN CIRCUMSTANCES WHICH MAKES ANY OF THE
     INFORMATION PROVIDED BY YOU IN YOUR CERTIFICATION BELOW INCORRECT, THEN YOU
     ARE UNDER A CONTINUING OBLIGATION SO LONG AS YOU OWN UNITS IN THE
     PARTNERSHIP TO NOTIFY THE PARTNERSHIP AND FURNISH THE PARTNERSHIP A NEW
     CERTIFICATE WITHIN THIRTY (30) DAYS OF THE CHANGE.

     [_]  UNDER PENALTIES OF PERJURY, I CERTIFY THAT:

          (1)  THE NUMBER PROVIDED IN MY SUBSCRIPTION AGREEMENT IS MY CORRECT
               "TIN" (I.E., SOCIAL SECURITY NUMBER OR EMPLOYER IDENTIFICATION
               NUMBER);

          (2)  I AM NOT SUBJECT TO BACKUP WITHHOLDING BECAUSE (a) I AM EXEMPT
               FROM BACKUP WITHHOLDING UNDER Section 3406(g)(1) OF THE INTERNAL
               REVENUE CODE AND THE RELATED REGULATIONS, OR (B) I HAVE NOT BEEN
               NOTIFIED BY THE INTERNAL REVENUE SERVICE (IRS) THAT I AM SUBJECT
               TO BACKUP WITHHOLDING AS A RESULT OF FAILURE TO REPORT ALL
               INTEREST OR DIVIDENDS, OR (C) THE IRS HAS NOTIFIED ME THAT I AM
               NO LONGER SUBJECT TO BACKUP WITHHOLDING; AND

          (3)  I AM A U.S. PERSON (WHICH INCLUDES U.S. CITIZENS, RESIDENT
               ALIENS, ENTITIES OR ASSOCIATIONS FORMED IN THE U.S. OR UNDER U.S.
               LAW, AND U.S. ESTATES AND TRUSTS.)

     (NOTE: YOU MUST CROSS OUT ITEM 2 ABOVE IF YOU HAVE BEEN NOTIFIED BY THE IRS
     THAT YOU ARE CURRENTLY SUBJECT TO BACKUP WITHHOLDING BECAUSE YOU HAVE
     FAILED TO REPORT ALL INTEREST AND DIVIDENDS ON YOUR TAX RETURN.)

          [_]  FOREIGN PARTNER. I AM AT LEAST 21 YEARS OF AGE, AND I HAVE
               PROVIDED THE PARTNERSHIP WITH THE APPROPRIATE FORM W-8
               CERTIFICATION OR, IF A JOINT ACCOUNT, EACH JOINT ACCOUNT OWNER
               HAS PROVIDED THE PARTNERSHIP THE APPROPRIATE FORM W-8
               CERTIFICATION, AND IF ANY ONE OF THE JOINT ACCOUNT OWNERS HAS NOT
               ESTABLISHED FOREIGN STATUS, THAT JOINT ACCOUNT OWNER HAS PROVIDED
               THE PARTNERSHIP WITH A CERTIFIED TIN.

          [_]  U.S. GRANTOR TRUSTS. UNDER PENALTIES OF PERJURY, I CERTIFY THAT:

               (1)  THE TRUST DESIGNATED AS THE INVESTOR ON THE SUBSCRIPTION
                    AGREEMENT IS A UNITED STATES GRANTOR TRUST WHICH I CAN AMEND
                    OR REVOKE DURING MY LIFETIME;

               (2)  UNDER SUBPART E OF SUBCHAPTER J OF THE INTERNAL REVENUE CODE
                    (CHECK ONLY ONE OF THE BOXES BELOW):

                    [_]  (A) 100% OF THE TRUST IS TREATED AS OWNED BY ME;

                    [_]  (B) THE TRUST IS TREATED AS OWNED IN EQUAL SHARES BY ME
                             AND MY SPOUSE; OR

                    [_]  (C) ____% OF THE TRUST IS TREATED AS OWNED BY
                             ________________________, AND THE REMAINDER IS
                             TREATED AS OWNED _____% BY ME AND _____% BY MY
                             SPOUSE); AND

               (3)  EACH GRANTOR OR OTHER OWNER OF ANY PORTION OF THE TRUST HAS
                    PROVIDED THE PARTNERSHIP WITH THE APPROPRIATE FORM W-8 OR
                    FORM W-9 CERTIFICATION.

     NOTE: IF YOU CHECK THE BOX IN (2)(c), YOU MUST INSERT THE INFORMATION
     CALLED FOR BY THE BLANKS.

     THE INTERNAL REVENUE SERVICE DOES NOT REQUIRE YOUR CONSENT TO ANY PROVISION
     OF THIS DOCUMENT OTHER THAN THE CERTIFICATIONS REQUIRED TO AVOID BACKUP
     WITHHOLDING.


                                        7

<PAGE>

                        ATLAS AMERICA SERIES 27-2006 L.P.
                     DISTRIBUTIONS NOT TO ADDRESS OF RECORD

      PLEASE COMPLETE THIS FORM TO REQUEST ELECTRONIC OR ALTERNATE MAILING
                                  DISTRIBUTION

INVESTOR INFORMATION:

NAME _________________________________________ SOCIAL SECURITY NO.: ____________

================================================================================

                 ALTERNATE ADDRESS -- ELECTRONIC DEPOSIT OPTION
                    (ACH TRANSACTIONS ONLY, NOT FOR WIRE USE)

NAME OF FINANCIAL INSTITUTION: _________________________________________________

ABA NUMBER: _____________________________ ACCOUNT NUMBER: ______________________

NAME ON ACCOUNT ________________________________________________________________

TYPE OF ACCOUNT:           [_]   CHECKING/BROKER             [_]  SAVINGS

================================================================================

   ALTERNATE MAILING INSTRUCTIONS FOR DISTRIBUTIONS TO FINANCIAL INSTITUTIONS
                              (NEED ACCOUNT NUMBER)

PAYEE (NAME FOR CHECK TO BE MADE OUT TO): ______________________________________

________________________________________________________________________________

STREET OR POST OFFICE BOX NUMBER: ______________________________________________
CITY, STATE, ZIP CODE __________________________________________________________
FOR THE BENEFIT OF (NAME): _____________________________________________________
ACCOUNT NUMBER: ________________________________________________________________

================================================================================

            ALTERNATE MAILING ADDRESS OTHER THAN TO ADDRESS OF RECORD

    NO ACCOUNT NUMBER (P.O. BOX // ALTERNATE ADDRESS // DO NOT USE ADDRESS OF
                                     RECORD)

NAME: __________________________________________________________________________

ADDRESS: _______________________________________________________________________

CITY, STATE, ZIP CODE: _________________________________________________________

================================================================================

INVESTOR'S SIGNATURE: __________________________________________________________
PRINT INVESTOR'S NAME: _________________________________________________________

================================================================================

OFFICE USE ONLY:
   DATE RECEIVED: ______ DATE ENTERED: ______ INITIALS _____ ATLAS ID. NO. _____

ATLAS RESOURCES, LLC, MGP, 311 Rouser Road, Moon Township, PA 15108, PHONE:
1-800-251-0171 FAX: 412-262-7430


                                        8

<PAGE>

                                  EXHIBIT (II)

                                     FORM OF

                        DRILLING AND OPERATING AGREEMENT

                                       FOR

                      ATLAS AMERICA PUBLIC #16-2007(A) L.P.

                     [ATLAS AMERICA PUBLIC #16-2007(B) L.P.]

<PAGE>

                                      INDEX

SECTION                                                                     PAGE
                                                                            ----

1.   Assignment of Well Locations; Representations and Indemnification
     Associated with the Assignment of the Lease; Designation of
     Additional Well Locations; Outside Activities Are Not Restricted....     1
2.   Drilling of Wells; Timing; Depth; Interest of Developer; Right to
     Substitute Well Locations...........................................     2
3.   Operator - Responsibilities in General; Covenants; Term.............     3
4.   Operator's Charges for Drilling and Completing Wells; Payment;
     Completion Determination; Dry Hole Determination; Excess Funds and
     Cost Overruns - Intangible Drilling Costs; Excess Funds and Cost
     Overruns - Tangible Costs...........................................     5
5.   Title Examination of Well Locations; Developer's Acceptance and
     Liability; Additional Well Locations................................     8
6.   Operations Subsequent to Completion of the Wells; Fee Adjustments;
     Extraordinary Costs; Pipelines; Price Determinations; Plugging and
     Abandonment.........................................................     8
7.   Billing and Payment Procedure with Respect to Operation of Wells;
     Disbursements; Separate Account for Sale Proceeds; Records and
     Reports; Additional Information.....................................    10
8.   Operator's Lien; Right to Collect From Oil or Gas Purchaser.........    12
9.   Successors and Assigns; Transfers; Appointment of Agent.............    12
10.  Operator's Insurance; Subcontractors' Insurance; Operator's
     Liability...........................................................    14
11.  Internal Revenue Code Election; Relationship of Parties; Right to
     Take Production in Kind.............................................    14
12.  Effect of Force Majeure; Definition of Force Majeure; Limitation....    15
13.  Term................................................................    16
14.  Governing Law; Invalidity...........................................    16
15.  Integration; Written Amendment......................................    16
16.  Waiver of Default or Breach.........................................    16
17.  Notices.............................................................    16
18.  Interpretation......................................................    17
19.  Counterparts........................................................    17
     Signature Page......................................................    17

     Exhibit A                 Description of Leases and Initial Well Locations
     Exhibits A-l through A-_  Maps of Initial Well Locations
     Exhibit B                 Form of Assignment
     Exhibit C                 Form of Addendum

<PAGE>

                        DRILLING AND OPERATING AGREEMENT

THIS AGREEMENT made this ______ day of _______________, 200____, by and between
ATLAS RESOURCES, LLC, a Pennsylvania limited liability company (hereinafter
referred to as "Atlas" or "Operator"),

                                       and

ATLAS AMERICA PUBLIC #16-2007(A) L.P. [Atlas America Public #16-2007(B) L.P.], a
Delaware limited partnership, (hereinafter referred to as the "Developer").

                                WITNESSETH THAT:

WHEREAS, the Operator, by virtue of the Oil and Gas Leases (the "Leases")
described on Exhibit A attached to and made a part of this Agreement, has
certain rights to develop the ____________ (______) initial well locations (the
"Initial Well Locations") identified on the maps attached to and made a part of
this Agreement as Exhibits A-l through A-______;

WHEREAS, the Developer, subject to the terms and conditions of this Agreement,
desires to acquire certain of the Operator's rights to develop the Initial Well
Locations and to provide for the development on the terms and conditions set
forth in this Agreement of additional well locations ("Additional Well
Locations") that the parties may from time to time designate; and

WHEREAS, the Operator is in the oil and gas exploration and development
business, and the Developer desires that Operator, as its independent
contractor, perform certain services in connection with its efforts to develop
the aforesaid Initial and Additional Well Locations (collectively the "Well
Locations") and to operate the wells completed on the Well Locations, on the
terms and conditions set forth in this Agreement;

NOW THEREFORE, in consideration of the mutual covenants herein contained and
subject to the terms and conditions hereinafter set forth, the parties hereto,
intending to be legally bound, hereby agree as follows:

1.   ASSIGNMENT OF WELL LOCATIONS; REPRESENTATIONS AND INDEMNIFICATION
     ASSOCIATED WITH THE ASSIGNMENT OF THE LEASE; DESIGNATION OF ADDITIONAL WELL
     LOCATIONS; OUTSIDE ACTIVITIES ARE NOT RESTRICTED.

     (a)  ASSIGNMENT OF WELL LOCATIONS. The Operator shall execute an assignment
          of an undivided percentage of Working Interest in the Well Location
          acreage for each well to the Developer as shown on Exhibit A attached
          hereto, which assignment shall be limited to a depth from the surface
          to the deepest depth penetrated at the cessation of drilling
          operations.

          The assignment shall be substantially in the form of Exhibit B
          attached to and made a part of this Agreement. The amount of acreage
          included in each Initial Well Location and the configuration of the
          Initial Well Location are indicated on the maps attached to this
          Agreement as Exhibits A-l through A-______. The amount of acreage
          included in each Additional Well Location and the configuration of the
          Additional Well Location shall be indicated on the maps to be attached
          as exhibits to the applicable addendum to this Agreement as provided
          in sub-section (c) below.

     (b)  REPRESENTATIONS AND INDEMNIFICATION ASSOCIATED WITH THE ASSIGNMENT OF
          THE LEASE. The Operator represents and warrants to the Developer that:

          (i)  the Operator is the lawful owner of the Lease and rights and
               interest under the Lease and of the personal property on the
               Lease or used in connection with the Lease;

          (ii) the Operator has good right and authority to sell and convey the
               rights, interest, and property;

          (iii) the rights, interest, and property are free and clear from all
               liens and encumbrances; and

          (iv) all rentals and royalties due and payable under the Lease have
               been duly paid.


                                       1

<PAGE>

          These representations and warranties shall also be included in each
          recorded assignment of the acreage included in each Initial Well
          Location and Additional Well Location designated pursuant to
          sub-section (c) below, substantially in the form of Exhibit B attached
          to and made a part of this Agreement.

          The Operator agrees to indemnify, protect and hold the Developer and
          its successors and assigns harmless from and against all costs
          (including but not limited to reasonable attorneys' fees),
          liabilities, claims, penalties, losses, suits, actions, causes of
          action, judgments or decrees resulting from the breach of any of the
          above representations and warranties. It is understood and agreed
          that, except as specifically set forth above, the Operator makes no
          warranty or representation, express or implied, as to its title or the
          title of the lessors in and to the lands or oil and gas interests
          covered by said Leases.

     (c)  DESIGNATION OF ADDITIONAL WELL LOCATIONS. If the parties hereto desire
          to designate Additional Well Locations to be developed in accordance
          with the terms and conditions of this Agreement, then the parties
          shall execute an addendum substantially in the form of Exhibit C
          attached to and made a part of this Agreement specifying:

          (i)  the undivided percentage of Working Interest and the Oil and Gas
               Leases to be included as Leases under this Agreement;

          (ii) the amount and configuration of acreage included in each
               Additional Well Location on maps attached as exhibits to the
               addendum; and

          (iii) their agreement that the Additional Well Locations shall be
               developed in accordance with the terms and conditions of this
               Agreement.

     (d)  OUTSIDE ACTIVITIES ARE NOT RESTRICTED. It is understood and agreed
          that the assignment of rights under the Leases and the oil and gas
          development activities contemplated by this Agreement relate only to
          the Initial Well Locations and the Additional Well Locations. Nothing
          contained in this Agreement shall be interpreted to restrict in any
          manner the right of each of the parties to conduct without the
          participation of the other party any additional activities relating to
          exploration, development, drilling, production, or delivery of oil and
          gas on lands adjacent to or in the immediate vicinity of the Well
          Locations or elsewhere.

2.   DRILLING OF WELLS; TIMING; DEPTH; INTEREST OF DEVELOPER; RIGHT TO
     SUBSTITUTE WELL LOCATIONS.

     (a)  DRILLING OF WELLS. Operator, as Developer's independent contractor,
          agrees to drill, complete (or plug) and operate ____________ (_____)
          oil and gas wells on the ____________ (______) Initial Well Locations
          in accordance with the terms and conditions of this Agreement.
          Developer, as a minimum commitment, agrees to participate in and pay
          the Operator's charges for drilling and completing (or plugging) the
          wells and any extra costs pursuant to Section 4 in proportion to the
          share of the Working Interest owned by the Developer in the wells with
          respect to all initial wells. It is understood and agreed that,
          subject to sub-section (e) below, Developer does not reserve the right
          to decline participation in the drilling of any of the initial wells
          to be drilled under this Agreement.

     (b)  TIMING. Operator shall begin drilling the first well within thirty
          (30) days after the date of this Agreement, and shall begin drilling
          each of the other initial wells for which payment is made pursuant to
          Section 4(b) before the close of the 90th day after the close of the
          calendar year in which this Agreement is entered into by Operator and
          the Developer. Subject to the foregoing time limits, Operator shall
          determine the timing of and the order of drilling the Initial Well
          Locations.

     (c)  DEPTH. All of the wells to be drilled under this Agreement shall be:

          (i)  drilled and completed (or plugged) in accordance with the
               generally accepted and customary oil and gas field practices and
               techniques then prevailing in the geographical area of the Well
               Locations; and


                                       2

<PAGE>

          (ii) drilled to a depth sufficient to test thoroughly the objective
               formation or the deepest assigned depth, whichever is less.

     (d)  INTEREST OF DEVELOPER. Except as otherwise provided in this Agreement,
          all costs, expenses, and liabilities incurred in connection with the
          drilling and other operations and activities contemplated by this
          Agreement shall be borne and paid, and all wells, gathering lines of
          up to approximately 2,500 feet on each Well Location in connection
          with a natural gas well, equipment, materials, and facilities
          acquired, constructed or installed under this Agreement shall be
          owned, by the Developer in proportion to the share of the Working
          Interest owned by the Developer in the wells. Subject to the payment
          of lessor's royalties and other royalties and overriding royalties, if
          any, production of oil and gas from the wells to be drilled under this
          Agreement shall be owned by the Developer in proportion to the share
          of the Working Interest owned by the Developer in the wells.

     (e)  RIGHT TO SUBSTITUTE WELL LOCATIONS. Notwithstanding the provisions of
          sub-section (a) above, if the Operator or Developer determines in good
          faith, with respect to any Well Location, before operations begin
          under this Agreement on the Well Location, that it would not be in the
          best interest of the parties to drill a well on the Well Location,
          then the party making the determination shall notify the other party
          of its determination and the basis for its determination and, unless
          otherwise instructed by Developer, the well shall not be drilled. This
          determination may be based on:

          (i)   the production or failure of production of any other wells that
                may have been recently drilled in the immediate area of the Well
                Location;

          (ii)  newly discovered title defects; or

          (iii) any other evidence with respect to the Well Location as may have
                been obtained.

          If the well is not drilled, then Operator shall promptly propose a new
          well location (including all information for the Well Location as
          Developer may reasonably request) to be substituted for the original
          Well Location. Developer shall then have seven (7) business days to
          either reject or accept the proposed new well location. If the new
          well location is rejected, then Operator shall promptly propose
          another substitute well location pursuant to the provisions of this
          sub-section.

          Once the Developer accepts a substitute well location or does not
          reject it within the seven (7) day period, this Agreement shall
          terminate as to the original Well Location and the substitute well
          location shall become subject to the terms and conditions of this
          Agreement.

3.   OPERATOR - RESPONSIBILITIES IN GENERAL; COVENANTS; TERM.

     (a)  OPERATOR - RESPONSIBILITIES IN GENERAL. Atlas shall be the Operator of
          the wells and Well Locations subject to this Agreement and, as the
          Developer's independent contractor, shall, in addition to its other
          obligations under this Agreement do the following:

          (i)   arrange for drilling and completing (or plugging) the wells and,
                if a gas well, installing the necessary gas gathering line
                systems and connection facilities;

          (ii)  make the technical decisions required in drilling, testing,
                completing (or plugging), and operating the wells;

          (iii) manage and conduct all field operations in connection with the
                drilling, testing, completing (or plugging), equipping,
                operating, and producing the wells;

          (iv)  maintain all wells, equipment, gathering lines if a gas well,
                and facilities in good working order during their useful lives;
                and


                                       3

<PAGE>

          (v)  perform the necessary administrative and accounting functions.

          In performing the work contemplated by this Agreement, Operator is an
          independent contractor with authority to control and direct the
          performance of the details of the work.

     (b)  COVENANTS. Operator covenants and agrees that under this Agreement:

          (i)   it shall perform and carry on (or cause to be performed and
                carried on) its duties and obligations in a good, prudent,
                diligent, and workmanlike manner using technically sound,
                acceptable oil and gas field practices then prevailing in the
                geographical area of the Well Locations;

          (ii)  all drilling and other operations conducted by, for and under
                the control of Operator shall conform in all respects to
                federal, state and local laws, statutes, ordinances,
                regulations, and requirements;

          (iii) unless otherwise agreed in writing by the Developer, all work
                performed pursuant to a written estimate shall conform to the
                technical specifications set forth in the written estimate and
                all equipment and materials installed or incorporated in the
                wells and facilities shall be new or used and of good quality;

          (iv)  in the course of conducting operations, it shall comply with all
                terms and conditions, other than any minimum drilling
                commitments, of the Leases (and any related assignments,
                amendments, subleases, modifications and supplements);

          (v)   it shall keep the Well Locations and all wells, equipment and
                facilities located on the Well Locations free and clear of all
                labor, materials and other types of liens or encumbrances
                arising out of operations;

          (vi)  it shall file all reports and obtain all permits and bonds
                required to be filed with or obtained from any governmental
                authority or agency in connection with the drilling or other
                operations and activities; and

          (vii) it will provide competent and experienced personnel to supervise
                drilling, completing (or plugging), and operating the wells and
                use the services of competent and experienced service companies
                to provide any third party services necessary or appropriate in
                order to perform its duties.

     (c)  TERM. Atlas shall serve as Operator under this Agreement until the
          earliest of:

          (i)   the termination of this Agreement pursuant to Section 13;

          (ii)  the termination of Atlas as Operator by the Developer at any
                time in the Developer's discretion, with or without cause on
                sixty (60) days' advance written notice to the Operator; or

          (iii) the resignation of Atlas as Operator under this Agreement which
                may occur on ninety (90) days' written notice to the Developer
                at any time after five (5) years from the date of this
                Agreement, it being expressly understood and agreed that Atlas
                shall have no right to resign as Operator before the expiration
                of the five-year period.

          Any successor Operator shall be selected by the Developer. Nothing
          contained in this sub-section shall relieve or release Atlas or the
          Developer from any liability or obligation under this Agreement that
          accrued or occurred before Atlas' removal or resignation as Operator
          under this Agreement. On any change in Operator under this provision,
          the then present Operator shall deliver to the successor Operator
          possession of all records, equipment, materials and appurtenances used
          or obtained for use in connection with operations under this Agreement
          and owned by the Developer.


                                       4

<PAGE>

4.   OPERATOR'S CHARGES FOR DRILLING AND COMPLETING WELLS; PAYMENT; COMPLETION
     DETERMINATION; DRY HOLE DETERMINATION; EXCESS FUNDS AND COST
     OVERRUNS-INTANGIBLE DRILLING COSTS; EXCESS FUNDS AND COST OVERRUNS-TANGIBLE
     COSTS.

     (a)  OPERATOR'S CHARGES FOR DRILLING AND COMPLETING WELLS. Each oil and gas
          well that is drilled and completed under this Agreement shall be
          drilled and completed for an amount equal to the sum of the following
          items: (i) the Cost of permits, supplies, materials, equipment, and
          all other items used in the drilling and completion of a well provided
          by third-parties, or if the foregoing items are provided by Affiliates
          of the Developer's Managing General Partner, then those items shall be
          charged at competitive rates; (ii) fees for third-party services;
          (iii) fees for services provided by the Developer's Managing General
          Partner's Affiliates, which shall be charged at competitive rates;
          (iv) an administration and oversight fee of $15,000 per well, which
          shall be charged to the Developer's investors as part of each well's
          Intangible Drilling Costs, as that term is defined below and the
          portion of Tangible Costs, as that term is defined below, paid by the
          Developer's investors; and (v) a mark-up in an amount equal to 15% of
          the sum of (i), (ii), (iii) and (iv), above, for the Developer's
          Managing General Partner's services as general drilling contractor as
          Operator under this Agreement. "Cost" shall mean the price paid by
          Operator in an arm's-length transaction.

          The estimated price for drilling and completing each of the wells
          shall be set forth in an Authority for Expenditure ("AFE") that shall
          be attached to this Agreement as an Exhibit, and shall cover all
          ordinary costs which may be incurred in drilling and completing (or
          plugging) each well. This includes without limitation, site
          preparation, permits and bonds, roadways, surface damages, power at
          the site, water, Operator's compensation as set forth above,
          rights-of-way, drilling rigs, equipment and materials, costs of title
          examinations, logging, cementing, fracturing, casing, meters (other
          than utility purchase meters), connection facilities, salt water
          collection tanks, separators, siphon string, rabbit, tubing, an
          average of 2,500 feet of gathering line per well in connection with
          each gas well, and geological, geophysical and engineering services.

     (b)  PAYMENT. The Developer shall pay to Operator, in proportion to the
          share of the Working Interest owned by the Developer in the wells, one
          hundred percent (100%) of the estimated Intangible Drilling Costs and
          Tangible Costs, as those terms are defined below, for drilling and
          completing all initial wells on execution of this Agreement.
          Notwithstanding the foregoing, Atlas' payments for its share of the
          estimated Tangible Costs, as that term is defined below, of drilling
          and completing all initial wells as the Managing General Partner of
          the Developer shall be paid within five (5) business days of notice
          from Operator that the costs have been incurred. The Developer's
          payment shall be nonrefundable in all events in order to enable
          Operator to do the following:

          (i)   commence site preparation for the initial wells;

          (ii)  obtain suitable subcontractors for drilling and completing or
                plugging the initial wells at currently prevailing prices; and

          (iii) insure the availability of equipment and materials.

          For purposes of this Agreement, "Intangible Drilling Costs" shall mean
          those expenditures associated with property acquisition and the
          drilling and completion of oil and gas wells that under present law
          are generally accepted as fully deductible currently for federal
          income tax purposes. This includes:

          (i)  all expenditures made with respect to any well before the
               establishment of production in commercial quantities for wages,
               fuel, repairs, hauling, supplies and other costs and expenses
               incident to and necessary for the drilling of the well and the
               preparation of the well for the production of oil or gas, that
               are currently deductible pursuant to Section 263(c) of the
               Internal Revenue Code of 1986, as amended (the "Code"), and
               Treasury Reg. Section 1.612-4, which are generally termed
               "intangible drilling and development costs";


                                       5

<PAGE>

          (ii)  the expense of plugging and abandoning any well before a
                completion attempt; and

          (iii) the costs (other than Tangible Costs and Lease acquisition
                costs) to re-enter and deepen an existing well, complete the
                well to deeper formations or reservoirs, or plug and abandon the
                well if it is nonproductive from the targeted deeper formations
                or reservoirs.

          "Tangible Costs" shall mean those costs associated with property
          acquisition and the drilling and completion of oil and gas wells that
          are generally accepted as capital expenditures pursuant to the
          provisions of the Code. This includes:

          (i)   all costs of equipment, parts and items of hardware used in
                drilling and completing (or plugging) a well;

          (ii)  the costs (other than Intangible Drilling Costs and Lease
                acquisition costs) to re-enter and deepen an existing well,
                complete the well to deeper formations or reservoirs, or plug
                and abandon the well if it is nonproductive from the targeted
                deeper formations or reservoirs; and

          (iii) those items necessary to deliver acceptable oil and gas
                production to purchasers to the extent installed downstream from
                the wellhead of any well, which are required to be capitalized
                under the Code and its regulations.

          With respect to each additional well drilled on the Additional Well
          Locations, if any, the Developer shall pay to Operator, in proportion
          to the share of the Working Interest owned by the Developer in the
          wells, one hundred percent (100%) of the estimated Intangible Drilling
          Costs and Tangible Costs for drilling and completing the well on
          execution of the applicable addendum pursuant to Section l(c) above.
          Notwithstanding the foregoing, Atlas' payments for its share of the
          estimated Tangible Costs of drilling and completing all additional
          wells as the Managing General Partner of the Developer shall be paid
          within five (5) business days of notice from Operator that the costs
          have been incurred. The Developer's payment shall be nonrefundable in
          all events in order to enable Operator to do the following:

          (i)   commence site preparation for the additional wells;

          (ii)  obtain suitable subcontractors for drilling and completing the
                additional wells at currently prevailing prices; and

          (iii) insure the availability of equipment and materials.

          Developer shall pay, in proportion to the share of the Working
          Interest owned by the Developer in the wells, any extra costs incurred
          for each well pursuant to sub-section (a) above within ten (10)
          business days of its receipt of Operator's statement for the extra
          costs.

     (c)  COMPLETION DETERMINATION. Operator shall determine whether or not to
          run the production casing for an attempted completion or to plug and
          abandon any well drilled under this Agreement. However, a well shall
          be completed only if Operator has made a good faith determination that
          there is a reasonable possibility of obtaining commercial quantities
          of oil and/or gas.

     (d)  DRY HOLE DETERMINATION. If Operator determines at any time during the
          drilling or attempted completion of any well drilled under this
          Agreement, in accordance with the generally accepted and customary oil
          and gas field practices and techniques then prevailing in the
          geographic area of the Well Location that the well should not be
          completed, then it shall promptly and properly plug and abandon the
          well.

     (e)  EXCESS FUNDS AND COST OVERRUNS-INTANGIBLE DRILLING COSTS. Any
          estimated Intangible Drilling Costs (which are the Intangible Drilling
          Costs set forth on the AFE) prepaid by Developer with respect to any
          well that exceed Operator's price specified in sub-section (a) above
          for the Intangible Drilling Costs of the


                                       6

<PAGE>

          well shall be retained by Operator and shall be applied, in proportion
          to the share of the Working Interest owned by the Developer in the
          wells, to:

          (i)  the Intangible Drilling Costs of an additional well or wells to
               be drilled on the Additional Well Locations; or

          (ii) any cost overruns owed by the Developer to Operator for
               Intangible Drilling Costs on one or more of the other wells on
               the Well Locations.

          Conversely, if Operator's price specified in sub-section (a) above for
          the Intangible Drilling Costs of any well exceeds the estimated
          Intangible Drilling Costs (which are the Intangible Drilling Costs set
          forth on the AFE) prepaid by Developer for the well, then:

          (i)  Developer shall pay the additional price to Operator within ten
               (10) business days after notice from Operator that the additional
               amount is due and owing; or

          (ii) Developer and Operator may agree to delete or reduce Developer's
               Working Interest in one or more wells to be drilled under this
               Agreement that have not yet been spudded to provide funds to pay
               the additional amounts owed by Developer to Operator. If doing so
               results in any excess prepaid Intangible Drilling Costs, then
               these funds shall be applied, in proportion to the share of the
               Working Interest owned by the Developer in the wells, to:

               (a)  the Intangible Drilling Costs of an additional well or wells
                    to be drilled on the Additional Well Locations; or

               (b)  any cost overruns owed by the Developer to Operator for
                    Intangible Drilling Costs of one or more of the other wells
                    on the Well Locations.

          The Exhibits to this Agreement with respect to the affected wells
          shall be amended as appropriate.

     (f)  EXCESS FUNDS AND COST OVERRUNS - TANGIBLE COSTS. Any estimated
          Tangible Costs (which are the Tangible Costs set forth on the AFE)
          prepaid by Developer with respect to any well that exceed Operator's
          price specified in sub-section (a) above for the Tangible Costs of the
          well shall be retained by Operator and shall be applied, in proportion
          to the share of the Working Interest owned by the Developer in the
          wells, to:

          (i)  the Developer's Participants' share of the Tangible Costs for an
               additional well or wells to be drilled on the Additional Well
               Locations; or

          (ii) any cost overruns owed by the Developer to Operator for the
               Developer's Participants' share of the Tangible Costs of one or
               more of the other wells on the Well Locations.

          Conversely, if Operator's price specified in sub-section (a) above for
          the Developer's Participants' share of Tangible Costs of any well
          exceeds the estimated Tangible Costs (which are the Tangible Costs set
          forth on the AFE) prepaid by Developer for the Developer's
          Participants' share of the Tangible Costs for the well, then:

          (i)   Developer shall pay the additional price to Operator within ten
                (10) business days after notice from Operator that the
                additional price is due and owing; or

          (ii)  Developer and Operator may agree to delete or reduce Developer's
                Working Interest in one or more wells to be drilled under this
                Agreement that have not yet been spudded to provide funds to pay
                the additional amounts owed by Developer to Operator. If doing
                so results in any excess prepaid Tangible Costs, then these
                funds shall be applied, in proportion to the share of the
                Working Interest owed by the Developer in the wells, to:


                                       7

<PAGE>

               (a)  the Developer's Participants' share of the Tangible Costs of
                    an additional well or wells to be drilled on the Additional
                    Well Locations; or

               (b)  any cost overruns owed by the Developer to Operator for the
                    Developer's Participants' share of the Tangible Costs of one
                    or more of the other wells on the Well Locations.

          (iii) The Developer's Participants' share of the Tangible Costs of all
                of the wells drilled under this Agreement and any additional
                wells to be drilled on the Additional Well Locations under any
                Addendum to this Agreement shall be ten percent (10%) of the
                total price prepaid by Developer to Operator pursuant to Section
                4(b) of this Agreement or any Addendum hereto. The Developer's
                Participants' share of the Tangible Costs of any one well
                drilled under this Agreement shall be determined subject to the
                preceding sentence, taking into account the Developer's share of
                all of the Tangible Costs of all of the wells to be drilled
                under this Agreement and any Addendum hereto.

          The Exhibits to this Agreement with respect to the affected wells
          shall be amended as appropriate.

5.   TITLE EXAMINATION OF WELL LOCATIONS, DEVELOPER'S ACCEPTANCE AND LIABILITY;
     ADDITIONAL WELL LOCATIONS.

     (a)  TITLE EXAMINATION OF WELL LOCATIONS, DEVELOPER'S ACCEPTANCE AND
          LIABILITY. The Developer acknowledges that Operator has furnished
          Developer with the title opinions identified on Exhibit A, and other
          documents and information that Developer or its counsel has requested
          in order to determine the adequacy of the title to the Initial Well
          Locations and leased premises subject to this Agreement. The Developer
          accepts the title to the Initial Well Locations and leased premises
          and acknowledges and agrees that, except for any loss, expense, cost,
          or liability caused by the breach of any of the warranties and
          representations made by the Operator in Section l(b), any loss,
          expense, cost or liability whatsoever caused by or related to any
          defect or failure of the title shall be the sole responsibility of and
          shall be borne entirely by the Developer.

     (b)  ADDITIONAL WELL LOCATIONS. Before beginning drilling of any well on
          any Additional Well Location, Operator shall conduct, or cause to be
          conducted, a title examination of the Additional Well Location, in
          order to obtain appropriate abstracts, opinions and certificates and
          other information necessary to determine the adequacy of title to both
          the applicable Lease and the fee title of the lessor to the premises
          covered by the Lease. The results of the title examination and such
          other information as is necessary to determine the adequacy of title
          for drilling purposes shall be submitted to the Developer for its
          review and acceptance. No drilling on the Additional Well Locations
          shall begin until the title has been accepted in writing by the
          Developer. After any title has been accepted by the Developer, any
          loss, expense, cost, or liability whatsoever, caused by or related to
          any defect or failure of the title shall be the sole responsibility of
          and shall be borne entirely by the Developer, unless such loss,
          expense, cost, or liability was caused by the breach of any of the
          warranties and representations made by the Operator in Section l(b).

6.   OPERATIONS SUBSEQUENT TO COMPLETION OF THE WELLS; FEE ADJUSTMENTS;
     EXTRAORDINARY COSTS; PIPELINES; PRICE DETERMINATIONS; PLUGGING AND
     ABANDONMENT.

     (a)  OPERATIONS SUBSEQUENT TO COMPLETION OF THE WELLS. Beginning with the
          month in which a well drilled under this Agreement begins to produce,
          Operator shall be entitled to an operating fee of $362 per month for
          each well being operated under this Agreement, which operating fee
          shall be proportionately reduced, on a well-by-well basis to the
          extent the Developer owns less than 100% of the Working Interest in a
          well. This fee shall be in lieu of any direct charges by Operator for
          its services or the provision by Operator of its equipment for normal
          superintendence and maintenance of the wells and related pipelines and
          facilities.

          The operating fees shall cover all normal, regularly recurring
          operating expenses for the production, delivery and sale of natural
          gas, including without limitation:


                                       8

<PAGE>

          (i)   well tending, routine maintenance and adjustment;

          (ii)  reading meters, recording production, pumping, maintaining
                appropriate books and records;

          (iii) preparing reports to the Developer and government agencies; and

          (iv)  collecting and disbursing revenues.

          The operating fees shall not cover costs and expenses related to the
          following:

          (i)   the production and sale of oil;

          (ii)  the collection and disposal of salt water or other liquids
                produced by the wells;

          (iii) the rebuilding of access roads; and

          (iv)  the purchase of equipment, materials or third party services;

          which, subject to the provisions of sub-section (c) of this Section 6,
          shall be invoiced by Operator to the Developer on a monthly basis, and
          shall be paid by the Developer within ten (10) business days after
          notice from Operator that the additional amounts are due and owing in
          proportion to the share of the Working Interest owned by the Developer
          in the wells.

          Any well that is temporarily abandoned or shut-in continuously for an
          entire calendar month shall not be considered a producing well for
          purposes of determining the number of wells in the month subject to
          the operating fee.

     (b)  FEE ADJUSTMENTS. The monthly operating fee set forth in sub-section
          (a) above may be adjusted by Operator annually, as of the first day of
          January (the "Adjustment Date") of each year, beginning January 1,
          2008. This adjustment, if any, shall not exceed the percentage
          increase in the average weekly earnings of "Crude Petroleum, Natural
          Gas, and Natural Gas Liquids" workers, as published by the U.S.
          Department of Labor, Bureau of Labor Statistics, and shown in
          Employment and Earnings Publication, Monthly Establishment Data, Hours
          and Earning Statistical Table C-2, Index Average Weekly Earnings of
          "Crude Petroleum, Natural Gas, and Natural Gas Liquids" workers, SIC
          Code #131-2, or any successor index thereto, since January l, 2006, in
          the case of the first adjustment, and since the previous Adjustment
          Date, in the case of each subsequent adjustment.

          In addition, the monthly operating fee set forth in sub-section (a)
          above for any given well or wells being operated under this Agreement
          may be increased beyond the annual adjustment described in the prior
          paragraph without advance notice to the Developer, from time-to-time
          to the competitive rate in the area where the well(s) are situated, as
          determined by the Operator in its sole discretion.

     (c)  EXTRAORDINARY COSTS. Without the prior written consent of the
          Developer, pursuant to a written estimate submitted by Operator,
          Operator shall not undertake any single project or incur any
          extraordinary cost with respect to any well being produced under this
          Agreement that is reasonably estimated to result in an expenditure of
          more than $5,000, unless the project or extraordinary cost is
          necessary for the following:

          (i)  to safeguard persons or property; or

          (ii) to protect the well or related facilities in the event of a
               sudden emergency.

          In no event, however, shall the Developer be required to pay for any
          project or extraordinary cost arising from the negligence or
          misconduct of Operator, its agents, servants, employees,
          subcontractors, licensees, or invitees.


                                       9

<PAGE>

          All extraordinary costs incurred and the cost of projects undertaken
          under this section with respect to a well being produced under this
          Agreement shall be billed to the Developer at the invoice cost of
          third-party services performed or materials purchased together with a
          reasonable charge by Operator for any services performed directly by
          it, in proportion to the share of the Working Interest owned by the
          Developer in the wells. Operator shall have the right to require the
          Developer to pay in advance all or a portion of the estimated costs of
          a project undertaken under this section, before undertaking the
          project, in proportion to the share of the Working Interest owned by
          the Developer in the well or wells.

     (d)  PIPELINES. Developer shall have no interest in the pipeline gathering
          system, which gathering system shall remain the sole property of
          Operator or its Affiliates and shall be maintained at their sole cost
          and expense.

     (e)  PRICE DETERMINATIONS. Notwithstanding anything in this Agreement to
          the contrary, the Developer shall pay all costs in proportion to the
          share of the Working Interest owned by the Developer in the wells with
          respect to obtaining price determinations under and otherwise
          complying with the Natural Gas Policy Act of 1978 and the implementing
          state regulations. This responsibility shall include, without
          limitation, preparing, filing, and executing all applications,
          affidavits, interim collection notices, reports and other documents
          necessary or appropriate to obtain price certification, to effect
          sales of natural gas, or otherwise to comply with the Act and the
          implementing state regulations.

          Operator agrees to furnish the information and render the assistance
          as the Developer may reasonably request in order to comply with the
          Act and the implementing state regulations without charge for services
          performed by its employees.

     (f)  PLUGGING AND ABANDONMENT. The Developer shall have the right to direct
          Operator to plug and abandon any well that has been completed under
          this Agreement as a producer. In addition, Operator shall not plug and
          abandon any well that has been drilled and completed as a producer
          under this Agreement before obtaining the written consent of the
          Developer. However, if the Operator determines that any well drilled
          and completed under this Agreement as a producer shall be plugged and
          abandoned in accordance with the generally accepted and customary oil
          and gas field practices and techniques then prevailing in the
          geographic area of the well location, and makes a written request to
          the Developer for authority to plug and abandon the well and the
          Developer fails to respond in writing to the request within forty-five
          (45) days following the date of the request, then the Developer shall
          be deemed to have consented to the plugging and abandonment of the
          well.

          All costs and expenses related to plugging and abandoning wells that
          have been drilled and completed under this Agreement as producing
          wells shall be borne and paid by the Developer in proportion to the
          share of the Working Interest owned by the Developer in the wells.
          Also, at any time after one (1) year from the date each well drilled
          and completed under this Agreement is placed into production, Operator
          shall have the right to deduct each month from the proceeds of the
          sale of the production from the well up to $200, in proportion to the
          share of the Working Interest owned by the Developer in the well, for
          the purpose of establishing a fund to cover the Operator's estimate of
          the Developer's share of the costs of eventually plugging and
          abandoning the well. All of these funds shall be deposited by Operator
          in a separate interest bearing escrow account for the account of the
          Developer, and the total amount so retained and deposited shall not
          exceed Operator's reasonable estimate of Developer's share of the
          costs of eventually plugging and abandoning the well.

7.   BILLING AND PAYMENT PROCEDURE WITH RESPECT TO OPERATION OF WELLS;
     DISBURSEMENTS; SEPARATE ACCOUNT FOR SALE PROCEEDS; RECORDS AND REPORTS;
     ADDITIONAL INFORMATION.

     (a)  BILLING AND PAYMENT PROCEDURE WITH RESPECT TO OPERATION OF WELLS.
          Operator shall promptly and timely pay and discharge on behalf of the
          Developer, in proportion to the share of the Working Interest owned by
          the Developer in the wells, the following:


                                       10

<PAGE>

          (i)  all expenses and liabilities payable and incurred by reason of
               its operation of the wells in accordance with this Agreement,
               such as severance taxes, royalties, overriding royalties,
               operating fees, and pipeline gathering charges; and

          (ii) any third-party invoices received by Operator with respect to the
               Developer's share of the costs and expenses incurred in
               connection with the operation of the wells.

          Operator, however, shall not be required to pay and discharge any of
          the above costs and expenses that are being contested in good faith by
          Operator.

          Operator shall:

          (i)  deduct the foregoing costs and expenses from the Developer's
               share of the proceeds of the oil and/or gas sold from the wells;
               and

          (ii) keep an accurate record of the Developer's account, showing
               expenses incurred and charges and credits made and received with
               respect to each well.

          If the Developer's share of the proceeds of the oil and/or gas sold
          from the wells is insufficient to pay the costs and expenses, then
          Operator shall promptly and timely pay and discharge the costs and
          expenses described above, in proportion to the share of the Working
          Interest owned by the Developer in the wells, and prepare and submit
          an invoice to the Developer each month for those costs and expenses.
          The invoice shall be accompanied by the form of statement specified in
          sub-section (b) below, and shall be paid by the Developer within ten
          (10) business days of its receipt.

     (b)  DISBURSEMENTS. Operator shall disburse to the Developer, on a monthly
          basis, the Developer's share of the proceeds received from the sale of
          oil and/or gas sold from the wells operated under this Agreement,
          less:

          (i)  the amounts charged to the Developer under sub-section (a); and

          (ii) the amount, if any, withheld by Operator for future plugging
               costs pursuant to sub-section (f) of Section 6.

          Each disbursement made and/or invoice submitted to the Developer
          pursuant to sub-section (a) above shall be accompanied by a statement
          from the Operator itemizing with respect to each well:

          (i)   the total production of oil and/or gas since the date of the
                last disbursement or invoice billing period, as the case may be,
                and the Developer's share of the production;

          (ii)  the total proceeds received from any sale of the production, and
                the Developer's share of the proceeds;

          (iii) the costs and expenses deducted from the proceeds and/or being
                billed to the Developer pursuant to sub-section (a) above;

          (iv)  the amount withheld for future plugging costs; and

          (v)   any other information as Developer may reasonably request,
                including without limitation copies of all third-party invoices
                listed on the statement for the period.

     (c)  SEPARATE ACCOUNT FOR SALE PROCEEDS. Operator agrees to deposit all
          proceeds from the sale of oil and/or gas sold from the wells operated
          under this Agreement in a separate checking account maintained by
          Operator. This account shall be used solely for the purpose of
          collecting and disbursing funds constituting proceeds from the sale of
          production under this Agreement.


                                       11

<PAGE>

     (d)  RECORDS AND REPORTS. In addition to the statements required under
          sub-section (b) above, Operator, within seventy-five (75) days after
          the completion of each well drilled, shall furnish the Developer with
          a detailed statement itemizing with respect to the well the total
          costs and charges under Section 4(a) and the Developer's share of the
          costs and charges, and any other information as is necessary to enable
          the Developer:

          (i)  to allocate any extra costs incurred with respect to the well
               between Tangible Costs and Intangible Drilling Costs; and

          (ii) to determine the amount of the investment tax credit or marginal
               well production tax credit, if applicable.

     (e)  ADDITIONAL INFORMATION. Operator shall promptly furnish the Developer
          with any additional information as it may reasonably request,
          including without limitation geological, technical, and financial
          information, in the form as may reasonably be requested, pertaining to
          any phase of the operations and activities governed by this Agreement.
          The Developer and its authorized employees, agents and consultants,
          including independent accountants shall, at Developer's sole cost and
          expense:

          (i)  on at least ten (10) days' written notice to Operator have access
               during normal business hours to all of Operator's records
               pertaining to operations under this Agreement, including without
               limitation, the right to audit the books of account of Operator
               relating to all receipts, costs, charges, expenses and
               disbursements and information regarding the separate account
               required under sub-section (c); and

          (ii) have access, at its sole risk, to any wells drilled by Operator
               under this Agreement at all times to inspect and observe any
               machinery, equipment and operations.

8.   OPERATOR'S LIEN; RIGHT TO COLLECT FROM OIL OR GAS PURCHASER.

     (a)  OPERATOR'S LIEN. To secure the payment of all sums due from Developer
          to Operator under this Agreement, the Developer grants Operator a
          first and preferred lien on and security interest in the following:

          (i)   the Developer's interest in the Leases covered by this
                Agreement;

          (ii)  the Developer's interest in oil and gas produced under this
                Agreement and its share of the proceeds from the sale of the oil
                and gas; and

          (iii) the Developer's interest in materials and equipment under this
                Agreement.

     (b)  RIGHT TO COLLECT FROM OIL OR GAS PURCHASER. If the Developer fails to
          timely pay any amount owing under this Agreement by it to the
          Operator, then Operator, without prejudice to other existing remedies,
          may collect and retain from any purchaser or purchasers of oil or gas
          the Developer's share of the proceeds from the sale of the oil and gas
          until the amount owed by the Developer, plus twelve percent (12%)
          interest on a per annum basis, and any additional costs (including
          without limitation actual attorneys' fees and costs) resulting from
          the delinquency, has been paid. Each purchaser of oil or gas shall be
          entitled to rely on Operator's written statement concerning the amount
          of any default.

9.   SUCCESSORS AND ASSIGNS; TRANSFERS; APPOINTMENT OF AGENT.

     (a)  SUCCESSORS AND ASSIGNS. This Agreement shall be binding on and inure
          to the benefit of the undersigned parties and their respective
          successors and permitted assigns. However, without the prior written
          consent of the Developer, the Operator may not assign, transfer,
          pledge, mortgage, hypothecate, sell or otherwise


                                       12

<PAGE>

          dispose of any of its interest in this Agreement, or any of its rights
          or obligations under this Agreement. Notwithstanding, this consent
          shall not be required in connection with:

          (i)   the assignment of work to be performed for Operator to
                subcontractors, it being understood and agreed, however, that
                any assignment to Operator's subcontractors shall not in any
                manner relieve or release Operator from any of its obligations
                and responsibilities under this Agreement;

          (ii)  any lien, assignment, security interest, pledge or mortgage
                arising under Operator's present or future financing
                arrangements; or

          (iii) the liquidation, merger, consolidation, or other corporate
                reorganization or sale of substantially all of the assets of
                Operator.

          Further, in order to maintain uniformity of ownership in the wells,
          production, equipment, and leasehold interests covered by this
          Agreement, and notwithstanding any other provision of this Agreement
          to the contrary, the Developer shall not, without the prior written
          consent of Operator, sell, assign, transfer, encumber, mortgage or
          otherwise dispose of any of its interest in the wells, production,
          equipment or leasehold interests covered by this Agreement unless the
          disposition encompasses either:

          (i)  the entire interest of the Developer in all wells, production,
               equipment and leasehold interests subject to this Agreement; or

          (ii) an equal undivided interest in all such wells, production,
               equipment, and leasehold interests.

     (b)  TRANSFERS. Subject to the provisions of sub-section (a) above, any
          sale, encumbrance, transfer or other disposition made by the Developer
          of its interests in the wells, production, equipment, and/or leasehold
          interests covered by this Agreement shall be made:

          (i)   expressly subject to this Agreement;

          (ii)  without prejudice to the rights of the Operator; and

          (iii) in accordance with and subject to the provisions of the Leases
                covering the Well Locations.

     (c)  APPOINTMENT OF AGENT. If at any time the interest of the Developer is
          divided among or owned by co-owners, Operator may, in its discretion,
          require the co-owners to appoint a single trustee or agent with full
          authority to do the following:

          (i)   receive notices, reports and distributions of the proceeds from
                production;

          (ii)  approve expenditures;

          (iii) receive billings for and approve and pay all costs, expenses and
                liabilities incurred under this Agreement;

          (iv)  exercise any rights granted to the co-owners under this
                Agreement;

          (v)   grant any approvals or authorizations required or contemplated
                by this Agreement;

          (vi)  sign, execute, certify, acknowledge, file and/or record any
                agreements, contracts, instruments, reports, or documents
                whatsoever in connection with this Agreement or the activities
                contemplated by this Agreement; and

          (vii) deal generally with, and with power to bind, the co-owners with
                respect to all activities and operations contemplated by this
                Agreement.


                                       13

<PAGE>

          However, all the co-owners shall continue to have the right to enter
          into and execute all contracts or agreements for their respective
          shares of the oil and gas produced from the wells drilled under this
          Agreement in accordance with sub-section (c) of Section 11.

10.  OPERATOR'S INSURANCE; SUBCONTRACTORS' INSURANCE; OPERATOR'S LIABILITY.

     (a)  OPERATOR'S INSURANCE. Operator shall obtain and maintain at its own
          expense so long as it is Operator under this Agreement all required
          Workmen's Compensation Insurance and comprehensive general public
          liability insurance in amounts and coverage not less than $1,000,000
          per person per occurrence for personal injury or death and $1,000,000
          for property damage per occurrence, which shall include coverage for
          blow-outs, and total liability coverage of not less than $10,000,000.

          Subject to the above limits, the Operator's general public liability
          insurance shall be in all respects comparable to that generally
          maintained in the industry with respect to services of the type to be
          rendered and activities of the type to be conducted under this
          Agreement. Operator's general public liability insurance shall, if
          permitted by Operator's insurance carrier:

          (i)  name the Developer as an additional insured party; and

          (ii) provide that at least thirty (30) days' prior notice of
               cancellation and any other adverse material change in the policy
               shall be given to the Developer.

          However, the Developer shall reimburse Operator for the additional
          cost, if any, of including it as an additional insured party under the
          Operator's insurance.

          Current copies of all policies or certificates of the Operator's
          insurance coverage shall be delivered to the Developer on request. It
          is understood and agreed that Operator's insurance coverage may not
          adequately protect the interests of the Developer and that the
          Developer shall carry at its expense the excess or additional general
          public liability, property damage, and other insurance, if any, as the
          Developer deems appropriate.

     (b)  SUBCONTRACTORS' INSURANCE. Operator shall require all of its
          subcontractors to carry all required Workmen's Compensation Insurance
          and to maintain such other insurance, if any, as Operator in its
          discretion may require.

     (c)  OPERATOR'S LIABILITY. Operator's liability to the Developer as
          Operator under this Agreement shall be limited to, and Operator shall
          indemnify the Developer and hold it harmless from, claims, penalties,
          liabilities, obligations, charges, losses, costs, damages, or expenses
          (including but not limited to reasonable attorneys' fees) relating to,
          caused by or arising out of:

          (i)   the noncompliance with or violation by Operator, its employees,
                agents, or subcontractors of any local, state or federal law,
                statute, regulation, or ordinance;

          (ii)  the negligence or misconduct of Operator, its employees, agents
                or subcontractors; or

          (iii) the breach of or failure to comply with any provisions of this
                Agreement.

11.  INTERNAL REVENUE CODE ELECTION; RELATIONSHIP OF PARTIES; RIGHT TO TAKE
     PRODUCTION IN KIND.

     (a)  INTERNAL REVENUE CODE ELECTION. With respect to this Agreement, each
          of the parties elects under Section 761(a) of the Internal Revenue
          Code of 1986, as amended, to be excluded from the provisions of
          Subchapter K of Chapter 1 of Subtitle A of the Internal Revenue Code
          of 1986, as amended. If the income tax laws of the state or states in
          which the property covered by this Agreement is located contain, or
          may subsequently contain, a similar election, each of the parties
          agrees that the election shall be exercised.


                                       14

<PAGE>

          Beginning with the first taxable year of operations under this
          Agreement, each party agrees that the deemed election provided by
          Section 1.761-2(b)(2)(ii) of the Regulations under the Internal
          Revenue Code of 1986, as amended, will apply; and no party will file
          an application under Section 1.761-2 (b)(3)(i) of the Regulations to
          revoke the election. Each party agrees to execute the documents and
          make the filings with the appropriate governmental authorities as may
          be necessary to effect the election.

     (b)  RELATIONSHIP OF PARTIES. It is not the intention of the parties to
          create, nor shall this Agreement be construed as creating, a mining or
          other partnership or association or to render the parties liable as
          partners or joint venturers for any purpose. Operator shall be deemed
          to be an independent contractor and shall perform its obligations as
          set forth in this Agreement.

     (c)  RIGHT TO TAKE PRODUCTION IN KIND. Subject to the provisions of Section
          8 above, the Developer shall have the exclusive right to sell or
          dispose of its proportionate share of all oil and gas produced from
          the wells to be drilled under this Agreement, exclusive of production:

          (i)   that may be used in development and producing operations;

          (ii)  unavoidably lost; and

          (iii) used to fulfill any free gas obligations under the terms of the
                applicable Lease or Leases.

          Operator shall not have any right to sell or otherwise dispose of the
          oil and gas. The Developer shall have the exclusive right to execute
          all contracts relating to the sale or disposition of its proportionate
          share of the production from the wells drilled under this Agreement.

          Developer shall have no interest in any gas supply agreements of
          Operator, except the right to receive Developer's share of the
          proceeds received from the sale of any gas or oil from wells developed
          under this Agreement. The Developer agrees to designate Operator or
          Operator's designated bank agent as the Developer's collection agent
          in any contracts. On request, Operator shall assist Developer in
          arranging the sale or disposition of Developer's oil and gas under
          this Agreement and shall promptly provide the Developer with all
          relevant information that comes to Operator's attention regarding
          opportunities for selling production.

          If Developer fails to take in kind or separately dispose of its
          proportionate share of the oil and gas produced under this Agreement,
          then Operator shall have the right, subject to the revocation at will
          by the Developer, but not the obligation, to purchase the oil and gas
          or sell it to others at any time and from time to time, for the
          account of the Developer at the best price obtainable in the area for
          the production. Notwithstanding, Operator shall have no liability to
          Developer should Operator fail to market the production.

          Any such purchase or sale by Operator shall be subject always to the
          right of the Developer to exercise at any time its right to take
          in-kind, or separately dispose of, its share of oil and gas not
          previously delivered to a purchaser. Any purchase or sale by Operator
          of the Developer's share of oil and gas under this Agreement shall be
          only for reasonable periods of time as are consistent with the minimum
          needs of the oil and gas industry under the particular circumstances,
          but in no event for a period in excess of one (1) year.

12.  EFFECT OF FORCE MAJEURE; DEFINITION OF FORCE MAJEURE; LIMITATION.

     (a)  EFFECT OF FORCE MAJEURE. If Operator is rendered unable, wholly or in
          part, by force majeure (as defined below) to carry out any of its
          obligations under this Agreement, including but not limited to
          beginning the drilling of one or more wells by the applicable times
          set forth in Section 2(b), or any Addendum to this Agreement, the
          obligations of the Operator, so far as it is affected by the force
          majeure, shall be suspended during but no longer than, the continuance
          of the force majeure. The Operator shall give to the Developer prompt
          written notice of the force majeure with reasonably full particulars


                                       15

<PAGE>

          concerning it. Operator shall use all reasonable diligence to remove
          the force majeure as quickly as possible to the extent the same is
          within its reasonable control.

     (b)  DEFINITION OF FORCE MAJEURE. The term "force majeure" shall mean an
          act of God, strike, lockout, or other industrial disturbance, act of
          the public enemy, war, terrorist acts, blockade, public riot,
          lightning, fire, storm, flood, explosion, governmental restraint,
          unavailability of drilling rigs, equipment or materials, plant
          shut-downs, curtailments by oil and gas purchasers and any other
          causes whether of the kind specifically enumerated above or otherwise,
          which directly preclude Operator's performance under this Agreement
          and is not reasonably within the control of the Operator including,
          but not limited to, the inability of Operator to begin the drilling of
          the wells subject to this Agreement by the applicable times set forth
          in Section 2(b) or in any Addendum to this Agreement due to decisions
          of third-party operators to delay drilling the wells, poor weather
          conditions, inability to obtain drilling permits, access right to the
          drilling site or title problems.

     (c)  LIMITATION. The requirement that any force majeure shall be remedied
          with all reasonable dispatch shall not require the settlement of
          strikes, lockouts, or other labor difficulty affecting the Operator
          contrary to its wishes. The method of handling these difficulties
          shall be entirely within the discretion of the Operator.

13.  TERM.

     This Agreement shall become effective when executed by Operator and the
     Developer. Except as provided in sub-section (c) of Section 3, this
     Agreement shall continue and remain in full force and effect for the
     productive lives of each wells being operated under this Agreement.

14.  GOVERNING LAW; INVALIDITY.

     (a)  GOVERNING LAW. This Agreement shall be governed by, construed and
          interpreted in accordance with the laws of the Commonwealth of
          Pennsylvania, excluding its conflict of law provisions.

     (b)  INVALIDITY. The invalidity or unenforceability of any particular
          provision of this Agreement shall not affect the other provisions of
          this Agreement, and this Agreement shall be construed in all respects
          as if the invalid or unenforceable provision were omitted.

15.  INTEGRATION; WRITTEN AMENDMENT.

     (a)  INTEGRATION. This Agreement, including the Exhibits to this Agreement,
          constitutes and represents the entire understanding and agreement of
          the parties with respect to the subject matter of this Agreement and
          supersedes all prior negotiations, understandings, agreements, and
          representations relating to the subject matter of this Agreement.

     (b)  WRITTEN AMENDMENT. No change, waiver, modification, or amendment of
          this Agreement shall be binding or of any effect unless in writing
          duly signed by the party against which the change, waiver,
          modification, or amendment is sought to be enforced.

16.  WAIVER OF DEFAULT OR BREACH.

     No waiver by any party to any default of or breach by any other party under
     this Agreement shall operate as a waiver of any future default or breach,
     whether of like or different character or nature.

17.  NOTICES.

     Unless otherwise provided in this Agreement, all notices, statements,
     requests, or demands that are required or contemplated by this Agreement
     shall be in writing and shall be hand-delivered or sent by registered or
     certified mail, postage prepaid, to the following addresses until a party's
     address is changed by certified or registered letter so addressed to the
     other party:


                                       16

<PAGE>

     (i)  If to the Operator, to:
          Atlas Resources, LLC
          311 Rouser Road
          Moon Township, Pennsylvania 15108
          Attention: President

     (ii) If to Developer, to:
          Atlas America Public #16-2007(A) L.P.
          [Atlas America Public #16-2007(B) L.P.]
          c/o Atlas Resources, LLC
          311 Rouser Road
          Moon Township, Pennsylvania 15108

     Notices that are served by registered or certified mail on the parties in
     the manner provided above shall be deemed sufficiently served or given for
     all purposes under this Agreement at the time the notice is hand-delivered
     or mailed in any post office or branch post office regularly maintained by
     the United States Postal Service or any successor. All payments shall be
     hand-delivered or sent by United States mail, postage prepaid to the
     addresses set forth above until a party's address is changed by certified
     or registered letter so addressed to the other party.

18.  INTERPRETATION.

     The titles of the Sections in this Agreement are for convenience of
     reference only and shall not control or affect the meaning or construction
     of any of the terms and provisions of this Agreement. As used in this
     Agreement, the plural shall include the singular and the singular shall
     include the plural whenever appropriate.

19.  COUNTERPARTS.

     The parties may execute this Agreement in any number of separate
     counterparts, each of which, when executed and delivered by the parties,
     shall have the force and effect of an original; but all counterparts of
     this Agreement shall be deemed to constitute one and the same instrument.

     IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement as
of the day and year first above written.


                                  ATLAS RESOURCES, LLC


                                  By:
                                      ------------------------------------------
                                      Frank P. Carolas, Executive Vice President


                                   ATLAS AMERICA PUBLIC #16-2007(A) L.P.
                                   [ATLAS AMERICA PUBLIC #16-2007(B) L.P.]


                                  By its Managing General Partner:
                                  ATLAS RESOURCES, LLC


                                  By:
                                      ------------------------------------------
                                      Frank P. Carolas, Executive Vice President


                                       17

<PAGE>

                DESCRIPTION OF LEASES AND INITIAL WELL LOCATIONS
               [To be completed as information becomes available]

1.   WELL LOCATION

     (a)  Oil and Gas Lease from ______________________________________ dated
          _____________________ and recorded in Deed Book Volume __________,
          Page __________ in the Recorder's Office of County, ____________,
          covering approximately _________ acres in ____________________________
          Township, ___________________ County, ______________________.

     (b)  The portion of the leasehold estate constituting the
          ____________________________________________ No. __________ Well
          Location is described on the map attached hereto as Exhibit A-l.

     (c)  Title Opinion of _________________________________,
          ____________________________________, _______________________________,
          ________________________________________, dated ___________________,
          200___.

     (d)  The Developer's interest in the leasehold estate constituting this
          Well Location is an undivided % Working Interest to those oil and gas
          rights from the surface to the deepest depth penetrated at the
          cessation of drilling activities (which is ___________ feet), subject
          to the landowner's royalty interest and overriding royalty interests.


                                    Exhibit A

<PAGE>

                                                                 Well Name, Twp.
                                                                   County, State

ASSIGNMENT OF OIL AND GAS LEASE

STATE OF _______________________________

COUNTY OF ___________________________

KNOW ALL MEN BY THESE PRESENTS:

     THAT the undersigned_______________________________________________________
(hereinafter called "Assignor"), for and in consideration of One Dollar and
other valuable consideration ($1.00 ovc), the receipt whereof is hereby
acknowledged, does hereby sell, assign, transfer and set over unto______________
________________________________(hereinafter called "Assignee"), an undivided
 _____________________________ in, and to, the oil and
gas lease described as follows:

together with the rights incident thereto and the personal property thereto,
appurtenant thereto, or used, or obtained, in connection therewith.

     And for the same consideration, the assignor covenants with the said
assignee and his or its heirs, successors, or assigns that assignor is the
lawful owner of said lease and rights and interest thereunder and of the
personal property thereon or used in connection therewith; that the undersigned
has good right and authority to sell and convey the same; and that said rights,
interest and property are free and clear from all liens and encumbrances, and
that all rentals and royalties due and payable thereunder have been duly paid.

     In Witness Whereof, the undersigned owner ______ and assignor ______ ha___
signed and sealed this instrument the ______ day of _______________, 200___.


Signed and acknowledged in the
presence of                             ----------------------------------------

-------------------------------------   ----------------------------------------

-------------------------------------   ----------------------------------------


                                    Exhibit B
                                    (Page 1)

<PAGE>

                          ACKNOWLEDGMENT BY INDIVIDUAL

STATE OF ___

                                     BEFORE ME, a Notary Public, in and for said

COUNTY OF _________________________

     County and State, on this day personally appeared who acknowledged to me
that ____ he ____ did sign the foregoing instrument and that the same is
_____________ free act and deed.

     In testimony whereof, I have hereunto set my hand and official seal, at
_____________________________, this ______ day of _______________, A.D., 200_.


                                               _________________________________
                                               Notary Public

                           CORPORATION ACKNOWLEDGMENT

STATE OF _________________________

                                     BEFORE ME, a Notary Public, in and for said

COUNTY OF ________________________

     County and State, on this day personally appeared known to me to be the
person and officer whose name is subscribed to the foregoing instrument and
acknowledged that the same was the act of the said
______________________________________________, a corporation, and that he
executed the same as the act of such corporation for the purposes and
consideration therein expressed, and in the capacity therein stated.

     In testimony whereof, I have hereunto set my hand and official seal, at
_____________________________, this ______ day of _______________, A.D., 200_.


                                               _________________________________
                                               Notary Public

This instrument was prepared by:

Atlas Resources, LLC
311 Rouser Road
P.O. Box 611
Moon Township, PA 15108


                                    Exhibit B
                                    (Page 2)

<PAGE>

                             ADDENDUM NO. __________

                       TO DRILLING AND OPERATING AGREEMENT

                       DATED ___________________,  200_

THIS ADDENDUM NO. __________ made and entered into this ______ day of
________________, 200_, by and between ATLAS RESOURCES, LLC, a Pennsylvania
limited liability company (hereinafter referred to as "Operator"),

                                       and

ATLAS AMERICA PUBLIC #16-2007(A) L.P. [ATLAS AMERICA PUBLIC #16-2007(B) L.P.], a
Delaware limited partnership, (hereinafter referred to as the Developer).

                                WITNESSETH THAT:

WHEREAS, Operator and the Developer have entered into a Drilling and Operating
Agreement dated ___________________, 200_, (the "Agreement"), which relates to
the drilling and operating of ________________ (______)wells on the
________________ (______) Initial Well Locations identified on the maps attached
as Exhibits A-l through A-______ to the Agreement, and provides for the
development on the terms and conditions set forth in the Agreement of Additional
Well Locations as the parties may from time to time designate; and

WHEREAS, pursuant to Section l(c) of the Agreement, Operator and Developer
presently desire to designate ________________ Additional Well Locations
described below to be developed in accordance with the terms and conditions of
the Agreement.

NOW, THEREFORE, in consideration of the mutual covenants contained in this
Addendum and intending to be legally bound, the parties agree as follows:

1. Pursuant to Section l(c) of the Agreement, the Developer hereby authorizes
Operator to drill, complete (or plug) and operate, on the terms and conditions
set forth in the Agreement and this Addendum No.__________, ________________
additional wells on the ________________ Additional Well Locations described on
Exhibit A to this Addendum and on the maps attached to this Addendum as Exhibits
A-______ through A-______.

2. Operator, as Developer's independent contractor, agrees to drill, complete
(or plug) and operate the additional wells on the Additional Well Locations in
accordance with the terms and conditions of the Agreement and further agrees to
begin drilling the first additional well within thirty (30) days after the date
of this Addendum and to begin drilling all of the additional wells before the
close of the 90th day after the close of the calendar year in which the
Agreement was entered into by Operator and the Developer, or, if this Addendum
is dated after that 90 day period, to begin drilling the first additional well
within thirty (30) days after the date of this Addendum and to drill and
complete (or plug) all of the remaining additional wells by the end of the
calendar year in which this Addendum is dated.

3. Developer acknowledges that:

     (a)  Operator has furnished Developer with the title opinions identified on
          Exhibit A to this Addendum; and

     (b)  such other documents and information which Developer or its counsel
          has requested in order to determine the adequacy of the title to the
          above Additional Well Locations.

The Developer accepts the title to the Additional Well Locations and leased
premises in accordance with the provisions of Section 5 of the Agreement.

4. The drilling and operation of the additional wells on the Additional Well
Locations shall be in accordance with and subject to the terms and conditions
set forth in the Agreement as supplemented by this Addendum No. __________ and
except as previously supplemented, all terms and conditions of the Agreement
shall remain in full force and effect as originally written.


                                    Exhibit C
                                    (Page 1)

<PAGE>

5. This Addendum No. __________ shall be legally binding on, and shall inure to
the benefit of, the parties and their respective successors and permitted
assigns.

WITNESS the due execution of this Addendum on the day and year first above
written.

                                        ATLAS RESOURCES, LLC


                                        By
                                           -------------------------------------

                                        ATLAS AMERICA PUBLIC #16-2007(A) L.P.
                                        [ATLAS AMERICA PUBLIC #16-2007(B) L.P.]


                                        By its Managing General Partner:

                                        ATLAS RESOURCES, LLC


                                        By
                                           -------------------------------------


                                    Exhibit C
                                    (Page 2)

<PAGE>

                                   EXHIBIT (B)
                        SPECIAL SUITABILITY REQUIREMENTS
                          AND DISCLOSURES TO INVESTORS

<PAGE>

          SPECIAL SUITABILITY REQUIREMENTS AND DISCLOSURES TO INVESTORS

If you are a resident of one of the following states, then you must meet that
state's qualification and suitability standards as set forth below.

    SPECIAL SUITABILITY REQUIREMENTS IF YOU ARE BUYING LIMITED PARTNER UNITS.

I.   If you are a resident of CALIFORNIA or NEW JERSEY and you purchase limited
     partners units, then you must meet any one of the following special
     suitability requirements:

          o    a net worth of not less than $250,000, exclusive of home, home
               furnishings and automobiles, and expect to have gross income in
               the current year of $65,000 or more; or

          o    a net worth of not less than $500,000, exclusive of home, home
               furnishings and automobiles; or

          o    a net worth of not less than $1 million; or

          o    expected gross income in the current tax year of not less than
               $200,000.

II.  If you are a resident of MICHIGAN OR NORTH CAROLINA and you purchase
     limited partner units, then you must meet either one of the following
     special suitability requirements:

          o    a net worth of not less than $225,000, exclusive of home, home
               furnishings and automobiles; or

          o    a net worth of not less than $60,000, exclusive of home, home
               furnishings and automobiles, and estimated CURRENT year taxable
               income as defined in Section 63 of the Internal Revenue Code of
               $60,000 or more without regard to an investment in the
               partnership.

     In addition, if you are a resident of MICHIGAN, then you must not make an
     investment in the partnership in excess of 10% of your net worth, exclusive
     of home, home furnishings and automobiles.

III. If you are a resident of NEW HAMPSHIRE and you purchase limited partner
     units, then you must meet either one of the following special suitability
     requirements:

          o    a net worth of not less than $250,000, exclusive of home, home
               furnishings, and automobiles, or

          o    a net worth of not less than $125,000, exclusive of home, home
               furnishings, and automobiles, and $50,000 of taxable income.

IV.  If you are a resident of OHIO and you subscribe for limited partner units,
     then you must meet, without regard to your investment in a partnership,
     either of the following special suitability requirements:

          o    a net worth of not less than $330,000, exclusive of home, home
               furnishings, and automobiles; or

          o    a net worth of not less than $85,000, exclusive of home, home
               furnishings, and automobiles, and an annual gross income during
               the current tax year of at least $85,000.

     Additionally, if you are a resident of OHIO you must not make an investment
     in a partnership which would, after including your previous investments in
     prior Atlas Resources programs, if any, and any other similar natural gas
     and oil drilling programs, exceed 10% of your net worth, exclusive of home,
     home furnishings and automobiles.

           SPECIAL SUITABILITY REQUIREMENTS IF YOU ARE BUYING INVESTOR
                             GENERAL PARTNER UNITS.

I.   If you are a resident of CALIFORNIA or NEW JERSEY and you purchase investor
     general partner units, then you must meet any one of the following special
     suitability requirements:


                                       1

<PAGE>

          o    an individual or joint net worth with your spouse of not less
               than $250,000, exclusive of home, home furnishings and
               automobiles, and expect to have annual gross income in the
               current year of $120,000 or more; or

          o    an individual or joint net worth with your spouse of not less
               than $500,000, exclusive of home, home furnishings and
               automobiles; or

          o    an individual or joint net worth with your spouse of not less
               than $1 million; or

          o    a combined expected gross income in the current year of not less
               than $200,000.

II. If you are a resident of any of the following states:

          o    ALABAMA;

          o    ARKANSAS;

          o    INDIANA;

          o    MAINE;

          o    MASSACHUSETTS;

          o    MINNESOTA;

          o    NORTH CAROLINA;

          o    OKLAHOMA;

          o    PENNSYLVANIA;

          o    TENNESSEE;

          o    TEXAS; OR

          o    WASHINGTON.

and you purchase investor general partner units, then you must meet any one of
the following special suitability requirements:

          o    an individual or joint net worth with your spouse of $225,000 or
               more, without regard to the investment in the partnership,
               exclusive of home, home furnishings and automobiles, and A
               COMBINED GROSS INCOME OF $100,000 OR MORE FOR THE CURRENT YEAR
               AND FOR THE TWO PREVIOUS YEARS; or

          o    an individual or joint net worth with your spouse in excess of $1
               million, inclusive of home, home furnishings and automobiles; or

          o    an individual or joint net worth with your spouse in excess of
               $500,000, exclusive of home, home furnishings and automobiles; or

          o    a combined "gross income" as defined in Section 61 of the
               Internal Revenue Code of 1986, as amended, in excess of $200,000
               in the current year and the two previous years.

III. If you are a resident of any of the following states:

          o    ARIZONA;

          o    IOWA;

          o    KANSAS;

          o    KENTUCKY;

          o    MICHIGAN;

          o    MISSISSIPPI;

          o    MISSOURI;

          o    NEW MEXICO;

          o    OREGON;

          o    SOUTH DAKOTA; OR

          o    VERMONT;

     and you purchase investor general partner units, then you must meet any one
     of the following special suitability requirements:

          o    an individual or joint net worth with your spouse of $225,000 or
               more, without regard to the investment in the partnership,
               exclusive of home, home furnishings and automobiles, AND A
               COMBINED "TAXABLE INCOME" OF $60,000 OR MORE FOR THE PREVIOUS
               YEAR AND EXPECT TO HAVE A COMBINED "TAXABLE INCOME" OF $60,000 OR
               MORE FOR THE CURRENT YEAR AND FOR THE SUCCEEDING YEAR; or


                                       2

<PAGE>

          o    an individual or joint net worth with your spouse in excess of $1
               million, inclusive of home, home furnishings and automobiles; or

          o    an individual or joint net worth with your spouse in excess of
               $500,000, exclusive of home, home furnishings and automobiles; or

          o    a combined "gross income" as defined in Section 61 of the
               Internal Revenue Code of 1986, as amended, in excess of $200,000
               in the current year and the two previous years.

IV. In addition, if you are a resident of any of the following states:

          o    IOWA;

          o    MICHIGAN; OR

          o    PENNSYLVANIA;

     then you must not make an investment in the partnership in excess of 10% of
     your net worth, exclusive of home, furnishings and automobiles.

     Also, if you are a resident of KANSAS, it is recommended by the Office of
     the Kansas Securities Commissioner that you should limit your investment in
     the program and substantially similar programs to no more than 10% of your
     net worth, excluding home, furnishings and automobiles.

V.   If you are a resident of NEW HAMPSHIRE and you purchase investor general
     partner units, then you must meet either one of the following special
     suitability requirements:

          o    an individual or joint net worth with your spouse of not less
               than $250,000, exclusive of home, home furnishings, and
               automobiles, or

          o    an individual or joint net worth with your spouse of not less
               than $125,000, exclusive of home, home furnishings, and
               automobiles, and $50,000 of taxable income.

VI.  If you are a resident of OHIO and you subscribe for investor general
     partner units, then you must meet, without regard to your investment in a
     partnership, either of the following special suitability requirements:

          o    an individual or joint net worth with your spouse of not less
               than $750,000, exclusive of home, home furnishings, and
               automobiles; or

          o    an individual or joint net worth with your spouse of not less
               than $330,000, exclusive of home, home furnishings, and
               automobiles, and an annual gross income of at least $150,000 for
               the current year and the two previous years.

     Additionally, if you are a resident of OHIO you must not make an investment
     in a partnership which would, after including your previous investments in
     prior Atlas Resources programs, if any, and any other similar natural gas
     and oil drilling programs, exceed 10% of your net worth, exclusive of home,
     home furnishings and automobiles.

                   SPECIAL REPRESENTATIONS OF SUBSCRIBERS IN
               CALIFORNIA, IOWA, NORTH CAROLINA AND PENNSYLVANIA.

I. If a resident of CALIFORNIA, I am aware that:

               IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY,
               OR ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION
               THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER
               OF


                                       3

<PAGE>

               CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN
               THE COMMISSIONER'S RULES.

As a condition of qualification of the units for sale in the State of
California, the following rule is hereby delivered to each California purchaser.

CALIFORNIA ADMINISTRATIVE CODE, TITLE 10, CH. 3, RULE 260.141.11. RESTRICTION ON
TRANSFER.

     (a)  The issuer of any security upon which a restriction on transfer has
          been imposed pursuant to Section 260.141.10 or 260.534 shall cause a
          copy of this section to be delivered to each issuee or transferee of
          such security at the time the certificate evidencing the security is
          delivered to the issuee or transferee.

     (b)  It is unlawful for the holder of any such security to consummate a
          sale or transfer of such security, or any interest therein, without
          the prior written consent of the Commissioner (until this condition is
          removed pursuant to Section 260.141.12 of these rules), except:

          (i)    to the issuer;

          (ii)   pursuant to the order or process of any court;

          (iii)  to any person described in Subdivision (i) of Section 25102 of
                 the Code or Section 260.105.14 of these rules;

          (iv)   to the transferor's ancestors, descendants or spouse, or any
                 custodian or trustee for the account of the transferor or the
                 transferor's ancestors, descendants or spouse, or to a
                 transferee by a trustee or custodian for the account of the
                 transferee or the transferee's ancestors, descendants or
                 spouse;

          (v)    to holders of securities of the same class of the same issuer;

          (vi)   by way of gift or donation inter vivos or on death;

          (vii)  by or through a broker-dealer licensed under the Code (either
                 acting as such or as a finder) to a resident of a foreign
                 state, territory or country who is neither domiciled in this
                 state to the knowledge of the broker-dealer, nor actually
                 present in this state if the sale of such securities is not in
                 violation of any securities law of the foreign state, territory
                 or country concerned;

          (viii) to a broker-dealer licensed under the Code in a principal
                 transaction, or as an underwriter or member of an underwriting
                 syndicate or selling group;

          (ix)   if the interest sold or transferred is a pledge or other lien
                 given by the purchaser to the seller upon a sale of the
                 security for which the Commissioner's written consent is
                 obtained or under this rule not required;

          (x)    by way of a sale qualified under Sections 25111, 25112, 25113
                 or 25121 of the Code, of the securities to be transferred,
                 provided that no order under Section 25140 or Subdivision (a)
                 of Section 25143 is in effect with respect to such
                 qualification;

          (xi)   by a corporation to a wholly-owned subsidiary of such
                 corporation, or by a wholly-owned subsidiary of a corporation
                 to such corporation;

          (xii)  by way of an exchange qualified under Section 25111, 25112 or
                 25113 of the Code, provided that no order under Section 25140
                 or Subdivision (a) of Section 25143 is in effect with respect
                 to such qualification;


                                       4

<PAGE>

          (xiii) between residents of foreign states, territories or countries
                 who are neither domiciled nor actually present in this state;

          (xiv)  to the State Controller pursuant to the Unclaimed Property Law
                 or to the administrator of the unclaimed property law of
                 another state;

          (xv)   by the State Controller pursuant to the Unclaimed Property Law
                 or by the administrator of the unclaimed property law of
                 another state if, in either such case, such person (i)
                 discloses to potential purchasers at the sale that transfer of
                 the securities is restricted under this rule, (ii) delivers to
                 each purchaser a copy of this rule, and (iii) advises the
                 Commissioner of the name of each purchaser;

          (xvi)  by a trustee to a successor trustee when such transfer does not
                 involve a change in the beneficial ownership of the securities;

          (xvii) by way of an offer and sale of outstanding securities in an
                 issuer transaction that is subject to the qualification
                 requirement of Section 25110 of the Code but exempt from that
                 qualification requirement by subdivision (f) of Section 25102;

          provided that any such transfer is on the condition that any
          certificate evidencing the security issued to such transferee shall
          contain the legend required by this section.

     (c)  The certificates representing all such securities subject to such a
          restriction on transfer, whether upon initial issuance or upon any
          transfer thereof, shall bear on their face a legend, prominently
          stamped or printed thereon in capital letters of not less than
          10-point size, reading as follows:

          "IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY, OR
          ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFOR,
          WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER OF CORPORATIONS
          OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE COMMISSIONER'S
          RULES."

II. If a resident of IOWA or NORTH CAROLINA, I am aware that:

          IN MAKING AN INVESTMENT DECISION INVESTORS MUST RELY ON THEIR OWN
          EXAMINATION OF THE PERSON OR ENTITY CREATING THE SECURITIES AND THE
          TERMS OF THE OFFERING, INCLUDING THE MERITS AND RISKS INVOLVED. THESE
          SECURITIES HAVE NOT BEEN RECOMMENDED BY ANY FEDERAL OR STATE
          SECURITIES COMMISSION OR REGULATORY AUTHORITY. FURTHERMORE, THE
          FOREGOING AUTHORITIES HAVE NOT CONFIRMED THE ACCURACY OR DETERMINED
          THE ADEQUACY OF THIS DOCUMENT. ANY REPRESENTATION TO THE CONTRARY IS A
          CRIMINAL OFFENSE.

III. PENNSYLVANIA INVESTORS: Because the minimum closing amount is less than 10%
     of the maximum closing amount allowed to a partnership in this offering,
     you are cautioned to carefully evaluate the partnership's ability to fully
     accomplish its stated objectives and inquire as to the current dollar
     volume of partnership subscriptions.


                                       5

<PAGE>

                                TABLE OF CONTENTS

                                                                            Page
                                                                            ----
Summary of the Offering..................................................      1
Risk Factors.............................................................      8
Additional Information...................................................     21
Forward Looking Statements and Associated Risks..........................     21
Investment Objectives....................................................     22
Actions to be Taken by Managing General Partner to Reduce Risks of
   Additional Payments by Investor General Partners......................     24
Capitalization and Source of Funds and Use of Proceeds...................     26
Compensation.............................................................     29
Terms of the Offering....................................................     37
Prior Activities.........................................................     44
Management...............................................................     55
Management's Discussion and Analysis of Financial Condition, Results
   of Operations, Liquidity and Capital Resources........................     63
Proposed Activities......................................................     65
Competition, Markets and Regulation......................................     80
Participation in Costs and Revenues......................................     84
Conflicts of Interest....................................................     91
Fiduciary Responsibility of the Managing General Partner.................    103
Federal Income Tax Consequences..........................................    104
Summary of Partnership Agreement.........................................    135
Summary of Drilling and Operating Agreement..............................    137
Reports to Investors.....................................................    138
Presentment Feature......................................................    139
Transferability of Units.................................................    141
Plan of Distribution.....................................................    142
Sales Material...........................................................    144
Legal Opinions...........................................................    145
Experts..................................................................    145
Litigation...............................................................    145
Financial Information Concerning the Managing General Partner and
   Atlas America Public #16-2007(A) L.P..................................    146
Index to Financial Statements............................................    146

EXHIBIT (A) - Form of Amended and Restated Certificate and Agreement of
     Limited Partnership for Atlas America Public #16-2007(A) L.P. [Form
     of Amended and Restated Certificate and Agreement of Limited
     Partnership for Atlas America Public #16-2007(B) L.P.]

EXHIBIT (I-A) - Form of Managing General Partner Signature Page

EXHIBIT (I-B) - Form of Subscription Agreement

EXHIBIT (II) - Form of Drilling and Operating Agreement for Atlas America
     Public #16-2007(A) L.P. [Atlas America Public #16-2007(B) L.P.]

EXHIBIT (B) - Special Suitability Requirements and Disclosures to
     Investors

No one has been authorized to give any information or make any representations
other than those contained in this prospectus in connection with this offering.
If given or made, you should not rely on such information or representations as
having been authorized by the managing general partner. The delivery of this
prospectus does not imply that its information is correct as of any time after
its date. This prospectus is not an offer to sell these securities in any state
to any person where the offer and sale is not permitted.

                                  ATLAS AMERICA

                             PUBLIC #16-2007 PROGRAM

                                   ----------

                                   PROSPECTUS

                                   ----------

Until December 31, 2007, all dealers that effect transactions in these
securities, whether or not participating in this offering, may be required to
deliver a prospectus. This is in addition to the dealers' obligation to deliver
a prospectus when acting as underwriters and with respect to their unsold
allotments or subscriptions.

<PAGE>

                                     PART II

                     INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

The expenses to be incurred in connection with the issuance and distribution of
the securities to be registered, other than underwriting discounts, commissions
and expense allowances, are estimated to be as follows:

Accounting Fees and Expenses ...................   $   40,000*
Legal Fees (including Blue Sky) and Expenses ...      360,000*
Printing .......................................      300,000*
SEC Registration Fee ...........................       21,400
Blue Sky Filing Fees (excluding legal fees) ....      165,265*
NASD Filing Fee ................................       20,500
Miscellaneous ..................................      566,837*
                                                   ----------
   Total .......................................   $1,474,002*
                                                   ==========

----------
*    Estimated

ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

Title 15, Section 8945 of the Pennsylvania Consolidated Statutes provides for
indemnification of members and managers by a limited liability company subject
to certain limitations.

Under Section 4.05 of the Amended and Restated Certificate and Agreement of
Limited Partnership, the Participants, within the limits of their Capital
Contributions, and the Partnership, generally agree to indemnify and exonerate
the Managing General Partner, the Operator and their Affiliates from claims of
liability to any third party arising out of operations of the Partnership
provided that:

     o    they determined in good faith that the course of conduct which caused
          the loss or liability was in the best interest of the Partnership;

     o    they were acting on behalf of or performing services for the
          Partnership; and

     o    the course of conduct was not the result of their negligence or
          misconduct.

Section 11 of the Dealer-Manager Agreement provides for the indemnification of
the Managing General Partner, the Partnership and control persons under
specified conditions by the Dealer-Manager and/or Selling Agent.

ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.

None by the Registrant.

Atlas Resources, LLC ("Atlas"), an Affiliate of the Registrant, has made sales
of unregistered and registered securities within the last three years. See the
section of the Prospectus captioned "Prior Activities" regarding the sale of
limited and general partner interests. In the opinion of Atlas, the foregoing
unregistered securities in each case have been and/or are being offered and sold
in compliance with exemptions from registration provided by the Securities Act
of 1933, as amended, including the exemptions provided by Section 4(2) of that
Act and certain rules and regulations promulgated thereunder. The securities in
each case have been and/or are being offered and sold to a limited number of
persons who had the sophistication to understand the merits and risks of the
investment and who had the financial ability to bear such risks. The units of
limited and general partner interests were sold to persons who were Accredited
Investors, as that term is defined in Regulation D (17 CFR 230.501(a)), or who
had, at the time of purchase, a net worth of at least $225,000 (exclusive of
home,


                                        1

<PAGE>

furnishings and automobiles) of at least $125,000 and gross income of at least
$75,000, or otherwise satisfied Atlas that the investment was suitable.

ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

     (a)  Exhibits

          1(a)  Proposed form of Dealer-Manager Agreement with Anthem
                Securities, Inc.

          3(a)  Certificate of Organization of Atlas Resources, LLC

          3(b)  Operating Agreement of Atlas Resources, LLC

          4(a)  Certificate of Limited Partnership for Atlas America Public
                #16-2007(A) L.P.

          4(b)  Certificate of Limited Partnership for Atlas America Public
                #16-2007(B) L.P.

          4(c)  Form of Amended and Restated Certificate and Agreement of
                Limited Partnership for Atlas America Public #16-2007(A) L.P.
                [Form of Amended and Restated Certificate and Agreement of
                Limited Partnership for Atlas America Public #16-2007(B) L.P.]
                (See Exhibit (A) to Prospectus)

          5     Opinion of Kunzman & Bollinger, Inc. as to the legality of the
                Units

          8     Opinion of Kunzman & Bollinger, Inc. as to federal tax matters

          10(a) Escrow Agreement for Atlas America Public #16-2007(A) L.P.

          10(b) Form of Drilling and Operating Agreement for Atlas America
                Public #16-2007(A) L.P. [Atlas America Public #16-2007(B) L.P.]
                (See Exhibit (II) to the Form of Limited Partnership Agreement,
                Exhibit (A) to Prospectus)

          10(c) Gas Purchase Agreement dated March 31, 1999 between Northeast
                Ohio Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas
                Resources, Inc., and Resource Energy, Inc.

          10(d) Guaranty dated August 12, 2003 between First Energy Corp. and
                Atlas Resources, Inc. to Gas Purchase Agreement dated March 31,
                1999 between Northeast Ohio Gas Marketing, Inc., and Atlas
                Energy Group, Inc., Atlas Resources, Inc., and Resource Energy,
                Inc.

          10(e) Master Natural Gas Gathering Agreement dated February 2, 2000
                among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating
                Partnership, L.P., Atlas America, Inc., Resource Energy, Inc.,
                and Viking Resources Corporation

          10(f) Omnibus Agreement dated February 2, 2000 among Atlas America,
                Inc., Resource Energy, Inc., and Viking Resources Corporation,
                and Atlas Pipeline Operating Partnership, L.P., and Atlas
                Pipeline Partners, L.P.

          10(g) Natural Gas Gathering Agreement dated January 1, 2002 among
                Atlas Pipeline Partners, L.P., and Atlas Pipeline Operating
                Partnership, L.P. and Atlas Resources, Inc., and Atlas Energy
                Group, Inc. and Atlas Noble Corporation, and Resource Energy
                Inc., and Viking Resources Corporation

          10(h) Base Contract for Sale and Purchase of Natural Gas dated
                November 13, 2002 Between UGI Energy Services, Inc. and Viking
                Resources Corp.

          10(i) Guaranty dated June 1, 2004 between UGI Corporation and Viking
                Resources Corp.


                                        2

<PAGE>

          10(j) Guaranty as of December 7, 2004 between FirstEnergy Corp. and
                Atlas Resources, Inc.

          10(k) Confirmation of Gas Purchase and Sales Agreement dated November
                17, 2004 between Atlas Resources, Inc. et. al. and First Energy
                Solutions Corp. for the period from April 1, 2006 through March
                31, 2007 production/calendar periods

          10(l) Transaction Confirmation dated December 14, 2004 between Atlas
                America, Inc. and UGI Energy Services, Inc. d/b/a GASMARK

          10(m) Drilling and Operating Agreement Dated September 15, 2004 by and
                between Atlas America, Inc. and Knox Energy, LLC

          10(n) Guaranty dated January 1, 2005 between UGI Corporation and
                Viking Resources Corp.

          10(o) Escrow Agreement for Atlas America Public #16-2007(B) L.P.

          10(p) Amendment among Atlas Pipeline Partners, L.P. and Atlas Pipeline
                Operating Partnership, L.P., Atlas America, Inc., Resource
                Energy, Inc., Viking Resources Corporation, Atlas Noble Corp.,
                and Atlas Resources, Inc. to the Master Natural Gas Gathering
                Agreement dated February 2, 2000 and the Natural Gas Gathering
                Agreement dated January 1, 2002

          23(a) Consent of Independent Registered Public Accounting Firm

          23(b) Consent of Kunzman & Bollinger, Inc. (See Exhibits 5 and 8)

          23(c) Consent of Wright & Company, Inc.

          24    Power of Attorney

----------
     (b)  Financial Statement Schedules

     All financial statement schedules are omitted because the information is
not required, is not material or is otherwise included in the financial
statements or related notes thereto.

ITEM 17. UNDERTAKINGS.

The undersigned registrant hereby undertakes:

(a)  (1)  To file, during any period in which offers or sales are being made, a
          post-effective amendment to this registration statement:

          (i)   To include any prospectus required by section 10(a)(3) of the
                Securities Act of 1933;

          (ii)  To reflect in the prospectus any facts or events arising after
                the effective date of the registration statement (or the most
                recent post-effective amendment thereof) which, individually or
                in the aggregate, represent a fundamental change in the
                information set forth in the registration statement.
                Notwithstanding the foregoing, any increase or decrease in
                volume of securities offered (if the total dollar value of
                securities offered would not exceed that which was registered)
                and any deviation from the low or high end of the estimated
                maximum offering range may be reflected in the form of
                prospectus filed with the Commission pursuant to Rule 424(b)
                (Section 230.424(b) of this chapter) if, in the aggregate, the
                changes in volume and price represent no more than 20% change


                                        3

<PAGE>

                in the maximum aggregate offering price set forth in the
                "Calculation of Registration Fee" table in the effective
                registration statement.

          (iii) To include any material information with respect to the plan of
                distribution not previously disclosed in the registration
                statement or any material change to such information in the
                registration statement;

          Provided, however, That:

               (A)  Paragraphs (a)(1)(i) and (a)(1)(ii) of this section do not
                    apply if the registration statement is on Form S-8 (Section
                    239.16b of this chapter), and the information required to be
                    included in a post-effective amendment by those paragraphs
                    is contained in reports filed with or furnished to the
                    Commission by the registrant pursuant to section 13 or
                    section 15(d) of the Securities Exchange Act of 1934 (15
                    U.S.C. 78m or 78o(d)) that are incorporated by reference in
                    the registration statement; and

               (B)  Paragraphs (a)(1)(i), (a)(1)(ii) and (a)(1)(iii) of this
                    section do not apply if the registration statement is on
                    Form S-3 (Section 239.13 of this chapter) or Form F-3
                    (Section 239.33 of this chapter) and the information
                    required to be included in a post-effective amendment by
                    those paragraphs is contained in reports filed with or
                    furnished to the Commission by the registrant pursuant to
                    section 13 or section 15(d) of the Securities Exchange Act
                    of 1934 that are incorporated by reference in the
                    registration statement, or is contained in a form of
                    prospectus filed pursuant to Rule 424(b) (Section
                    230.424(b) of this chapter) that is part of the registration
                    statement.

               (C)  Provided further, however, that paragraphs (a)(1)(i) and
                    (a)(1)(ii) do not apply if the registration statement is for
                    an offering of asset-backed securities on Form S-1 (Section
                    239.11 of this chapter) or Form S-3 (Section 239.13 of this
                    chapter), and the information required to be included in a
                    post-effective amendment is provided pursuant to Item
                    1100(c) of Regulation AB (Section 229.1100(c)).

     (2)  That, for the purpose of determining any liability under the
          Securities Act of 1933, each such post-effective amendment shall be
          deemed to be a new registration statement relating to the securities
          offered therein, and the offering of such securities at that time
          shall be deemed to be the initial bona fide offering thereof.

     (3)  To remove from registration by means of a post-effective amendment any
          of the securities being registered which remain unsold at the
          termination of the offering.

     (4)  If the registrant is a foreign private issuer, to file a
          post-effective amendment to the registration statement to include any
          financial statements required by "Item 8.A. of Form 20-F (17 CFR
          249.220f)" at the start of any delayed offering or throughout a
          continuous offering. Financial statements and information otherwise
          required by Section 10(a)(3) of the Act need not be furnished,
          provided that the registrant includes in the prospectus, by means of a
          post-effective amendment, financial statements required pursuant to
          this paragraph (a)(4) and other information necessary to ensure that
          all other information in the prospectus is at least as current as the
          date of those financial statements. Notwithstanding the foregoing,
          with respect to registration statements on Form F-3 (Section 239.33
          of this chapter), a post-effective amendment need not be filed to
          include financial statements and information required by Section
          10(a)(3) of the Act or Section 210.3-19 of this chapter if such
          financial statements and information are contained in periodic reports
          filed with or furnished to the Commission by the registrant pursuant
          to section 13 or section 15(d) of the Securities Exchange Act of 1934
          that are incorporated by reference in the Form F-3.

     (5)  That, for the purpose of determining liability under the Securities
          Act of 1933 to any purchaser:


                                        4

<PAGE>

          (i)  If the registrant is relying on Rule 430B (Section 230.430B of
               this chapter):

               (A)  Each prospectus filed by the registrant pursuant to Rule
                    424(b)(3) (Section 230.424(b)(3) of this chapter) shall be
                    deemed to be part of the registration statement as of the
                    date the filed prospectus was deemed part of and included in
                    the registration statement; and

               (B)  Each prospectus required to be filed pursuant to Rule
                    424(b)(2), (b)(5), or (b)(7) (Section 230.424(b)(2),
                    (b)(5), or (b)(7) of this chapter) as part of a registration
                    statement in reliance on Rule 430B relating to an offering
                    made pursuant to Rule 415(a)(1)(i), (vii), or (x) (Section
                    230.415(a)(1)(i), (vii), or (x) of this chapter) for the
                    purpose of providing the information required by section
                    10(a) of the Securities Act of 1933 shall be deemed to be
                    part of and included in the registration statement as of the
                    earlier of the date such form of prospectus is first used
                    after effectiveness or the date of the first contract of
                    sale of securities in the offering described in the
                    prospectus. As provided in Rule 430B, for liability purposes
                    of the issuer and any person that is at that date an
                    underwriter, such date shall be deemed to be a new effective
                    date of the registration statement relating to the
                    securities in the registration statement to which that
                    prospectus relates, and the offering of such securities at
                    that time shall be deemed to be the initial bona fide
                    offering thereof. Provided, however, that no statement made
                    in a registration statement or prospectus that is part of
                    the registration statement or made in a document
                    incorporated or deemed incorporated by reference into the
                    registration statement or prospectus that is part of the
                    registration statement will, as to a purchaser with a time
                    of contract of sale prior to such effective date, supersede
                    or modify any statement that was made in the registration
                    statement or prospectus that was part of the registration
                    statement or made in any such document immediately prior to
                    such effective date; or

          (ii) If the registrant is subject to Rule 430C (Section 230.430C of
               this chapter), each prospectus filed pursuant to Rule 424(b) as
               part of a registration statement relating to an offering, other
               than registration statements relying on Rule 430B or other than
               prospectuses filed in reliance on Rule 430A (Section 230.430A of
               this chapter), shall be deemed to be part of and included in the
               registration statement as of the date it is first used after
               effectiveness. Provided, however, that no statement made in a
               registration statement or prospectus that is part of the
               registration statement or made in a document incorporated or
               deemed incorporated by reference into the registration statement
               or prospectus that is part of the registration statement will, as
               to a purchaser with a time of contract of sale prior to such
               first use, supersede or modify any statement that was made in the
               registration statement or prospectus that was part of the
               registration statement or made in any such document immediately
               prior to such date of first use.

     (6)  That, for the purpose of determining liability of the registrant under
          the Securities Act of 1933 to any purchaser in the initial
          distribution of the securities:

          The undersigned registrant hereby undertakes that in a primary
          offering of securities of the undersigned registrant pursuant to this
          registration statement, regardless of the underwriting method used to
          sell the securities to the purchaser, if the securities are offered or
          sold to such purchaser by means of any of the following
          communications, the undersigned registrant will be a seller to the
          purchaser and will be considered to offer or sell such securities to
          such purchaser:

          (i)   Any preliminary prospectus or prospectus of the undersigned
                registrant relating to the offering required to be filed
                pursuant to Rule 424 (Section 230.424 of this chapter);

          (ii)  Any free writing prospectus relating to the offering prepared by
                or on behalf of the undersigned registrant or used or referred
                to by the undersigned registrant;


                                        5

<PAGE>

          (iii) The portion of any other free writing prospectus relating to the
                offering containing material information about the undersigned
                registrant or its securities provided by or on behalf of the
                undersigned registrant; and

          (iv)  Any other communication that is an offer in the offering made by
                the undersigned registrant to the purchaser.

(b)  The undersigned registrant hereby undertakes that, for purposes of
     determining any liability under the Securities Act of 1933, each filing of
     the registrant's annual report pursuant to section 13(a) or section 15(d)
     of the Securities Exchange Act of 1934 (and, where applicable, each filing
     of an employee benefit plan's annual report pursuant to section 15(d) of
     the Securities Exchange Act of 1934) that is incorporated by reference in
     the registration statement shall be deemed to be a new registration
     statement relating to the securities offered therein, and the offering of
     such securities at that time shall be deemed to be the initial bona fide
     offering thereof.

(c)  The undersigned registrant hereby undertakes to supplement the prospectus,
     after the expiration of the subscription period, to set forth the results
     of the subscription offer, the transactions by the underwriters during the
     subscription period, the amount of unsubscribed securities to be purchased
     by the underwriters, and the terms of any subsequent reoffering thereof. If
     any public offering by the underwriters is to be made on terms differing
     from those set forth on the cover page of the prospectus, a post-effective
     amendment will be filed to set forth the terms of such offering.

(d)  The undersigned registrant hereby undertakes (1) to use its best efforts to
     distribute prior to the opening of bids, to prospective bidders,
     underwriters, and dealers, a reasonable number of copies of a prospectus
     which at that time meets the requirements of section 10(a) of the Act, and
     relating to the securities offered at competitive bidding, as contained in
     the registration statement, together with any supplements thereto, and (2)
     to file an amendment to the registration statement reflecting the results
     of bidding, the terms of the reoffering and related matters to the extent
     required by the applicable form, not later than the first use, authorized
     by the issuer after the opening of bids, of a prospectus relating to the
     securities offered at competitive bidding, unless no further public
     offering of such securities by the issuer and no reoffering of such
     securities by the purchasers is proposed to be made.

(e)  The undersigned registrant hereby undertakes to deliver or cause to be
     delivered with the prospectus, to each person to whom the prospectus is
     sent or given, the latest annual report to security holders that is
     incorporated by reference in the prospectus and furnished pursuant to and
     meeting the requirements of Rule 14a-3 or Rule 14c-3 under the Securities
     Exchange Act of 1934; and, where interim financial information required to
     be presented by Article 3 of Regulation S-X are not set forth in the
     prospectus, to deliver, or cause to be delivered to each person to whom the
     prospectus is sent or given, the latest quarterly report that is
     specifically incorporated by reference in the prospectus to provide such
     interim financial information.

(f)  The undersigned registrant hereby undertakes to provide to the underwriter
     at the closing specified in the underwriting agreements certificates in
     such denominations and registered in such names as required by the
     underwriter to permit prompt delivery to each purchaser.

(g)  (1)  The undersigned registrant hereby undertakes as follows: that prior to
          any public reoffering of the securities registered hereunder through
          use of a prospectus which is a part of this registration statement, by
          any person or party who is deemed to be an underwriter within the
          meaning of Rule 145(c), the issuer undertakes that such reoffering
          prospectus will contain the information called for by the applicable
          registration form with respect to reofferings by persons who may be
          deemed underwriters, in addition to the information called for by the
          other Items of the applicable form.

     (2)  The undersigned registrant hereby undertakes that every prospectus (i)
          that is filed pursuant to paragraph (h) (1) immediately preceding, or
          (ii) that purports to meet the requirements of section 10(a)(3) of the
          Act and is used in connection with an offering of securities subject
          to Rule 415 (Section 230.415 of this chapter), will be filed as a
          part of an amendment to the registration statement and will not be
          used until such amendment is effective, and that, for purposes of
          determining any liability under the Securities Act of 1933, each such


                                        6

<PAGE>

          post-effective amendment shall be deemed to be a new registration
          statement relating to the securities offered therein, and the offering
          of such securities at that time shall be deemed to be the initial bona
          fide offering thereof.

(h)  Insofar as indemnification for liabilities arising under the Securities Act
     of 1933 may be permitted to directors, officers and controlling persons of
     the registrant pursuant to the foregoing provisions, or otherwise, the
     registrant has been advised that in the opinion of the Securities and
     Exchange Commission such indemnification is against public policy as
     expressed in the Act and is, therefore, unenforceable. In the event that a
     claim for indemnification against such liabilities (other than the payment
     by the registrant of expenses incurred or paid by a director, officer or
     controlling person of the registrant in the successful defense of any
     action, suit or proceeding) is asserted by such director, officer or
     controlling person in connection with the securities being registered, the
     registrant will, unless in the opinion of its counsel the matter has been
     settled by controlling precedent, submit to a court of appropriate
     jurisdiction the question whether such indemnification by it is against
     public policy as expressed in the Act and will be governed by the final
     adjudication of such issue.

(i)  The undersigned registrant hereby undertakes that:

     (1)  For purposes of determining any liability under the Securities Act of
          1933, the information omitted from the form of prospectus filed as
          part of this registration statement in reliance upon Rule 430A and
          contained in a form of prospectus filed by the registrant pursuant to
          Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be
          deemed to be part of this registration statement as of the time it was
          declared effective.

     (2)  For the purpose of determining any liability under the Securities Act
          of 1933, each post-effective amendment that contains a form of
          prospectus shall be deemed to be a new registration statement relating
          to the securities offered therein, and the offering of such securities
          at that time shall be deemed to be the initial bona fide offering
          thereof.

(j)  The undersigned registrant hereby undertakes to file an application for the
     purpose of determining the eligibility of the trustee to act under
     subsection (a) of section 310 of the Trust Indenture Act ("Act") in
     accordance with the rules and regulations prescribed by the Commission
     under section 305(b)(2) of the Act.

(k)  The undersigned registrant hereby undertakes that, for purposes of
     determining any liability under the Securities Act of 1933, each filing of
     the annual report pursuant to section 13(a) or section 15(d) of the
     Securities Exchange Act of 1934 of a third party that is incorporated by
     reference in the registration statement in accordance with Item 1100(c)(1)
     of Regulation AB (17 CFR 229.1100(c)(1)) shall be deemed to be a new
     registration statement relating to the securities offered therein, and the
     offering of such securities at that time shall be deemed to be the initial
     bona fide offering thereof.

(l)  The undersigned registrant hereby undertakes that, except as otherwise
     provided by Item 1105 of Regulation AB (17 CFR 229.1105), information
     provided in response to that Item pursuant to Rule 312 of Regulation S-T
     (17 CFR 232.312) through the specified Internet address in the prospectus
     is deemed to be a part of the prospectus included in the registration
     statement. In addition, the undersigned registrant hereby undertakes to
     provide to any person without charge, upon request, a copy of the
     information provided in response to Item 1105 of Regulation AB pursuant to
     Rule 312 of Regulation S-T through the specified Internet address as of the
     date of the prospectus included in the registration statement if a
     subsequent update or change is made to the information.


                                        7

<PAGE>

                                   SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the
Registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in Moon Township,
Pennsylvania on October 18, 2006.

                                           ATLAS AMERICA PUBLIC #16-2007 PROGRAM
                                           (Registrant)


                                           By: Atlas Resources, LLC,
                                               Managing General Partner


Jack L. Hollander, pursuant                By: /s/ Jack L. Hollander
to the Registration Statement, has             ---------------------------------
been granted Power of Attorney and is          Jack L. Hollander, Senior Vice
signing on behalf of the names shown           President - Direct Participation
below, in the capacities indicated.            Programs

In accordance with the requirements of the Securities Act of 1933, this
Registration Statement has been signed by the following persons in the
capacities and on the dates indicated.

<TABLE>
<CAPTION>
SIGNATURE                                               Title                                              DATE
---------                                               -----                                              ----
<S>                  <C>                                                                           <C>
Freddie M. Kotek     President, Chief Executive Officer and Chairman of the Board of Directors     October 18, 2006
Frank P. Carolas     Executive Vice President - Land and Geology and a Director                    October 18, 2006
Jeffrey C. Simmons   Executive Vice President - Operations and a Director                          October 18, 2006
Nancy J. McGurk      Senior Vice President, Chief Financial Officer and Chief Accounting Officer   October 18, 2006
</TABLE>


<PAGE>

    As filed with the Securities and Exchange Commission on October 18, 2006

                                              Registration Number 333-__________

================================================================================

                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                   ----------

                                    EXHIBITS
                                       TO
                                    FORM S-1
                             REGISTRATION STATEMENT
                                      Under
                           THE SECURITIES ACT OF 1933

                                   ----------

                      ATLAS AMERICA PUBLIC #16-2007 PROGRAM
             (Exact name of Registrant as Specified in its Charter)

                                   ----------

    JACK L. HOLLANDER, SENIOR VICE PRESIDENT - DIRECT PARTICIPATION PROGRAMS
                              ATLAS RESOURCES, LLC
               311 ROUSER ROAD, MOON TOWNSHIP, PENNSYLVANIA 15108
                                 (412) 262-2830
           (Name, Address and Telephone Number of Agent for Service)

                                   ----------

                                   Copies to:

WALLACE W. KUNZMAN, JR., ESQ.                  JACK L. HOLLANDER
KUNZMAN & BOLLINGER, INC.                      ATLAS RESOURCES, LLC
5100 N. BROOKLINE, SUITE 600                   311 ROUSER ROAD
OKLAHOMA CITY, OKLAHOMA 73112                  MOON TOWNSHIP, PENNSYLVANIA 15108

================================================================================

<PAGE>

                                  EXHIBIT INDEX

Exhibit No.                               Description
-----------                               -----------
1(a)          Proposed form of Dealer-Manager Agreement with Anthem Securities,
              Inc.

3(a)          Certificate of Organization of Atlas Resources, LLC

3(b)          Operating Agreement of Atlas Resources, LLC

4(a)          Certificate of Limited Partnership for Atlas America Public
              #16-2007(A) L.P.

4(b)          Certificate of Limited Partnership for Atlas America Public
              #16-2007(B) L.P.

4(d)          Form of Amended and Restated Certificate and Agreement of Limited
              Partnership for Atlas America Public #16-2007(A) L.P. [Form of
              Amended and Restated Certificate and Agreement of Limited
              Partnership for Atlas America Public #16-2007(B) L.P.] (See
              Exhibit (A) to Prospectus)

5             Opinion of Kunzman & Bollinger, Inc. as to the legality of the
              Units

8             Opinion of Kunzman & Bollinger, Inc. as to federal tax matters

10(a)         Escrow Agreement for Atlas America Public #16-2007(A) L.P.

10(b)         Form of Drilling and Operating Agreement for Atlas America Public
              #16-2007(A) L.P. [Atlas America Public #16-2007(B) L.P.] (See
              Exhibit (II) to the Form of Limited Partnership Agreement, Exhibit
              (A) to Prospectus)

10(c)         Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio
              Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas
              Resources, Inc., and Resource Energy, Inc.

10(d)         Guaranty dated August 12, 2003 between First Energy Corp. and
              Atlas Resources, Inc. to Gas Purchase Agreement dated March 31,
              1999 between Northeast Ohio Gas Marketing, Inc., and Atlas Energy
              Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc.

10(e)         Master Natural Gas Gathering Agreement dated February 2, 2000
              among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating
              Partnership, L.P., Atlas America, Inc., Resource Energy, Inc., and
              Viking Resources Corporation

10(f)         Omnibus Agreement dated February 2, 2000 among Atlas America,
              Inc., Resource Energy, Inc., and Viking Resources Corporation, and
              Atlas Pipeline Operating Partnership, L.P., and Atlas Pipeline
              Partners, L.P.

10(g)         Natural Gas Gathering Agreement dated January 1, 2002 among Atlas
              Pipeline Partners, L.P., and Atlas Pipeline Operating Partnership,
              L.P. and Atlas Resources, Inc., and Atlas Energy Group, Inc. and
              Atlas Noble Corporation, and Resource Energy Inc., and Viking
              Resources Corporation

10(h)         Base Contract for Sale and Purchase of Natural Gas dated November
              13, 2002 Between UGI Energy Services, Inc. and Viking Resources
              Corp.

10(i)         Guaranty dated June 1, 2004 between UGI Corporation and Viking
              Resources Corp.

10(j)         Guaranty as of December 7, 2004 between FirstEnergy Corp. and
              Atlas Resources, Inc.

10(k)         Confirmation of Gas Purchase and Sales Agreement dated November
              17, 2004 between Atlas Resources, Inc. et. al. and First Energy
              Solutions Corp. for the period from April 1, 2006 through March
              31, 2007 production/calendar periods

10(l)         Transaction Confirmation dated December 14, 2004 between Atlas
              America, Inc. and UGI Energy Services, Inc. d/b/a GASMARK

10(m)         Drilling and Operating Agreement Dated September 15, 2004 by and
              between Atlas America, Inc. and Knox Energy, LLC

10(n)         Guaranty dated January 1, 2005 between UGI Corporation and Viking
              Resources Corp.

10(o)         Escrow Agreement for Atlas America Public #16-2007(B) L.P.


                                       i

<PAGE>

Exhibit No.                               Description
-----------                               -----------
10(p)         Amendment among Atlas Pipeline Partners, L.P. and Atlas Pipeline
              Operating Partnership, L.P., Atlas America, Inc., Resource Energy,
              Inc., Viking Resources Corporation, Atlas Noble Corp., and Atlas
              Resources, Inc. to the Master Natural Gas Gathering Agreement
              dated February 2, 2000 and the Natural Gas Gathering Agreement
              dated January 1, 2002

23(a)         Consent of Independent Registered Public Accounting Firm

23(b)         Consent of Kunzman & Bollinger, Inc. (See Exhibits 5 and 8)

23(c)         Consent of Wright & Company, Inc.

23(d)         Consent of United Energy Development Consultants, Inc.

24            Power of Attorney

----------


                                       ii
[{"type": "S-1", "sequence": "1", "filename": "p414971_s1.txt", "description": "FORM S-1", "secsgml_size_bytes": 1227962}]
[{"company-data": {"conformed-name": "Atlas America Public #16-2007 Program", "cik": "0001374986", "irs-number": "000000000", "fiscal-year-end": "1231"}, "filing-values": {"form-type": "S-1", "act": "33", "file-number": "333-138068", "film-number": "061151504"}, "business-address": {"street1": "311 ROSER RD.", "city": "MOON TOWNSHIP", "state": "PA", "zip": "15108", "phone": "330-896-8510"}, "mail-address": {"street1": "311 ROSER RD.", "city": "MOON TOWNSHIP", "state": "PA", "zip": "15108"}}, {"company-data": {"conformed-name": "Atlas America Public #16-2007 (B) L.P.", "cik": "0001374984", "irs-number": "000000000", "fiscal-year-end": "1231"}, "filing-values": {"form-type": "S-1", "act": "33", "file-number": "333-138068-01", "film-number": "061151505"}, "business-address": {"street1": "311 ROSER RD.", "city": "MOON TOWNSHIP", "state": "PA", "zip": "15108", "phone": "330-896-8510"}, "mail-address": {"street1": "311 ROSER RD.", "city": "MOON TOWNSHIP", "state": "PA", "zip": "15108"}}, {"company-data": {"conformed-name": "Atlas America Public #16-2007 (A) L.P.", "cik": "0001374985", "irs-number": "000000000", "fiscal-year-end": "1231"}, "filing-values": {"form-type": "S-1", "act": "33", "file-number": "333-138068-02", "film-number": "061151506"}, "business-address": {"street1": "311 ROSER RD.", "city": "MOON TOWNSHIP", "state": "PA", "zip": "15108", "phone": "330-896-8510"}, "mail-address": {"street1": "311 ROSER RD.", "city": "MOON TOWNSHIP", "state": "PA", "zip": "15108"}}]
As filed with the Securities and Exchange Commission on October 18, 2006

                                                  Registration Number 333-

                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                   ----------

                                    FORM S-1
             REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

                                   ----------

                      ATLAS AMERICA PUBLIC #16-2007 PROGRAM
             (Exact name of Registrant as Specified in its Charter)

                                    DELAWARE
         (State or other jurisdiction of incorporation or organization)

                                   ----------

                                      1311
            (Primary Standard Industrial Classification Code Number)

                                   ----------

                                 NOT APPLICABLE
                      (IRS Employer Identification Number)

                                   ----------

                                 311 ROUSER ROAD
                        MOON TOWNSHIP, PENNSYLVANIA 15108
                                 (412) 262-2830
               (Address, including zip code, and telephone number,
        including area code, of registrant's principal executive offices)

                                   ----------

    JACK L. HOLLANDER, SENIOR VICE PRESIDENT - DIRECT PARTICIPATION PROGRAMS
                              ATLAS RESOURCES, LLC
               311 ROUSER ROAD, MOON TOWNSHIP, PENNSYLVANIA 15108
                                 (412) 262-2830
                (Name, address, including zip code, and telephone
               number, including area code, of agent for service)

                                   ----------

                                 With a Copy to:
                          WALLACE W. KUNZMAN, JR., ESQ.
                            KUNZMAN & BOLLINGER, INC.
                                5100 N. BROOKLINE
                                    SUITE 600
                          OKLAHOMA CITY, OKLAHOMA 73112

                                   ----------

   AS SOON AS PRACTICABLE AFTER THIS REGISTRATION STATEMENT BECOMES EFFECTIVE.
        (Approximate Date of Commencement of Proposed Sale to the Public)

     If any of the securities being registered on this form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, check the following box: [X]

     If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [_]

     If this Form is a post-effective amendment filed pursuant to rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]

     If this Form is a post-effective amendment filed pursuant to rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]

                                   ----------
CALCULATION OF REGISTRATION FEE
Title of Each                               Unit             Dollar      Proposed Maximum   Proposed Maximum
Class of Securities                        Amounts       Amounts to be       Offering           Aggregate          Amount of
to be Registered                      to be Registered     Registered     Price per Unit     Offering Price    Registration Fee
-----------------------------------   ----------------   -------------   ----------------   -----------------------------------
Investor General Partner Units (1)         19,900        $199,000,000        $10,000          $199,000,000        $21,293.00
Converted Limited Partner Units (2)        19,900                 -0-            -0-                   -0-               -0-
Limited Partner Units (2)                     100        $  1,000,000        $10,000          $  1,000,000        $   107.00
                                           ------        ------------        -------          ------------        ----------
TOTAL                                      20,000        $200,000,000                         $200,000,000        $21,400.00
                                           ======        ============                         ============        ==========
(1)  "Investor General Partner Units" means the investor general partner
     interests offered to participants in the program.-

(2)  "Limited Partner Units" means up to 100 initial limited partner interests
     offered to participants in the program and up to 19,900 limited partner
     units into which the investor general partner units automatically will be
     converted by the managing general partner with no additional price paid by
     the investor.

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATES AS MAY BE
NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER
AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL
THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES
ACT OF 1933 OR UNTIL THIS REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH
DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE.
ATLAS AMERICA PUBLIC #16-2007 PROGRAM
                              CROSS REFERENCE SHEET
Item of Form S-1                                     Caption in Prospectus
                  ----------------                                     ---------------------
Item 1.  Forepart of the Registration Statement and
         Outside Front Cover Page of Prospectus.....   Front Page of Registration Statement and Outside
                                                       Front Cover Page of Prospectus

Item 2.  Inside Front and Outside Back Cover Pages
         of Prospectus..............................   Inside Front and Outside Back Cover Pages of
                                                       Prospectus

Item 3.  Summary Information, Risk Factors and Ratio
         Of Earnings to Fixed Charges...............   Summary of the Offering; Risk Factors

Item 4.  Use of Proceeds............................   Capitalization and Source of Funds and Use of
                                                       Proceeds

Item 5.  Determination of Offering Price............   Terms of the Offering

Item 6.  Dilution...................................   The managing general partner's officers, directors,
                                                       promoters and affiliated persons have not acquired
                                                       any units during the past five years. Also, no units
                                                       will be issued in this offering to the managing
                                                       general partner except units subscribed for by the
                                                       managing general partner, which it does not
                                                       anticipate. Discounted units, if any, are described
                                                       in "Plan of Distribution."

Item 7.  Selling Security Holders...................   The program does not have any selling security
                                                       holders.

Item 8.  Plan of Distribution.......................   Plan of Distribution

Item 9.  Description of Securities to be
         Registered.................................   Summary of the Offering; Terms of the Offering;
                                                       Summary of Partnership Agreement

Item 10. Interests of Named Experts and Counsel.....   Legal Opinions; Experts

Item 11. Information with respect to the Registrant

         (a) Description of Business................   Proposed Activities; Management

         (b) Description of Property................   Proposed Activities

         (c) Legal Proceedings......................   Litigation

         (d) Market Price of and Dividends on the
             Registrant's Common Equity and
             Related Stockholder Matters............   The partnerships composing the program have no
                                                       markets in which their units are being traded and
                                                       they have not yet conducted activities or paid any
                                                       dividends.

         (e) Financial Statements...................   Financial Information Concerning the Managing General
                                                       Partner and Atlas America Public #16-2007(A) L.P.

         (f) Selected Financial Data................   All of the partnerships composing the program have
                                                       been formed, but the partnerships have not conducted
                                                       any activities. Thus, the program does not have this
                                                       information for the partnerships.

         (g) Supplementary Financial Information....   All of the partnerships composing the program have
                                                       been formed, but the partnerships have not conducted
                                                       any activities. Thus, the program does not have this
                                                       information for the partnerships.

         (h) Management's Discussion and Analysis of
             Financial Condition and Results of
             Operations.............................   Management's Discussion and Analysis of Financial
                                                       Condition, Results of Operations, Liquidity and
                                                       Capital Resources
Item of Form S-1                                     Caption in Prospectus
                  ----------------                                     ---------------------
(i) Changes in and Disagreements with
             Accountants on Accounting and
             Financial Disclosure...................   There have been no changes in and disagreements with
                                                       accountants on accounting and financial disclosure.

         (j) Quantitative and Qualitative
             Disclosures about Market Risk..........   The partnerships have no market for their units and
                                                       none will be created.

         (k) Directors and Executive Officers.......   Management

         (l) Executive Compensation.................   Management

         (m) Security Ownership of Certain
             Beneficial Owners and Management.......   Management

         (n) Certain Relationships and Related
             Transactions...........................   Compensation; Management; Conflicts of Interest

Item 12. Disclosure of Commission Position on
         Indemnification for Securities Act
         Liabilities................................   Fiduciary Responsibilities of the Managing General
                                                       Partner
----------
********************************************************************************
The information in this prospectus is not complete and may be changed. We may
not sell these securities until the registration statement filed with the
Securities and Exchange Commission is effective. This prospectus is not an offer
to sell these securities and it is not soliciting an offer to buy these
securities in any state where the offer or sale is not permitted.
********************************************************************************

                  PRELIMINARY PROSPECTUS DATED OCTOBER 18, 2006

                      ATLAS AMERICA PUBLIC #16-2007 PROGRAM

    Up to 19,900 Investor General Partner Units and 19,900 converted Limited
    Partner Units and up to 100 Limited Partner Units, which are collectively
                 referred to as the "Units," at $10,000 per Unit
             $2 Million (200 Units) Minimum Aggregate Subscriptions
           $200 Million (20,000 Units) Maximum Aggregate Subscriptions

Atlas America Public #16-2007 Program is a series of up to two limited
partnerships which will drill primarily natural gas development wells. See
"Terms of the Offering - Subscription to a Partnership," beginning on page 8,
for a detailed description of the offering of these limited partnerships. The
limited partnerships will be managed by Atlas Resources, LLC of Pittsburgh,
Pennsylvania.

If you invest in a partnership, you will not have any interest in the other
partnership unless you also make a separate investment in the other partnership.

The units will be offered on a "best efforts" "minimum-maximum" basis. This
means the broker/dealers must sell at least 200 units and receive subscription
proceeds of at least $2 million in order for a partnership to close, and they
must use only their best efforts to sell the remaining units in the partnership.

Subscription proceeds for each partnership will be held in an interest bearing
escrow account until $2 million has been received. The offering of Atlas America
Public #16-2007(A) L.P. and Atlas America Public #16-2007(B) L.P. will not
extend beyond December 31, 2007. If the minimum subscription proceeds are not
received by a partnership's offering termination date, then your subscription
will be promptly returned to you from the escrow account with interest and
without deduction for any fees.

The Offering: In addition to the information in the table below for not less
than 95% of the units (19,000 units), up to 5% of the units (1,000 units), in
the aggregate, may be sold at $8,950 per unit to the managing general partner,
its officers, directors and affiliates, and investors who buy units through the
officers and directors of the managing general partner; or at $9,300 per unit to
registered investment advisors and their clients, and selling agents and their
registered representatives and principals. These discounted prices reflect
certain fees, sales commissions and reimbursements which will not be paid for
these sales. (See "Plan of Distribution.") To the extent that units are sold at
discounted prices, a partnership's subscription proceeds will be reduced.

                                                          Total         Total
                                            Per Unit     Minimum     Maximum (2)
                                            --------   ----------   ------------
Public Price                                 $10,000   $2,000,000   $200,000,000
Dealer-manager fee, sales
   commissions and bona fide due
   diligence reimbursements (1)              $ 1,000   $  200,000   $ 20,000,000
Proceeds to partnership                      $10,000   $2,000,000   $200,000,000

----------
(1)  These fees, sales commissions and reimbursements will be paid by the
     managing general partner as a part of its capital contribution and not from
     subscription proceeds.

o    A partnership's drilling operations involve the possibility of a partial
     loss of your investment, which may be substantial, because a partnership
     may drill wells that are productive, but do not produce enough revenue to
     return the investment made, and from time to time dry holes.

o    A partnership's revenues are directly related to its ability to market the
     natural gas produced from the wells it drills and natural gas and oil
     prices, which are volatile and uncertain. If natural gas and oil prices
     decrease, then your investment return will decrease.

o    Unlimited joint and several liability for partnership obligations if you
     choose to invest as an investor general partner until you are converted to
     a limited partner.

o    Lack of liquidity or a market for the units, which makes it extremely
     difficult for you to sell your units.

o    Lack of conflict of interest resolution procedures.

o    Total reliance on the managing general partner and its affiliates.

o    Authorization of substantial fees to the managing general partner and its
     affiliates.

o    You and the managing general partner will share in costs disproportionately
     to your sharing of revenues.

o    Possible allocation of taxable income to you in excess of your cash
     distributions from your partnership.

o    No guaranty of cash distributions every month.

     THESE SECURITIES ARE SPECULATIVE AND ARE SUBJECT TO CERTAIN RISKS. YOU
     SHOULD PURCHASE THESE SECURITIES ONLY IF YOU CAN AFFORD A COMPLETE LOSS OF
     YOUR INVESTMENT. (SEE "RISK FACTORS," PAGE 8.)

     Neither the SEC nor any state securities commission has approved or
     disapproved of these securities or determined if this prospectus is
     truthful or complete. Any representation to the contrary is a criminal
     offense.

                    ANTHEM SECURITIES, INC. - DEALER-MANAGER
TABLE OF CONTENTS

SUMMARY OF THE OFFERING...................................................     1
   Business of the Partnerships and the Managing General Partner..........     1
   Risk Factors...........................................................     1
   Terms of the Offering..................................................     3
   Description of Units...................................................     3
      Investor General Partner Units......................................     3
      Limited Partner Units...............................................     4
   Use of Proceeds........................................................     5
   Five Year-50% Subordination, Participation in Costs and Revenues, and
      Distributions.......................................................     5
   Compensation...........................................................     7

RISK FACTORS..............................................................     8
   Risks Related To The Partnerships' Oil and Gas Operations..............     8
      No Guarantee of Return of Investment or Rate of Return on Investment
         Because of Speculative Nature of Drilling Natural Gas and Oil
         Wells............................................................     8
      Because Some Wells May Not Return Their Drilling and Completion
         Costs, It May Take Many Years to Return Your Investment in Cash,
         If Ever..........................................................     8
      Nonproductive Wells May be Drilled Even Though the Partnerships'
         Operations are Primarily Limited to Development Drilling.........     8
      Partnership Distributions May be Reduced if There is a Decrease in
         the Price of Natural Gas and Oil.................................     8
      Adverse Events in Marketing a Partnership's Natural Gas Could Reduce
         Partnership Distributions........................................     9
      Possible Leasehold Defects..........................................    11
      Transfer of the Leases Will Not Be Made Until Well is Completed.....    11
      Participation with Third-Parties in Drilling Wells May Require the
         Partnerships to Pay Additional Costs.............................    11
   Risks Related to an Investment In a Partnership........................    12
      If You Choose to Invest as a General Partner, Then You Have Greater
         Risk Than a Limited Partner......................................    12
      The Managing General Partner May Not Meet Its Capital Contributions,
         Indemnification and Purchase Obligations If Its Liquid Net Worth
         Is Not Sufficient................................................    12
      An Investment in a Partnership Must be for the Long-Term Because the
         Units Are Illiquid and Not Readily Transferable..................    13
      Spreading the Risks of Drilling Among a Number of Wells Will be
         Reduced if Less than the Maximum Subscription Proceeds are
         Received and Fewer Wells are Drilled.............................    13
      Increases in the Costs of the Wells May Adversely Affect Your
         Return...........................................................    14
      The Partnerships Do Not Own Any Prospects, the Managing General
         Partner Has Complete Discretion to Select Which Prospects Are
         Acquired By a Partnership, and The Possible Lack of Information
         for a Majority of the Prospects Decreases Your Ability to
         Evaluate the Feasibility of a Partnership........................    14
      Drilling Prospects in One Area May Increase Risk....................    14
      Lack of Production Information Increases Your Risk and Decreases
         Your Ability to Evaluate the Feasibility of a Partnership's
         Drilling Program.................................................    15
      The Partnerships in This Program and Other Partnerships Sponsored by
         the Managing General Partner May Compete With Each Other for
         Prospects, Equipment, Subcontractors, and Personnel..............    15
      Managing General Partner's Subordination is Not a Guarantee of the
         Return of Any of Your Investment.................................    15
      Borrowings by the Managing General Partner Could Reduce Funds
         Available for Its Subordination Obligation.......................    15
      Compensation and Fees to the Managing General Partner Regardless of
         Success of a Partnership's Activities Will Reduce Cash
         Distributions....................................................    16
      The Intended Monthly Distributions to Investors May be Reduced or
         Delayed..........................................................    16
      There Are Conflicts of Interest Between the Managing General Partner
         and the Investors................................................    16
      The Presentment Obligation May Not Be Funded and the Presentment
         Price May Not Reflect Full Value.................................    17
      The Managing General Partner May Not Devote the Necessary Time to
         the Partnerships Because Its Management Obligations Are Not
         Exclusive........................................................    18
      Prepaying Subscription Proceeds to the Managing General Partner May
         Expose the Subscription Proceeds to Claims of the Managing
         General Partner's Creditors......................................    18
      Lack of Independent Underwriter May Reduce Due Diligence
         Investigation of the Partnerships and the Managing General
         Partner..........................................................    18
      A Lengthy Offering Period May Result in Delays in the Investment of
         Your Subscription and Any Cash Distributions From the Partnership
         to You...........................................................    18
      Your Interests May Be Diluted.......................................    18
   Tax Risks..............................................................    19
      Your Deduction for Intangible Drilling Costs May Be Limited for
         Purposes of the Alternative Minimum Tax..........................    19
      Limited Partners Need Passive Income to Use Their Deduction for
         Intangible Drilling Costs........................................    19
      You May Owe Taxes in Excess of Your Cash Distributions from Your
         Partnership......................................................    19
      Investment Interest Deductions of Investor General Partners May Be
         Limited..........................................................    20
      Your Tax Benefits from an Investment in a Partnership Are Not
         Contractually Protected..........................................    20
      An IRS Audit of Your Partnership May Result in an IRS Audit of Your
         Personal Federal Income Tax Returns..............................    20
      Each Partnership's Deductions May be Challenged by the IRS..........    20
      Changes in the Law May Reduce Your Tax Benefits From an Investment
         in a Partnership.................................................    21
      It May Be Many Years Before You Receive Any Marginal Well Production
         Credits, If Ever.................................................    21

ADDITIONAL INFORMATION....................................................    21

FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS...........................    21

INVESTMENT OBJECTIVES.....................................................    22

ACTIONS TO BE TAKEN BY MANAGING GENERAL PARTNER TO REDUCE RISKS OF
   ADDITIONAL PAYMENTS BY INVESTOR GENERAL PARTNERS.......................    24

CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS....................    26

                                        i
TABLE OF CONTENTS

   Source of Funds........................................................    26
   Use of Proceeds........................................................    26

COMPENSATION..............................................................    29
   Natural Gas and Oil Revenues...........................................    30
   Lease Costs............................................................    30
   Drilling Contracts.....................................................    31
   Per Well Charges.......................................................    33
   Gathering Fees.........................................................    34
   Dealer-Manager Fees....................................................    35
   Interest and Other Compensation........................................    35
   Estimate of Administrative Costs and Direct Costs to be Borne by the
      Partnerships........................................................    36

TERMS OF THE OFFERING.....................................................    37
   Subscription to a Partnership..........................................    37
   Partnership Closings and Escrow........................................    38
   Acceptance of Subscriptions............................................    38
   Suitability Standards..................................................    39
      In General..........................................................    39
      General Suitability Requirements for Purchasers of Limited Partner
         Units............................................................    39
      Special Suitability Requirements for Purchasers of Limited Partner
         Units............................................................    40
      General Suitability Requirements for Purchasers of Investor General
         Partner Units....................................................    41
      Special Suitability Requirements for Purchasers of Investor General
         Partner Units....................................................    42
      Fiduciary Accounts..................................................    44

PRIOR ACTIVITIES..........................................................    44

MANAGEMENT................................................................    55
   Managing General Partner and Operator..................................    55
   Officers, Directors and Other Key Personnel of Managing General
      Partner.............................................................    56
   Atlas America, Inc., a Delaware Company................................    59
   Organizational Diagrams and Security Ownership of Beneficial Owners....    60
   Atlas Energy Resources, LLC, a Delaware Limited Liability Company......    62
   Atlas Energy Management, Inc., a Delaware Company......................    63
   Remuneration of Officers and Directors.................................    63
   Code of Business Conduct and Ethics....................................    63
   Transactions with Management and Affiliates............................    63

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, RESULTS OF
   OPERATIONS, LIQUIDITY AND CAPITAL RESOURCES............................    63

PROPOSED ACTIVITIES.......................................................    65
   Overview of Drilling Activities........................................    65
   Primary Areas of Operations............................................    66
      Mississippian/Upper Devonian Sandstone Reservoirs, Fayette County,
         Pennsylvania.....................................................    67
      Clinton/Medina Geological Formation in Western Pennsylvania.........    68
      Mississippian Carbonate and Devonian Shale Reservoirs in Anderson,
         Campbell, Morgan, Roane and Scott Counties, Tennessee............    68
   Secondary Areas of Operations..........................................    69
      Upper Devonian Sandstone Reservoirs, Armstrong County,
         Pennsylvania.....................................................    69
      Upper Devonian Sandstone Reservoirs in McKean County, Pennsylvania..    70
      Clinton/Medina Geological Formation in Western New York.............    70
      Clinton/Medina Geological Formation in Southern Ohio................    70
   Acquisition of Leases..................................................    71
      Deep Drilling Rights Retained by Managing General Partner...........    72
   Interests of Parties...................................................    72
   Primary Areas..........................................................    73
      Clinton/Medina Geological Formation in Western Pennsylvania and
         Mississippian/Upper Devonian Sandstone Reservoirs in Fayette
         County, Pennsylvania.............................................    73
      Mississippian Carbonate and Devonian Shale Reservoirs in Anderson,
         Campbell, Morgan, Roane and Scott Counties, Tennessee............    74
   Secondary Areas........................................................    74
   Title to Properties....................................................    74
   Drilling and Completion Activities; Operation of Producing Wells.......    75
   Sale of Natural Gas and Oil Production.................................    76
      Policy of Treating All Wells Equally in a Geographic Area...........    76
      Gathering of Natural Gas............................................    76
      Natural Gas Contracts...............................................    77
   Marketing of Natural Gas Production from Wells in Other Areas of the
      United States.......................................................    79
   Crude Oil..............................................................    79
   Insurance..............................................................    79
   Use of Consultants and Subcontractors..................................    80

COMPETITION, MARKETS AND REGULATION.......................................    80
   Natural Gas Regulation.................................................    80
   Crude Oil Regulation...................................................    80
   Competition and Markets................................................    80
   State Regulations......................................................    83
   Environmental Regulation...............................................    83
   Proposed Regulation....................................................    84

PARTICIPATION IN COSTS AND REVENUES.......................................    84
   In General.............................................................    84
   Costs..................................................................    85
   Revenues...............................................................    87
   Subordination of Portion of Managing General Partner's Net Revenue
      Share...............................................................    87
   Table of Participation in Costs and Revenues...........................    89
   Allocation and Adjustment Among Investors..............................    90
   Distributions..........................................................    90
   Liquidation............................................................    91

CONFLICTS OF INTEREST.....................................................    91
   In General.............................................................    91
   Conflicts Regarding Transactions with the Managing General Partner and
      its Affiliates......................................................    92
   Conflict Regarding the Drilling and Operating Agreement................    93
   Conflicts Regarding Sharing of Costs and Revenues......................    93
   Conflicts Regarding Tax Matters Partner................................    93
   Conflicts Regarding Other Activities of the Managing General Partner,
      the Operator and Their Affiliates...................................    94
   Conflicts Involving the Acquisition of Leases..........................    94
   Conflicts Regarding Order of Pipeline Construction and Gathering Fees..    98
   Conflicts Between Investors and the Managing General Partner as an
      Investor............................................................    99
   Lack of Independent Underwriter and Due Diligence Investigation........    99
   Conflicts Concerning Legal Counsel.....................................   100
   Conflicts Regarding Presentment Feature................................   100

                                       ii
TABLE OF CONTENTS

   Conflicts Regarding Managing General Partner Withdrawing or Assigning
      an Interest.........................................................   100
   Procedures to Reduce Conflicts of Interest.............................   100
   Policy Regarding Roll-Ups..............................................   102

FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER..................   103
   In General.............................................................   103
   Limitations on Managing General Partner Liability as Fiduciary.........   104

FEDERAL INCOME TAX CONSEQUENCES...........................................   104
   Introduction...........................................................   104
   Disclosures in Tax Opinion Letter......................................   105
   Special Counsel's Assumptions..........................................   105
   Managing General Partner's Representations.............................   105
   Special Counsel's Opinions.............................................   106
   Discussion of Federal Income Tax Consequences..........................   109
   Introduction...........................................................   109
   Partnership Classification.............................................   109
   Limitations on Passive Activity Losses and Credits.....................   109
   Publicly Traded Partnership Rules......................................   112
   Conversion from Investor General Partner to Limited Partner............   112
   Taxable Year and Method of Accounting..................................   112
      Taxable Year.......................................................    112
      Method of Accounting...............................................    112
   Business Expenses......................................................   113
   Intangible Drilling Costs..............................................   113
   Drilling Contracts.....................................................   114
   Depletion Allowance....................................................   117
   Depreciation and Cost Recovery Deductions..............................   118
   Marginal Well Production Credits.......................................   119
   Lease Acquisition Costs and Abandonment................................   119
   Tax Basis of Units.....................................................   120
   "At Risk" Limitation on Losses.........................................   120
   Distributions From a Partnership.......................................   121
   Sale of the Properties.................................................   121
   Disposition of Units...................................................   123
   Alternative Minimum Tax................................................   124
   Limitations on Deduction of Investment Interest........................   126
   Allocations............................................................   126
   Partnership Borrowings.................................................   128
   Partnership Organization and Offering Costs............................   128
   Tax Elections..........................................................   128
   Tax Returns and IRS Audits.............................................   130
      Tax Returns........................................................    130
   Profit Motive, IRS Anti-Abuse Rule and Judicial Doctrines Limitations
      on Deductions.......................................................   130
   Federal Interest and Tax Penalties.....................................   131
   State and Local Taxes..................................................   133
   Severance and Ad Valorem (Real Estate) Taxes...........................   133
   Social Security Benefits and Self-Employment Tax.......................   133
   Farmouts...............................................................   134
   Foreign Partners.......................................................   134
   Estate and Gift Taxation...............................................   134
   Changes in the Law.....................................................   134

SUMMARY OF PARTNERSHIP AGREEMENT..........................................   135
   Liability of Limited Partners..........................................   135
   Amendments.............................................................   135
   Notice.................................................................   135
   Voting Rights..........................................................   135
   Access to Records......................................................   136
   Withdrawal of Managing General Partner.................................   136
   Return of Subscription Proceeds if Funds Are Not Invested in Twelve
      Months..............................................................   137

SUMMARY OF DRILLING AND OPERATING AGREEMENT...............................   137

REPORTS TO INVESTORS......................................................   138

PRESENTMENT FEATURE.......................................................   139

TRANSFERABILITY OF UNITS..................................................   141
   Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws
      and the Partnership Agreement.......................................   141
   Conditions to Becoming a Substitute Partner............................   141

PLAN OF DISTRIBUTION......................................................   142
   Commissions............................................................   142
   Indemnification........................................................   144

SALES MATERIAL............................................................   144

LEGAL OPINIONS............................................................   145

EXPERTS...................................................................   145

LITIGATION................................................................   145

FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL PARTNER AND ATLAS
   AMERICA PUBLIC #16-2007(A) L.P.........................................   146

INDEX TO FINANCIAL STATEMENTS.............................................   146

Exhibits

Appendix A      Information Regarding Currently Proposed Prospects for Atlas
                America Public #16-2007(A) L.P.

Exhibit (A)     Form of Amended and Restated Certificate and Agreement of
                Limited Partnership for Atlas America Public #16-2007(A) L.P.
                [Form of Amended and Restated Certificate and Agreement of
                Limited Partnership for Atlas America Public #16-2007(B) L.P.]

Exhibit (I-A)   Form of Managing General Partner
                Signature Page

Exhibit (I-B)   Form of Subscription Agreement

Exhibit (II)    Form of Drilling and Operating Agreement for Atlas America
                Public #16-2007(A) L.P. [Atlas America Public #16-2007(B)
                L.P.]

Exhibit (B)     Special Suitability Requirements and Disclosures to Investors

                                       iii
SUMMARY OF THE OFFERING

This is a summary and does not include all of the information that may be
important to you. You should read this entire prospectus and the attached
exhibits and appendix before you decide to invest in a partnership. Throughout
this prospectus when there is a reference to you it is a reference to you as a
potential investor or participant in a partnership.

BUSINESS OF THE PARTNERSHIPS AND THE MANAGING GENERAL PARTNER

Atlas America Public #16-2007 Program, which is sometimes referred to in this
prospectus as the "program," consists of up to two Delaware limited
partnerships. These limited partnerships are sometimes referred to in this
prospectus in the singular as a "partnership" or in the plural as the
"partnerships." Units in the two partnerships will be offered and sold in a
series beginning with the offering of units in the first partnership, Atlas
America Public #16-2007(A) L.P. See "Terms of the Offering" for a discussion of
the terms and conditions involved in making an investment in a partnership.

Each partnership in the program will be a separate business entity from the
other partnership. A limited partnership agreement will govern the rights and
obligations of the partners of each partnership. A form of the limited
partnership agreement is attached to this prospectus as Exhibit (A). For a
summary of the material provisions of the limited partnership agreement which
are not covered elsewhere in this prospectus see "Summary of Partnership
Agreement." You will be a partner only in the partnership in which you invest.
You will have no interest in the business, assets or tax benefits of the other
partnership unless you also invest in the other partnership. Thus, your
investment return will depend solely on the operations and success or lack of
success of the partnership in which you invest.

The offering proceeds of each partnership will be used to drill primarily
natural gas development wells in the Appalachian Basin. The wells to be drilled
by each partnership will be located primarily in western Pennsylvania and north
central Tennessee as described in "Proposed Activities." A development well
means a well drilled within the proved area of a natural gas or oil reservoir to
the depth of a stratigraphic horizon known to be productive. Currently, the
partnerships do not hold any interests in any properties or prospects on which
the wells will be drilled by each partnership.

The managing general partner of each partnership is Atlas Resources, LLC, a
Pennsylvania limited liability company, which was originally formed as a
corporation in 1979 and then changed to a limited liability company in March,
2006. The managing general partner is sometimes referred to in this prospectus
as "Atlas Resources." As set forth in "Prior Activities," the managing general
partner has sponsored and serves as managing general partner of 38 private
drilling partnerships and 16 public drilling partnerships. Atlas Resources also
will serve as each partnership's general drilling contractor and operator and it
will supervise the drilling, completing and operating of the wells to be drilled
by each partnership.

The address and telephone number of the partnerships and the managing general
partner are 311 Rouser Road, Moon Township, Pennsylvania 15108, (412) 262-2830.

RISK FACTORS

This offering involves numerous risks, including risks related to each
partnership's oil and gas operations, risks related to an investment in a
partnership, and tax risks. You should carefully consider a number of
significant risk factors inherent in and affecting the business of a partnership
and this offering, including the following.

     o    The drilling operations of the partnership in which you invest involve
          the possibility of a partial loss of your investment, which may be
          substantial, because each partnership may drill wells that are
          productive, but do not produce enough revenue to return the investment
          made, and from time to time dry holes.

     o    Each partnership's revenues are directly related to its ability to
          market the natural gas produced from the wells it drills and natural
          gas and oil prices, which are volatile and uncertain. If natural gas
          and oil prices decrease then your investment return will decrease.

                                       1
o    Unlimited joint and several liability for partnership obligations if
          you choose to invest as an investor general partner until you are
          converted to a limited partner.

     o    Lack of liquidity or a market for the units makes it extremely
          difficult for you to sell your units and necessitates a long-term
          investment commitment from you.

     o    Total reliance on the managing general partner and its affiliates to
          manage each partnership and its business.

     o    Authorization of substantial fees to the managing general partner and
          its affiliates.

     o    Possible allocation of taxable income to you and the other investors
          in excess of your respective cash distributions from a partnership.

     o    Each partnership must receive minimum subscription proceeds of $2
          million to close this offering, and the subscription proceeds of all
          partnerships, in the aggregate, may not exceed $200 million. There are
          no other requirements regarding the size of a partnership, and the
          subscription proceeds of one partnership may be substantially more or
          less than the subscription proceeds of the other partnership. If only
          the minimum subscription proceeds are received by a partnership, its
          ability to spread the risks of drilling will be greatly reduced as
          described in "Compensation - Drilling Contracts."

     o    There are certain conflicts of interest between the managing general
          partner and you and the other investors, and a lack of procedures to
          resolve the conflicts.

     o    You and the other investors and the managing general partner will
          share in a partnership's costs disproportionately to the sharing of
          its revenues.

     o    Currently, the partnerships do not hold any interests in any
          properties or prospects on which the wells will be drilled. Although
          the managing general partner has absolute discretion in determining
          which properties or prospects will be drilled by a partnership, the
          managing general partner intends that Atlas America Public #16-2007(A)
          L.P. will drill the prospects described in "Appendix A - Information
          Regarding Currently Proposed Prospects for Atlas America Public
          #16-2007(A) L.P." These prospects represent a portion of the wells to
          be drilled if the nonbinding targeted maximum subscription proceeds
          described in "Terms of the Offering - Subscription to a Partnership"
          are received. If there are material adverse events with respect to any
          of the currently proposed prospects before drilling begins on the
          prospect, the managing general partner will substitute a new prospect.
          The managing general partner also anticipates that it will designate a
          portion of the prospects in Atlas America Public #16-2007(B) L.P. by a
          supplement or an amendment to the registration statement of which this
          prospectus is a part.

     o    In each partnership the managing general partner may subordinate a
          portion of its share of that partnership's net production revenues to
          increase that partnership's distributions to you and the other
          investors. This subordination, however, is not a guaranty by the
          managing general partner of your distributions from that partnership.
          If the wells in that partnership produce small volumes of natural gas
          and oil and/or natural gas and oil prices decrease, then even with
          subordination your cash flow from the partnership may not return the
          intended distributions during the subordination period or, over the
          term of the partnership, all of your investment.

     o    In each partnership monthly cash distributions to its investors may be
          deferred if revenues are used for partnership operations or reserves.

                                       2
TERMS OF THE OFFERING

The time period for the offer and sale of the first partnership's units will
begin on the date of this prospectus. Each partnership will offer a minimum of
200 units, which is $2 million, and the partnerships, in the aggregate, will
offer a maximum of 20,000 units which is $200 million. The maximum subscription
proceeds for each partnership will be the lesser of:

     o    the amount of $200 million; or

     o    $200 million less the amount of subscriptions sold in the preceding
          partnership.

The targeted subscription proceeds and closing date for each partnership, which
are not binding on the managing general partner, are set forth in a table in
"Terms of the Offering - Subscription to a Partnership."

Units are offered at a subscription price of $10,000 per unit, provided that up
to 5% of the units in each partnership in this offering may be sold to certain
investors at discounted prices as described in "Plan of Distribution." All
subscriptions must be paid 100% in cash at the time of subscribing. Your minimum
subscription in a partnership is one unit ($10,000). Larger fractional
subscriptions will be accepted in $1,000 increments, beginning, for example,
with $11,000, $12,000, etc.

You may elect to purchase units as either an investor general partner or a
limited partner as described in "- Description of Units," below. Under the
partnership agreement no investor, including investor general partners, may
participate in the management of a partnership or its business. The managing
general partner will have exclusive management authority for the partnerships.

Each partnership has been formed as a limited partnership under the Delaware
Revised Uniform Limited Partnership Act. Subscription proceeds for each
partnership will be held in a separate interest bearing escrow account at
National City Bank of Pennsylvania until receipt of the minimum subscription
proceeds, excluding any subscriptions by the managing general partner or its
affiliates. On receipt of the minimum subscription proceeds, the managing
general partner on behalf of a partnership may break escrow, transfer the
escrowed subscription proceeds to a partnership account, and begin the
partnership's activities, including drilling. After breaking escrow, additional
subscription proceeds may be paid directly to a partnership account for that
partnership and will continue to earn interest until the final closing date of
the offering of units in that partnership. (See "Terms of the Offering.") If
subscription proceeds of $2 million are not received by the offering termination
date for your partnership, then your subscription amount will be promptly
returned to you from the escrow account with interest and without deduction for
any fees.

DESCRIPTION OF UNITS

On subscribing for units in the partnership being offered at the time, you may
elect to buy either:

     o    investor general partner units; or

     o    limited partner units.

The partnerships will not issue certificates for their units, but your ownership
of your unit(s) will be recorded on the partnership's books and records. Also,
the type of unit you buy will not affect the allocation of your partnership's
costs, revenues, and cash distributions among you and its other investors. There
are, however, material differences in the federal income tax effects and
liability associated with each type of unit.

INVESTOR GENERAL PARTNER UNITS.

     o    TAX EFFECT. If you invest in a partnership as an investor general
          partner, then your share of the partnership's deduction for intangible
          drilling costs will not be subject to the passive activity limitations
          on losses. For example, if you pay $10,000 for a unit, then generally
          you may deduct not less than 90% of your subscription amount, $9,000
          per unit, in the year in which you invest, which includes your
          deduction for intangible drilling costs for all of the wells to be
          drilled by the

                                       3
partnership. (See "Federal Income Tax Consequences - Limitations on
          Passive Activity Losses and Credits.")

          o    Intangible drilling costs generally means those costs of drilling
               and completing a well that are currently deductible, as compared
               to lease costs which must be recovered through the depletion
               allowance and costs for equipment in the well which must be
               recovered through depreciation deductions.

     o    LIABILITY. If you invest in a partnership as an investor general
          partner, then you will have unlimited liability regarding the
          partnership's activities. This means that if:

          o    the partnership's insurance proceeds from any source;

          o    the managing general partner's indemnification of you and the
               other investor general partners; and

          o    the partnership's assets;

          were not sufficient to satisfy a partnership liability for which you
          and the other investor general partners were also liable solely
          because of your status as general partners of the partnership, then
          the managing general partner would require you and the other investor
          general partners to make additional capital contributions to the
          partnership to satisfy the liability. In addition, you and the other
          investor general partners will have joint and several liability, which
          means generally that a person with a claim against the partnership may
          sue all or any one or more of the partnership's general partners,
          including you, for the entire amount of the liability. (See "Actions
          To Be Taken By Managing General Partner To Reduce Risks of Additional
          Payments by Investor General Partners" and "Proposed Activities -
          Insurance.")

     Although past performance is no guarantee of future results, the investor
     general partners in the managing general partner's prior partnerships have
     not had to make any additional capital contributions to their partnerships
     because of their status as investor general partners. (See "Prior
     Activities.")

     Your investor general partner units in a partnership will be automatically
     converted by the managing general partner to limited partner units after
     all of that partnership's wells have been drilled and completed. The
     conversion will not create any tax liability to you or the other investors.

     Once your units are converted, you will have the lesser liability of a
     limited partner under Delaware law for partnership obligations and
     liabilities arising after the conversion. However, you will continue to
     have the responsibilities of a general partner for partnership liabilities
     and obligations incurred before the effective date of the conversion. For
     example, you might become liable for partnership liabilities in excess of
     your subscription amount during the time the partnership is engaged in
     drilling activities and for environmental claims that arose during drilling
     activities, but were not discovered until after the conversion.

LIMITED PARTNER UNITS.

     o    TAX EFFECT. If you invest in a partnership as a limited partner, then
          your use of your share of the partnership's deduction for intangible
          drilling costs will be limited to offsetting your net passive income
          from "passive" trade or business activities. Passive trade or business
          activities generally include the partnership and other limited partner
          investments, but passive income does not include salaries, dividends
          or interest. This means that you will not be able to deduct your share
          of the partnership's intangible drilling costs in the year in which
          you invest unless you have net passive income from investments other
          than the partnership. However, any portion of your share of the
          partnership's deduction for intangible drilling costs that you cannot
          use in the year in which you invest, because you do not have
          sufficient net

                                       4
passive income in that year, may be carried forward by you and used to
          offset your net passive income from the partnership or your other
          passive activities, if any, in subsequent tax years. (See "Federal
          Income Tax Consequences - Limitations on Passive Activity Losses and
          Credits.")

     o    LIABILITY. If you invest in a partnership as a limited partner, then
          you will have limited liability for the partnership's liabilities and
          obligations. This means that you will not be liable for any
          partnership liabilities or obligations beyond the amount of your
          initial investment in the partnership and your share of the
          partnership's undistributed net profits, subject to certain exceptions
          set forth in "Summary of Partnership Agreement - Liability of Limited
          Partners."

USE OF PROCEEDS

Each partnership must receive minimum subscription proceeds of $2 million to
close, and the subscription proceeds of both partnerships, in the aggregate, may
not exceed $200 million. The subscription proceeds of one partnership may be
substantially more or less than the subscription proceeds of the other
partnerships and the managing general partner has the discretion to accept
subscriptions for up to and including the entire amount in Atlas America Public
#16-2007(A) L.P. and not offer and sell any units in Atlas America Public
#16-2007(B) L.P. In each partnership, regardless of whether the partnership
receives the minimum or the maximum subscription proceeds from you and the other
investors:

     o    90% of the subscription proceeds will be used to pay 100% of the
          intangible drilling costs, as defined above in "- Description of
          Units," of drilling and completing the partnership's wells; and

     o    10% of the subscription proceeds will be used to pay a portion of the
          equipment costs of drilling and completing the partnership's wells.

The managing general partner will contribute all of the leases to each
partnership covering the acreage on which that partnership's wells will be
drilled and pay all of the equipment costs of drilling and completing the
partnership's wells that exceed 10% of the partnership's subscription proceeds.
Thus, the managing general partner will pay the majority of each partnership's
equipment costs. The managing general partner also will be charged with 100% of
the organization and offering costs for each partnership. A portion of these
contributions to each partnership will be in the form of payments to itself, its
affiliates and third-parties and the remainder will be in the form of services
related to organizing this offering. The managing general partner will receive a
credit towards its required capital contribution to each partnership for these
payments and services as discussed in "Participation in Costs and Revenues."
(See "Capitalization and Source of Funds and Use of Proceeds" and "Federal
Income Tax Consequences - Intangible Drilling Costs.")

FIVE YEAR-50% SUBORDINATION, PARTICIPATION IN COSTS AND REVENUES, AND
DISTRIBUTIONS

Each partnership will be a separate business entity from the other partnerships,
and you will be a partner only in the partnership in which you invest. You will
have no interest in the business, assets or tax benefits of the other
partnership unless you also invest in the other partnership. Thus, your
investment return will depend solely on the operations and success or lack of
success of the particular partnership in which you invest. Each partnership is
structured to provide you and its other investors with cash distributions equal
to a minimum of 10% of capital, based on a subscription price of $10,000 per
unit, regardless of the actual subscription price you paid for your units, in
each of the first five 12-month periods beginning with the partnership's first
cash distribution from operations. To help achieve this investment feature of a
10% return of capital in each of the first five 12-month periods, the managing
general partner will subordinate up to 50% of its share of partnership net
production revenues, which will be up to between 16% and 20% of total
partnership net production revenues, depending on the amount of the managing
general partner's capital contribution to that partnership, during this
subordination period. (See "Participation in Costs and Revenues - Subordination
of Portion of Managing General Partner's Net Revenue Share.")

Each partnership's 60-month subordination period will begin with the
partnership's first cash distribution from operations to you and its other
investors. Subordination distributions will be determined by debiting or
crediting current period partnership revenues to the managing general partner as
may be necessary to provide the distributions to you and the other investors. At
any time during the subordination period, but not after, the managing general
partner is entitled to an

                                       5
additional share of partnership revenues to recoup previous subordination
distributions to the extent your cash distributions from the partnership exceed
the 10% return of capital described above. The specific formula for determining
subordination distributions is set forth in Section 5.01(b)(4)(a) of the
partnership agreement.

The following table sets forth how the partnership's costs and revenues will be
charged and credited between the managing general partner and you and the other
investors for each partnership after deducting from the partnership's gross
revenues the landowner royalties and any other lease burdens.

                                                       MANAGING
                                                        GENERAL
                                                        PARTNER   INVESTORS
                                                       --------   ---------
PARTNERSHIP COSTS
Organization and offering costs.....................     100%          0%
Lease costs.........................................     100%          0%
Intangible drilling costs (1).......................       0%        100%
Equipment costs.....................................      (2)         (2)
Operating costs, administrative costs, direct costs,
   and all other costs..............................      (3)         (3)

PARTNERSHIP REVENUES
Interest income.....................................      (4)         (4)
Equipment proceeds..................................      (2)         (2)
All other revenues including production revenues....      (5)(6)      (5)(6)

----------
(1)  Ninety percent of the subscription proceeds of you and the other investors
     in the partnership in which you subscribe will be used to pay 100% of the
     intangible drilling costs incurred by that partnership in drilling and
     completing its wells.

(2)  Ten percent of the subscription proceeds of you and the other investors in
     the partnership in which you subscribe will be used to pay a portion of the
     equipment costs incurred by that partnership in drilling and completing its
     wells. All equipment costs in excess of 10% of the partnership's
     subscription proceeds will be paid by the managing general partner. Thus,
     the managing general partner will pay a majority of each partnership's
     equipment costs. Equipment proceeds, if any, will be credited in the same
     percentage in which the equipment costs were charged. Thus, the managing
     general partner will receive a majority of any equipment proceeds.

(3)  These costs will be charged to the parties in the same ratio as the related
     production revenues are being credited. These costs also include the
     plugging and abandonment costs of the wells after their economic reserves
     have been produced and depleted as described in "Participation in Costs and
     Revenues."

(4)  Interest earned on your subscription proceeds before the final closing of
     the partnership to which you subscribed will be credited to your account
     and paid to you not later than the partnership's first cash distribution
     from operations. After each closing of a partnership, and until the
     subscription proceeds from the closing are invested in the partnership's
     natural gas and oil operations, any interest income from temporary
     investments will be allocated pro rata to the investors providing the
     subscription proceeds. All other interest income, including interest earned
     on the deposit of operating revenues, will be credited as natural gas and
     oil production revenues are credited.

(5)  The managing general partner and you and the other investors in a
     partnership will share in all of that partnership's other revenues in the
     same percentage as their respective capital contributions bears to the
     partnership's total capital contributions, except that the managing general
     partner will receive an additional 7% of the partnership revenues. However,
     the managing general partner's total revenue share may not exceed 40% of
     partnership revenues.

(6)  The actual allocation of partnership revenues between the managing general
     partner and you and the other investors will vary from the allocation
     described in (5) above if a portion of the managing general partner's share
     of partnership net production revenues is subordinated as described above.

The managing general partner will review each partnership's accounts at least
monthly to determine whether cash distributions are appropriate and the amount
to be distributed, if any. The partnership in which you invest will distribute

                                       6
funds to you and its other investors that the managing general partner does not
believe are necessary for the partnership to retain. (See "Participation in
Costs and Revenues.")

COMPENSATION

The items of compensation paid to the managing general partner and its
affiliates from each partnership are as follows:

     o    The managing general partner will receive a share of each
          partnership's revenues. The managing general partner's revenue share
          will be in the same percentage as its capital contribution bears to
          that partnership's total capital contributions plus an additional 7%
          of partnership revenues. However, the managing general partner's
          revenue share may not exceed a total of 40% of partnership revenues,
          regardless of the amount of the managing general partner's capital
          contribution, and a portion of the managing general partner's revenue
          share will be subject to the its subordination obligation.

     o    The managing general partner will receive a credit to its capital
          account in an amount equal to the cost of the leases contributed to a
          partnership by the managing general partner, or the fair market value
          of the leases if the managing general partner has reason to believe
          that cost is materially more than the fair market value.

     o    Each partnership will enter into the drilling and operating agreement
          with the managing general partner to drill and complete the
          partnership's wells at competitive rates as described in "Compensation
          - Drilling Contracts."

     o    When a partnership's wells begin producing natural gas or oil in
          commercial quantities, the managing general partner, as operator of
          the wells, will receive:

          o    reimbursement at actual cost for all direct expenses incurred by
               it on behalf of the partnership; and

          o    well supervision fees for operating and maintaining the wells
               during producing operations at a competitive rate.

     o    The managing general partner will receive gathering fees at
          competitive rates for its services in gathering and transporting a
          partnership's natural gas production.

     o    Subject to certain exceptions described in "Plan of Distribution,"
          Anthem Securities, Inc., the dealer-manager and an affiliate of the
          managing general partner, which is sometimes referred to in this
          prospectus as "Anthem Securities," will receive on each unit sold to
          an investor a 2.5% dealer-manager fee, a 7% sales commission and up to
          a .5% reimbursement of the selling agents' bona fide due diligence
          expenses.

     o    The managing general partner or an affiliate will have the right to
          charge a competitive rate of interest on any loan it may make to or on
          behalf of a partnership. If the managing general partner provides
          equipment, supplies, and other services to a partnership, then it may
          do so at competitive industry rates.

     o    The managing general partner and its affiliates will receive a
          nonaccountable, fixed payment reimbursement for their administrative
          costs, which has been determined by the managing general partner to be
          $75 per well per month. The managing general partner may not increase
          this fee during the term of the partnership.

(See "Compensation.")

                                       7
RISK FACTORS

An investment in a partnership involves a high degree of risk and is suitable
only if you have substantial financial means and no need of liquidity in your
investment.

RISKS RELATED TO THE PARTNERSHIPS' OIL AND GAS OPERATIONS

NO GUARANTEE OF RETURN OF INVESTMENT OR RATE OF RETURN ON INVESTMENT BECAUSE OF
SPECULATIVE NATURE OF DRILLING NATURAL GAS AND OIL WELLS. Natural gas and oil
exploration is an inherently speculative activity. Before the drilling of a well
the managing general partner cannot predict with absolute certainty:

     o    the volume of natural gas and oil recoverable from the well; or

     o    the time it will take to recover the natural gas and oil.

You may not recover all of your investment in a partnership, or if you do
recover your investment in a partnership you may not receive a rate of return on
your investment that is competitive with other types of investment. You will be
able to recover your investment only through distributions of the partnership's
net proceeds from the sale of its natural gas and oil from productive wells. The
quantity of natural gas and oil in a well, which is referred to as its reserves,
decreases over time as the natural gas and oil is produced until the well is no
longer economical to operate. All of these distributions to you will be
considered a return of capital until you have received 100% of your investment.
This means that you are not receiving a return on your investment in a
partnership, excluding tax benefits, until your total cash distributions from
the partnership exceed 100% of your investment. (See "Prior Activities.")

BECAUSE SOME WELLS MAY NOT RETURN THEIR DRILLING AND COMPLETION COSTS, IT MAY
TAKE MANY YEARS TO RETURN YOUR INVESTMENT IN CASH, IF EVER. Even if a well is
completed in a partnership and produces natural gas and oil in commercial
quantities, it may not produce enough natural gas and oil to pay for the costs
of drilling and completing the well, even if tax benefits are considered. For
example, the managing general partner has formed 54 partnerships since 1985,
however, 38 of the 54 partnerships have not yet returned to the investor 100% of
his capital contributions without taking tax savings into account. Thus, it may
take many years to return your investment in cash, if ever. The partnerships'
primary drilling areas are located in the most active drilling areas in the
Appalachian Basin. As a result, many of the leases which will be drilled by a
partnership are in areas that have already been partially depleted or drained by
earlier offset drilling. This may reduce a partnership's ability to find
economically recoverable quantities of natural gas in those areas. (See "Prior
Activities.")

NONPRODUCTIVE WELLS MAY BE DRILLED EVEN THOUGH THE PARTNERSHIPS' OPERATIONS ARE
PRIMARILY LIMITED TO DEVELOPMENT DRILLING. Each partnership may drill some
development wells that are nonproductive, which is referred to as a "dry hole,"
and must be plugged and abandoned. If one or more of a partnership's wells are
nonproductive, then the partnership's productive wells may not produce enough
revenues to offset the loss of investment in the nonproductive wells. (See
"Prior Activities.")

PARTNERSHIP DISTRIBUTIONS MAY BE REDUCED IF THERE IS A DECREASE IN THE PRICE OF
NATURAL GAS AND OIL. The prices at which a partnership's natural gas and oil
will be sold are uncertain and, as discussed in "- Adverse Events in Marketing a
Partnership's Natural Gas Could Reduce Partnership Distributions," the
partnerships are not guaranteed a specific natural gas price for the sale of
their natural gas production. Changes in natural gas and oil prices will have a
significant impact on a partnership's cash flow and the value of its reserves.
Lower natural gas and oil prices may not only decrease a partnership's revenues,
but also may reduce the amount of natural gas and oil that a partnership can
produce economically. Historically, natural gas and oil prices have been
volatile and it is likely that they will continue to be volatile in the future.
Prices for natural gas and oil will depend on supply and demand factors largely
beyond the control of the partnerships and prices may fluctuate widely in
response to:

     o    relatively minor changes in the supply of and demand for natural gas
          or oil;

     o    market uncertainty; and

                                       8
o    a variety of additional factors that are beyond a partnership's
          control, as described in "Competition, Markets and Regulations -
          Competition and Markets."

These factors make it extremely difficult to predict natural gas and oil price
movements with any certainty.

If natural gas and oil prices decrease in the future, then your partnership
distributions will decrease accordingly. Also, natural gas and oil prices may
decrease during the first years of production from your partnership's wells
which is when the wells typically achieve their greatest level of production.
This would have a greater adverse effect on your partnership distributions than
price decreases in later years when the wells have a lower level of production.
Also, your return level will decrease during the term of the partnership, even
if there are rising natural gas prices, because of declining production volumes
from the wells over time. See "Appendix A - Information Regarding Currently
Proposed Prospects for Atlas America Public #16-2007(A) L.P." for a discussion
of flush production and "Proposed Activities - Sale of Natural Gas and Oil
Production." Further, as discussed in "Federal Income Tax Consequences -
Depletion Allowance," the managing general partner has represented that most, if
not all, of the natural gas and oil production from your partnership's
productive wells will be marginal production under the Internal Revenue Code and
could qualify for potentially higher rates of percentage depletion. Thus, the
partnership will be more sensitive to price declines than if its wells produced
at a higher average rate of production that did not qualify for the potentially
higher rate of percentage depletion.

ADVERSE EVENTS IN MARKETING A PARTNERSHIP'S NATURAL GAS COULD REDUCE PARTNERSHIP
DISTRIBUTIONS. In addition to the risk of decreased natural gas and oil prices
described above, certain material adverse events in marketing a partnership's
natural gas could reduce a partnership's distributions to you and its other
investors. These risks are set forth below.

     o    Competition from other natural gas producers and marketers in the
          Appalachian Basin, as well as competition from alternative energy
          sources, may make it more difficult to market each partnership's
          natural gas.

     o    The majority of each partnership's natural gas production and that of
          the managing general partner will be sold to a limited number of
          different natural gas purchasers as described in "Proposed Activities
          - Sale of Natural Gas and Oil Production." As set forth in "Appendix A
          - Information Regarding Currently Proposed Prospects for Atlas America
          Public #16-2007(A) L.P.," the managing general partner has identified
          three primary areas where it intends to drill each partnership's
          wells. The managing general partner anticipates that each
          partnership's natural gas production in each of the three primary
          areas initially will be sold to a different purchaser or purchasers in
          each area. Each partnership will depend on a limited number of natural
          gas purchasers. If a partnership loses a natural gas purchaser in a
          given area, the partnership may be unable to locate a new natural gas
          purchaser in the area that will buy the partnership's natural gas on
          as favorable terms as the initial purchaser.

          Although one of the partnership's natural gas purchasers has a 10-year
          agreement, which began on April 1, 1999, to buy all of the managing
          general partner's and its affiliates' natural gas production, there
          are various exceptions to its obligation to buy the natural gas. The
          most significant exception for each partnership includes natural gas
          produced from the Fayette County, Pennsylvania area, which is where
          the managing general partner anticipates that the majority of each
          partnership's prospects will be situated. The majority of the natural
          gas produced from the Fayette County area by each partnership
          initially will be sold to four different purchasers under natural gas
          contracts described in "Proposed Activities - Sale of Natural Gas and
          Oil Production." Of the remaining two primary areas, there will be a
          different natural gas purchaser in each area and natural gas produced
          from only one of those areas will be sold under the 10-year agreement
          referred to above.

          Also, all of these natural gas purchase contracts provide that the
          price paid by the natural gas purchaser may be adjusted upward or
          downward in accordance with the spot market price and market
          conditions as described in "Proposed Activities - Sale of Natural Gas
          and Oil Production." Thus, the partnerships will not be guaranteed a
          specific natural gas price, other than through hedging or forward
          sales transactions

                                       9
through the natural gas purchasers (which is not considered hedging
          for accounting purposes), and the price a partnership receives for the
          sale of its natural gas may decrease in the future because of market
          conditions. Although hedging and forward sales transactions provide
          the partnerships some protection against falling natural gas prices,
          those arrangements also could reduce the potential benefits of price
          increases if, at the time the natural gas is to be delivered, the spot
          market natural gas price is higher than the price paid under the
          hedging arrangements or forward sales transactions. Also, the
          partnership could incur liability on the financial hedges.

     o    There is a credit risk associated with a natural gas purchaser's
          ability to pay. Each partnership may not be paid, or may experience
          delays in receiving payment, for its natural gas that has already been
          delivered to the purchaser. In accordance with industry practice, a
          partnership typically will deliver natural gas to a purchaser for a
          period of up to 60 to 90 days before it receives payment. Thus, it is
          possible that the partnership may not be paid for natural gas that
          already has been delivered if the natural gas purchaser fails to pay
          for any reason, including bankruptcy. This ongoing credit risk also
          may delay or interrupt the sale of the partnership's natural gas or
          the partnership's negotiation of different terms and arrangements for
          selling its natural gas to other purchasers. Finally, this credit risk
          may reduce the price benefit derived by the partnerships from the
          managing general partner's natural gas hedging arrangements as
          described in "Proposed Activities - Sale of Natural Gas and Oil
          Production - Natural Gas Contracts," since from time to time the
          managing general partner has implemented a portion of its natural gas
          hedges through the natural gas purchasers.

     o    A partnership's net revenues will decrease the farther its natural gas
          is transported for sale because of increased transportation costs.

     o    Production from wells drilled in certain areas, such as wells drilled
          in the Crawford County, Pennsylvania area and, to a lesser extent, the
          Fayette County, Pennsylvania and Anderson, Campbell, Morgan, Scott and
          Roane Counties, Tennessee area, may be delayed until construction of
          the necessary gathering lines and production facilities is completed.
          (See "Proposed Activities - Sale of Natural Gas and Oil Production -
          Gathering of Natural Gas.")

     o    The managing general partner anticipates that it will use the
          gathering system owned by Atlas Pipeline Partners for the majority of
          a partnership's natural gas as described in "Proposed Activities -
          Sale of Natural Gas and Oil Production - Gathering of Natural Gas."
          Atlas Pipeline Partners GP, LLC, a wholly-owned subsidiary of Atlas
          Pipeline Holdings, L.P., an affiliate of Atlas America, Inc., which is
          sometimes referred to in this prospectus as "Atlas America" and is the
          indirect parent company of the managing general partner, controls and
          manages the gathering system for Atlas Pipeline Partners. (See
          "Management - Organizational Diagram and Security Ownership of
          Beneficial Owners.") However, Atlas Pipeline Holdings, L.P., as a
          public company, may be more susceptible to a change of control from
          Atlas America's affiliates to independent third-parties.

          Also, certain of the managing general partner's affiliates, including
          Atlas America, are obligated through their agreement with Atlas
          Pipeline Partners to pay the difference between the amount a
          partnership pays for gathering fees to the managing general partner as
          set forth in "Compensation - Gathering Fees," and the greater of $.35
          per mcf or 16% of the gross sales price for the natural gas. This
          creates a conflict of interest between the managing general partner
          and a partnership because the managing general partner has an economic
          incentive to increase the amount of gathering fees paid by a
          partnership so as to reduce the amount of gathering fees paid by Atlas
          America to Atlas Pipeline Partners, but any increase cannot exceed a
          competitive rate. Further, if Atlas Pipeline Partners GP, LLC were
          removed as general partner of Atlas Pipeline Partners without cause
          and without its consent, this could create further pressure to
          increase the amount of gathering fees required to be paid by the
          partnerships for natural gas transported through Atlas Pipeline
          Partners' gathering system since Atlas Pipeline Partners GP, LLC would
          no longer receive revenues from Atlas Pipeline Partners, but Atlas
          America and its affiliates would be obligated to pay the

                                       10
difference between the amount in the master natural gas gathering
          agreement and the amount paid by a partnership other than with respect
          to new wells drilled, if any, by the partnership after the removal of
          Atlas Pipeline Partners GP, LLC as general partner of Atlas Pipeline
          Partners. Thus, the managing general partner and its affiliates would
          have an incentive to increase the gathering fees charged to a
          partnership. Any increase in the gathering fees that your partnership
          pays, which cannot exceed competitive rates, would reduce your cash
          distributions from the partnership.

POSSIBLE LEASEHOLD DEFECTS. There may be defects in a partnership's title to its
leases. Although the managing general partner will obtain a favorable formal
title opinion for the leases before each well is drilled, it will not obtain a
division order title opinion after the well is completed. Thus, a partnership
may experience losses from title defects which arose during drilling that would
have been disclosed by a division order title opinion, such as liens arising
during drilling operations or transfers of interests in the leases after
drilling begins. Also, the managing general partner may use its own judgment in
waiving title requirements for a partnership's leases and it will not be liable
for any failure of title of leases transferred to a partnership. (See "Proposed
Activities - Title to Properties.")

TRANSFER OF THE LEASES WILL NOT BE MADE UNTIL WELL IS COMPLETED. Because the
leases will not be transferred from the managing general partner to a
partnership until after the wells are drilled and completed, the transfer could
be set aside by a creditor of the managing general partner, or the trustee in
the event of the voluntary or involuntary bankruptcy of the managing general
partner, if it were determined that the managing general partner received less
than a reasonably equivalent value for the leases. In this event, the leases and
the wells would revert to the creditors or trustee, and the partnership would
either recover nothing or only the amount it paid for the leases and the cost of
drilling the wells. Assigning the leases to a partnership after the wells are
drilled and completed, however, will not affect the availability of the tax
deductions for intangible drilling costs since the partnership will have an
economic interest in the wells under the drilling and operating agreement before
the wells are drilled. (See "Proposed Activities - Title to Properties.")

PARTICIPATION WITH THIRD-PARTIES IN DRILLING WELLS MAY REQUIRE THE PARTNERSHIPS
TO PAY ADDITIONAL COSTS. Third-parties will participate with each partnership in
drilling some of the well and additional financial risks exist when the costs of
drilling, equipping, completing, and operating wells is shared by more than one
person. If a partnership pays its share of the costs, but another interest owner
does not pay its share of the costs, then the partnership would have to pay the
costs of the defaulting party. In this event, the partnership would receive the
defaulting party's revenues from the well, if any, under penalty arrangements
set forth in the operating agreement, which may, or may not, cover all of the
additional costs paid by the partnership.

If the managing general partner is not the actual operator of the well for all
of the working interest owners of the well, then there is a risk that the
managing general partner cannot supervise the third-party operator closely
enough. For example, decisions related to the following would be made by the
third-party operator and may not be in the best interests of the partnerships
and you and the other investors:

     o    how the well is operated;

     o    expenditures related to the well; and

     o    possibly the marketing of the natural gas and oil production from the
          well.

Further, the third-party operator may have financial difficulties and fail to
pay for materials or services on the wells it drills or operates, which would
cause the partnership to incur extra costs in discharging materialmen's and
workmen's liens. The managing general partner may not be the operator of the
well for all of the working interest owners of the well if the partnership owns
less than a 50% working interest in the well, or if the managing general partner
acquired the working interest in the well from a third-party under arrangements
that required the third-party to be named operator as one of the terms of the
acquisition.

                                       11
RISKS RELATED TO AN INVESTMENT IN A PARTNERSHIP

IF YOU CHOOSE TO INVEST AS A GENERAL PARTNER, THEN YOU HAVE GREATER RISK THAN A
LIMITED PARTNER. If you elect to invest in a partnership as an investor general
partner for the tax benefits instead of as a limited partner, then under
Delaware law you will have unlimited liability for your partnership's activities
until you are converted to limited partner status, subject to certain exceptions
described in "Actions To Be Taken by Managing General Partner To Reduce Risks of
Additional Payments By Investor General Partners - Conversion of Investor
General Partner Units to Limited Partner Units." This could result in you being
required to make payments, in addition to your original investment, in amounts
that are impossible to predict because of their uncertain nature. Under the
terms of the partnership agreement, if you are an investor general partner you
agree to pay only your proportionate share, as among all of your partnership's
investor general partners, of your partnership's obligations and liabilities.
This agreement, however, does not eliminate your liability to third-parties if
another investor general partner does not pay his proportionate share of your
partnership's obligations and liabilities.

Also, each partnership will own less than 100% of the working interest in some
of its wells. If a court holds you and the other third-party working interest
owners of the well liable for the development and operation of a well and the
third-party working interest owners do not pay their proportionate share of the
costs and liabilities associated with the well, then the partnership and you and
the other investor general partners also would be liable for those costs and
liabilities.

As an investor general partner you may become subject to the following:

     o    contract liability, which is not covered by insurance;

     o    liability for pollution, abuses of the environment, and other
          environmental damages as discussed in "Competition, Markets and
          Regulation - Environmental Regulation, including but not limited to
          the release of toxic gas, spills or uncontrollable flows of natural
          gas, oil or well fluids, including underground or surface
          contamination, against which the managing general partner cannot
          insure because coverage is not available or against which it may elect
          not to insure because of high premium costs or other reasons; and

     o    liability for drilling hazards that result in property damage,
          personal injury, or death to third-parties in amounts greater than the
          insurance coverage. The drilling hazards include, but are not limited
          to, well blowouts, fires, craterings and explosions.

If your partnership's insurance proceeds and assets, the managing general
partner's indemnification of you and the other investor general partners, and
the liability coverage provided by major subcontractors were not sufficient to
satisfy the liability, then the managing general partner would call for
additional funds from you and the other investor general partners to satisfy the
liability. (See "Actions To Be Taken By Managing General Partner To Reduce Risks
of Additional Payments by Investor General Partners.") Additionally, any of the
drilling hazards may result in the loss of the well and the associated revenues.

THE MANAGING GENERAL PARTNER MAY NOT MEET ITS CAPITAL CONTRIBUTIONS,
INDEMNIFICATION AND PURCHASE OBLIGATIONS IF ITS LIQUID NET WORTH IS NOT
SUFFICIENT. The managing general partner has made commitments to you and the
other investors in each partnership regarding the following:

     o    the payment of organization and offering costs and the majority of
          equipment costs;

     o    indemnification of the investor general partners for liabilities in
          excess of their pro rata share of partnership assets and insurance
          proceeds; and

     o    purchasing units presented by an investor, although this feature may
          be suspended by the managing general partner if it determines, in its
          sole discretion, that it does not have the necessary cash flow or
          cannot borrow funds for this purpose on reasonable terms.

A significant financial reversal for the managing general partner could
adversely affect its ability to honor these obligations.

                                       12
The managing general partner's net worth is based primarily on the estimated
value of its producing natural gas properties and is not available in cash
without borrowings or a sale of the properties. Also, if natural gas prices
decrease, then the estimated value of the properties and the managing general
partner's net worth will be reduced. Further, price decreases will reduce the
managing general partner's revenues, and may make some reserves uneconomic to
produce. This would reduce the managing general partner's reserves and cash
flow, and could cause the lenders of the managing general partner and its
affiliates to reduce the borrowing base for the managing general partner and its
affiliates. Also, because the majority of the managing general partner's proved
reserves are currently natural gas reserves, the managing general partner's net
worth is more susceptible to movements in natural gas prices than in oil prices.

The managing general partner's net worth may not be sufficient, either currently
or in the future, to meet its financial commitments under the partnership
agreement. These risks are increased because the managing general partner has
made similar financial commitments in most of its other partnerships and will
make this same commitment in future partnerships. See "Financial Information
Concerning the Managing General Partner and Atlas America Public #16-2007(A)
L.P."

AN INVESTMENT IN A PARTNERSHIP MUST BE FOR THE LONG-TERM BECAUSE THE UNITS ARE
ILLIQUID AND NOT READILY TRANSFERABLE. If you invest in a partnership, then you
must assume the risks of an illiquid investment. The transferability of the
units is limited by the securities laws, the tax laws, and the partnership
agreement. The units generally cannot be liquidated since there is not a readily
available market for the sale of the units. Further, the partnerships do not
intend to list the units on any exchange. (See "Transferability of Units -
Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the
Partnership Agreement.")

Also, a sale of your units could create adverse tax and economic consequences
for you. The sale or exchange of all or part of your units held for more than 12
months generally will result in a recognition of long-term capital gain or loss.
However, previous deductions for depreciation, depletion and intangible drilling
costs may be recaptured as ordinary income rather than capital gain regardless
of how long you have owned your units. If you have held your units for 12 months
or less, then the gain or loss generally will be short-term gain or loss. Also,
your pro rata share of a partnership's liabilities, if any, as of the date of
the sale or exchange of your units must be included in the amount realized by
you. Thus, the gain recognized by you may result in a tax liability greater than
the cash proceeds, if any, received by you from the sale or other disposition of
your units, if permitted under the partnership agreement. (See "Federal Income
Tax Consequences - Disposition of Units" and "Presentment Feature.")

SPREADING THE RISKS OF DRILLING AMONG A NUMBER OF WELLS WILL BE REDUCED IF LESS
THAN THE MAXIMUM SUBSCRIPTION PROCEEDS ARE RECEIVED AND FEWER WELLS ARE DRILLED.
Each partnership must receive minimum subscription proceeds of $2 million to
close the offering, and the subscription proceeds of the partnerships, in the
aggregate, may not exceed $200 million. There are no other requirements
regarding the size of a partnership other than the nonbinding targeted maximum
amounts described in "Terms of the Offering - Subscription to a Partnership."
Thus, the subscription proceeds of one partnership may be substantially more or
less than the subscription proceeds of another partnership. A partnership with a
smaller amount of subscription proceeds will drill fewer wells which decreases
the partnership's ability to spread the risks of drilling. For example, the
managing general partner anticipates that a partnership will drill approximately
seven net wells if the minimum subscriptions of $2 million are received, which
is compared with approximately 710 net wells if subscription proceeds of $200
million are received by a partnership. A gross well is a well in which a
partnership owns a working interest. This is compared with a net well which is
the sum of the fractional working interests owned in the gross wells. For
example, a 50% working interest owned in three wells is three gross wells, but
1.5 net wells.

On the other hand, to the extent more than the minimum subscription proceeds are
received by a partnership and the number of wells drilled increases, the
partnership's overall investment return may decrease if the managing general
partner is unable to find enough suitable wells to be drilled. (See "Proposed
Activities - Acquisition of Leases.") Also, to the extent a partnership's
subscription proceeds and number of wells it drills increase, greater demands
will be placed on the managing general partner's management capabilities.

In addition, the cost of drilling and completing a well is often uncertain and
there may be cost overruns in drilling and completing the wells because the
wells will not be drilled and completed on a turnkey basis for a fixed price,
that would shift

                                       13
certain risks of loss to the managing general partner as drilling contractor.
The majority of the equipment costs of each partnership's wells will be paid by
the managing general partner. However, all of the intangible drilling costs of a
partnership's wells will be charged to you and the other investors in that
partnership. If a partnership incurs a cost overrun for the intangible drilling
costs of a well or wells, then the managing general partner anticipates that it
would use the partnership's subscription proceeds, if available, to pay the cost
overrun or advance the necessary funds to the partnership. Using subscription
proceeds to pay cost overruns charged to you and the other investors under the
partnership agreement will result in a partnership drilling fewer wells.

INCREASES IN THE COSTS OF THE WELLS MAY ADVERSELY AFFECT YOUR RETURN. The
increase in natural gas and oil prices over the last several years has increased
the demand for drilling rigs and other related equipment, and the costs of
drilling and completing natural gas and oil wells also have increased. Because
each partnership's wells will be drilled on a modified cost plus basis as
described in "Compensation - Drilling Contracts," these increased costs will
increase the cost to drill and complete each partnership's wells. Also, the
reduced availability of drilling rigs and other related equipment may make it
more difficult to drill a partnership's wells in a timely manner or to comply
with the prepaid intangible drilling costs rules discussed in "Federal Income
Tax Consequences - Drilling Contracts."

THE PARTNERSHIPS DO NOT OWN ANY PROSPECTS, THE MANAGING GENERAL PARTNER HAS
COMPLETE DISCRETION TO SELECT WHICH PROSPECTS ARE ACQUIRED BY A PARTNERSHIP, AND
THE POSSIBLE LACK OF INFORMATION FOR A MAJORITY OF THE PROSPECTS DECREASES YOUR
ABILITY TO EVALUATE THE FEASIBILITY OF A PARTNERSHIP. The partnerships do not
currently hold any interests in any prospects on which the wells will be
drilled, and the managing general partner has absolute discretion in determining
which prospects will be acquired to be drilled. The managing general partner has
identified in "Proposed Activities" the general areas where each partnership
will drill wells and the managing general partner intends that Atlas America
Public #16-2007(A) L.P. will drill the prospects described in "Appendix A -
Information Regarding Currently Proposed Prospects for Atlas America Public
#16-2007(A) L.P." These prospects represent the wells currently proposed to be
drilled if a portion of the targeted nonbinding amount of subscription proceeds
is received by Atlas America Public #16-2007(A) L.P. as described in "Terms of
the Offering - Subscription to a Partnership."

If there are material adverse events with respect to any of the currently
proposed prospects, the managing general partner will substitute a new prospect.
The managing general partner also anticipates that it will designate a portion
of the prospects in Atlas America Public #16-2007(B) L.P., if units are offered
in that partnership, by a supplement or an amendment to the registration
statement of which this prospectus is a part. With respect to the identified
prospects to be drilled by a partnership, the managing general partner has the
right on behalf of the partnership to:

     o    substitute prospects;

     o    take a lesser working interest in the prospects;

     o    drill in other areas; or

     o    do any combination of the foregoing.

Thus, you do not have any geological or production information to evaluate any
additional and/or substituted prospects and wells. Also, if the subscription
proceeds received by a partnership are insufficient to drill all of the
identified prospects, then the managing general partner will choose those
prospects which it believes are most suitable for the partnership. You must rely
entirely on the managing general partner to select the prospects and wells for a
partnership.

In addition, the partnerships do not have the right of first refusal in the
selection of prospects from the inventory of the managing general partner and
its affiliates, and they may sell their prospects to other partnerships,
companies, joint ventures, or other persons at any time.

DRILLING PROSPECTS IN ONE AREA MAY INCREASE RISK. If multiple wells are drilled
in one area at approximately the same time, then there is a greater risk that
two or more of the wells will be marginal or nonproductive since the managing
general partner will not be using the drilling results of one or more of those
wells to decide whether or not to continue drilling

                                       14
prospects in that area or to substitute other prospects in other areas. This is
contrasted with the situation in which a partnership drills one well in an area,
and then assesses the drilling results before it decides to drill a second well
in the same area or to substitute a different prospect in another area.

This risk is further increased with respect to wells for which the drilling and
completing costs are prepaid in one year, and the drilling of the wells must
begin within the first 90 days of the immediately following year under the tax
laws associated with deducting the intangible drilling costs of the prepaid
wells in the year in which the prepayment is made, rather than the year in which
the wells are drilled. For example, if the partnership prepays in 2007 the costs
of drilling one or more wells to be drilled in 2008, potential bad weather
conditions during the first 90 days of 2008 could delay beginning the drilling
of one or more of the prepaid wells beyond the 90 day time limit under the tax
laws. This would have a greater adverse effect on the partnership's deduction
for prepaid intangible drilling costs if the managing general partner is
required to begin drilling many wells at the same time, rather than only a few
wells. Also, "frost laws" prohibit drilling rigs and other heavy equipment from
using certain roads during the winter, which may delay beginning the drilling of
the prepaid wells within the 90 day time limit in 2007 under the tax laws. In
addition, there could be shortages of drilling rigs, equipment, supplies and
personnel during this time period, or unexpected operational events and drilling
conditions. (See "Federal Income Tax Consequences - Drilling Contracts"
regarding prepaid wells and the 90 day time constraint.)

LACK OF PRODUCTION INFORMATION INCREASES YOUR RISK AND DECREASES YOUR ABILITY TO
EVALUATE THE FEASIBILITY OF A PARTNERSHIP'S DRILLING PROGRAM. Production
information from wells previously drilled in the area surrounding the location
where a new well is proposed to be drilled is an important indicator in
evaluating the economic potential of the well proposed to be drilled. However,
generally, there will be a lack of production information from surrounding wells
for the majority of the wells to be drilled by a partnership, which results in
greater uncertainty to you and the other investors. This lack of production
information results from the Pennsylvania Department of Environmental Resources
keeping production data confidential for the first five years from the time a
well starts producing, so if there was a third-party operation and the well has
been drilled within five years the production information is not available.
Also, when the managing general partner is the operator the wells may often be
drilled adjacent to wells which are not yet completed, not on-line to sell
production, or have been producing for only a short period of time so there is
little or no production information available.

THE PARTNERSHIPS IN THIS PROGRAM AND OTHER PARTNERSHIPS SPONSORED BY THE
MANAGING GENERAL PARTNER MAY COMPETE WITH EACH OTHER FOR PROSPECTS, EQUIPMENT,
SUBCONTRACTORS, AND PERSONNEL. One or more partnerships in this program and
other partnerships sponsored by the managing general partner may have unexpended
capital funds at the same time. Thus, these partnerships may compete for
suitable prospects, equipment, subcontractors, and the managing general
partner's personnel. For example, a partnership previously organized by the
managing general partner may still be acquiring prospects to drill when the
partnerships in this program are attempting to acquire their prospects. This may
make it more difficult for the partnerships to complete their prospect
acquisition and drilling activities and may make each partnership less
profitable.

MANAGING GENERAL PARTNER'S SUBORDINATION IS NOT A GUARANTEE OF THE RETURN OF ANY
OF YOUR INVESTMENT. If your cash distributions from the partnership in which you
invest are less than a 10% return of capital for each of the first five 12-month
periods beginning with the partnership's first cash distribution from
operations, then the managing general partner has agreed to subordinate a
portion of its share of the partnership's net production revenues. However, if
the wells produce only small natural gas and oil volumes, and/or natural gas and
oil prices decrease, then even with subordination you may not receive the 10%
return of capital for each of the first five years as described above, or a
return of your capital during the term of the partnership. Also, at any time
during the subordination period the managing general partner is entitled to an
additional share of partnership revenues to recoup previous subordination
distributions to the extent your cash distributions from the partnership exceed
the 10% return of capital described above. (See "Participation in Costs and
Revenues - Subordination of Portion of Managing General Partner's Net Revenue
Share.")

BORROWINGS BY THE MANAGING GENERAL PARTNER COULD REDUCE FUNDS AVAILABLE FOR ITS
SUBORDINATION OBLIGATION. With respect to each partnership, the managing general
partner has or will pledge either its partnership interest and/or an undivided
interest in the partnership's assets equal to or less than its revenue interest,
which will range from 32% to 40%, depending on the amount of its capital
contribution, to secure borrowings for its and its affiliates' general purposes.
(See "Participation in

                                       15
Costs and Revenues" and "Conflicts of Interest - Conflicts Regarding Managing
General Partner Withdrawing or Assigning an Interest.") Under agreements
previously entered into as described in "Management's Discussion and Analysis of
Financial Condition, Results of Operations, Liquidity and Capital Resources,"
the managing general partner's lenders have required a first lien on the
managing general partner's interest in the natural gas and oil properties and
other assets of each partnership, and the lenders will have priority over the
managing general partner's subordination obligation under the partnership
agreement for each partnership. Thus, if there was a default by the managing
general partner to the lenders under this pledge arrangement, or if there was a
default by an affiliate of the managing general partner under this pledge
arrangement or another loan secured by this pledge arrangement, the amount of
each partnership's net production revenues available to the managing general
partner for its subordination obligation to you and the other investors would be
reduced or eliminated. Also, under certain circumstances, if the managing
general partner made a subordination distribution to you and the other investors
after a default to its lenders, then the lenders may be able to recoup that
subordination distribution from you and the other investors.

COMPENSATION AND FEES TO THE MANAGING GENERAL PARTNER REGARDLESS OF SUCCESS OF A
PARTNERSHIP'S ACTIVITIES WILL REDUCE CASH DISTRIBUTIONS. The managing general
partner and its affiliates will profit from their services in drilling,
completing, and operating each partnership's wells, and will receive the other
fees and reimbursement of direct costs described in "Compensation," regardless
of the success of the partnership's wells. These fees and direct costs will
reduce the amount of cash distributions to you and the other investors. The
amount of the fees is subject to the complete discretion of the managing general
partner, other than the fees must not exceed competitive fees charged by
unaffiliated third-parties in the same geographic area engaged in similar
businesses and they must comply with any other restrictions set forth in
"Compensation." With respect to direct costs, the managing general partner has
sole discretion on behalf of each partnership to select the provider of the
services or goods and the provider's compensation as discussed in
"Compensation."

THE INTENDED MONTHLY DISTRIBUTIONS TO INVESTORS MAY BE REDUCED OR DELAYED. Cash
distributions to you and the other investors may not be paid each month.
Distributions may be reduced or deferred, in the discretion of the managing
general partner, to the extent a partnership's revenues are used for any of the
following:

     o    compensation and fees to the managing general partner as described
          above in "- Compensation and Fees to the Managing General Partner
          Regardless of Success of a Partnership's Activities Will Reduce Cash
          Distributions";

     o    repayment of borrowings;

     o    cost overruns;

     o    remedial work to improve a well's producing capability;

     o    direct costs and general and administrative expenses of the
          partnership;

     o    reserves, including a reserve for the estimated costs of eventually
          plugging and abandoning the wells; or

     o    indemnification of the managing general partner and its affiliates by
          the partnership for losses or liabilities incurred in connection with
          the partnership's activities. (See "Participation in Costs and
          Revenues - Distributions.")

THERE ARE CONFLICTS OF INTEREST BETWEEN THE MANAGING GENERAL PARTNER AND THE
INVESTORS. There are conflicts of interest between you and the other investors
and the managing general partner and its affiliates. These conflicts of
interest, which are not otherwise discussed in this "Risk Factors" section,
include the following:

     o    the managing general partner has determined the compensation and
          reimbursement that it and its affiliates will receive in connection
          with the partnerships without any unaffiliated third-party dealing at
          arms' length on behalf of you and the other investors;

                                       16
o    the managing general partner must monitor and enforce, on behalf of
          the partnerships, its own compliance with the drilling and operating
          agreement and the partnership agreement and the compliance of it and
          its affiliate, Atlas Pipeline Partners, with the gas gathering
          agreement;

     o    because the managing general partner will receive a percentage of
          revenues greater than the percentage of costs that it pays, there may
          be a conflict of interest concerning which wells will be drilled based
          on each wells' risk and profit potential;

     o    the allocation of all intangible drilling costs to you and the other
          investors and the majority of the equipment costs to the managing
          general partner may create a conflict of interest concerning whether
          to complete a well;

     o    if the managing general partner, as tax matters partner, represents a
          partnership before the IRS, potential conflicts include, for example,
          whether or not to expend partnership funds to contest a proposed
          adjustment by the IRS, if any, to the amount of your deduction for
          intangible drilling costs, or the credit to the managing general
          partner's capital account for contributing the leases to the
          partnership;

     o    which wells will be drilled by the managing general partner's and its
          affiliates' other affiliated partnerships or third-party programs in
          which they serve as driller/operator and which wells will be drilled
          by the partnerships in this program, and the terms on which the
          partnerships' leases will be acquired;

     o    the managing general partner will have complete discretion in
          determining the terms on which it or its affiliated limited
          partnerships may purchase producing wells from each partnership;

     o    the managing general partner and its officers, directors, and
          affiliates may purchase units at a reduced price, which would dilute
          the voting rights of you and the other investors on certain matters;

     o    the same legal counsel represents the managing general partner and
          each partnership;

     o    Atlas Pipeline Partners, an affiliate of the managing general partner,
          has the right to determine the order of priority for constructing
          gathering lines for each partnership's wells; and

     o    Atlas Pipeline Partners, an affiliate of the managing general partner,
          will benefit from the partnerships drilling wells that will connect to
          its gathering system.

Other than certain guidelines set forth in "Conflicts of Interest," the managing
general partner has no established procedures to resolve a conflict of interest.

THE PRESENTMENT OBLIGATION MAY NOT BE FUNDED AND THE PRESENTMENT PRICE MAY NOT
REFLECT FULL VALUE. Subject to certain conditions, beginning with the fifth
calendar year after the offering of units in your partnership closes you may
present your units to the managing general partner for purchase. However, the
managing general partner may determine, in its sole discretion, that it does not
have the necessary cash flow or cannot borrow funds for this purpose on
reasonable terms. In either event the managing general partner may suspend the
presentment feature. This risk is increased because the managing general partner
has and will incur similar presentment obligations in other partnerships.

Further, the presentment price for your units may not reflect the full value of
a partnership's property or your units because of the difficulty in accurately
estimating natural gas and oil reserves. Reservoir engineering is a subjective
process of estimating underground accumulations of natural gas and oil that
cannot be measured in an exact way, and the accuracy of the reserve estimate is
a function of the quality of the available data and of engineering and
geological interpretation and judgment. Also, the reserves and future net
revenues are based on various assumptions as to natural gas and oil prices,
taxes, development expenses, capital expenses, operating expenses and
availability of funds. Any significant variance in these assumptions could
materially affect the estimated quantity of the reserves. As a result, the
managing general partner's estimates are inherently imprecise and may not
correspond to realizable value. Thus, the presentment price paid for your

                                       17
units and the amount of any partnership distributions received by you before the
presentment may be less than the subscription amount you paid for your units.
However, because the presentment price is a contractual price it is not reduced
by discounts such as minority interests and lack of marketability that generally
are used to value partnership interests for tax and other purposes. (See
"Presentment Feature.")

Finally, see "- An Investment in a Partnership Must be for the Long-Term Because
the Units Are Illiquid and Not Readily Transferable," above, concerning the tax
effects on you of presenting your units for purchase.

THE MANAGING GENERAL PARTNER MAY NOT DEVOTE THE NECESSARY TIME TO THE
PARTNERSHIPS BECAUSE ITS MANAGEMENT OBLIGATIONS ARE NOT EXCLUSIVE. The
partnerships do not have any employees and must rely on the managing general
partner and its affiliates for the management of it and its business, and they
may not devote the necessary time to the partnerships, which is in the managing
general partner's discretion. Also, the managing general partner depends on its
indirect parent company, Atlas America and its affiliates, for management and
administrative functions and financing for capital expenditures as discussed in
"Management - Transactions with Management and Affiliates." The managing general
partner and its affiliates will be engaged in other oil and gas activities,
including other partnerships and unrelated business ventures for their own
account or for the account of others, during the term of each partnership. Thus,
the competition for time and services of the managing general partner and its
affiliates could result in insufficient attention to the management and
operation of the partnerships.

PREPAYING SUBSCRIPTION PROCEEDS TO THE MANAGING GENERAL PARTNER MAY EXPOSE THE
SUBSCRIPTION PROCEEDS TO CLAIMS OF THE MANAGING GENERAL PARTNER'S CREDITORS.
Under the drilling and operating agreement, each partnership will be required to
immediately pay the managing general partner the investors' share of the entire
estimated price for drilling and completing the partnership's wells. Thus, these
funds could be subject to claims of the managing general partner's creditors.
(See "Financial Information Concerning the Managing General Partner and Atlas
America Public #16-2007(A) L.P.")

LACK OF INDEPENDENT UNDERWRITER MAY REDUCE DUE DILIGENCE INVESTIGATION OF THE
PARTNERSHIPS AND THE MANAGING GENERAL PARTNER. There has not been an extensive
in-depth "due diligence" investigation of the existing and proposed business
activities of the partnerships and the managing general partner that would be
provided by independent underwriters. Anthem Securities, which is affiliated
with the managing general partner, serves as dealer-manager and will receive
reimbursement of bona fide due diligence expenses for certain due diligence
investigations conducted by the selling agents which it will reallow to the
selling agents. However, Anthem Securities' due diligence examination concerning
the partnerships cannot be considered to be independent, nor as comprehensive as
an investigation that would have been conducted by an independent broker/dealer.
(See "Conflicts of Interest.")

A LENGTHY OFFERING PERIOD MAY RESULT IN DELAYS IN THE INVESTMENT OF YOUR
SUBSCRIPTION AND ANY CASH DISTRIBUTIONS FROM THE PARTNERSHIP TO YOU. Because the
offering period for a particular partnership can extend for many months, it is
likely that there will be a delay in the investment of your subscription
proceeds. This may create a delay in the partnership's cash distributions to you
which will be paid only after a portion of the partnership's wells have been
drilled, completed and placed on-line for the delivery and sale of natural gas
and/or oil, and payment has been received from the purchaser of the natural gas
and/or oil. Also, distributions of a partnership's net production revenues will
be made only after payment of the managing general partner's fees and expenses
and only if there is sufficient cash available in the managing general partner's
discretion. See "Terms of the Offering" for a discussion of the procedures
involved in the offering of the units and the formation of a partnership.

YOUR INTERESTS MAY BE DILUTED. The equity interests of you and the other
investors in a partnership may be diluted. You and the other investors will
share in a partnership's production revenues from all of its wells in proportion
to your respective number of units, based on $10,000 per unit, regardless of:

     o    when you subscribe;

     o    which wells are drilled with your subscription proceeds; or

     o    the actual subscription price you paid for your units as described
          below.

                                       18
Because the drilling results of the wells drilled with the subscription proceeds
in your closing may be better than the drilling results of wells drilled with
subscription proceeds from your partnership's other closings, the value of your
units could be diluted when compared to what their value would have been if the
other units had not been sold and the other wells had not been drilled.

Also, some investors, including the managing general partner and its officers
and directors as described in "Plan of Distribution," may buy up to 5% of the
total units in each partnership at discounted prices because the dealer-manager
fee, the sales commission, the reimbursement for bona fide due diligence
expenses and/or the accountable reimbursement for permissible non-cash
compensation, will not be paid for those sales. These discounted subscription
prices will reduce the amount of the subscription proceeds available to a
partnership to drill wells. (See "- Spreading the Risks of Drilling Among a
Number of Wells Will be Reduced if Less than the Maximum Subscription Proceeds
are Received and Fewer Wells are Drilled.") In addition, all of the investors in
each partnership will share in the partnership's production revenues with the
managing general partner, based on the number of units purchased by each
investor, rather than the purchase price paid by the investor for his units.
Thus, investors who pay discounted prices for their units will receive higher
returns on their investments in a partnership as compared to investors who pay
the entire $10,000 per unit.

TAX RISKS

YOUR DEDUCTION FOR INTANGIBLE DRILLING COSTS MAY BE LIMITED FOR PURPOSES OF THE
ALTERNATIVE MINIMUM TAX. You will be allocated a share of your partnership's
deduction for intangible drilling costs in the year 2007 in an amount equal to
90% of the subscription price you pay for your units. Under current tax law,
however, your alternative minimum taxable income in 2007 cannot be reduced by
more than 40% by your deduction for intangible drilling costs. (See "Federal
Income Tax Consequences - Alternative Minimum Tax.")

LIMITED PARTNERS NEED PASSIVE INCOME TO USE THEIR DEDUCTION FOR INTANGIBLE
DRILLING COSTS. If you invest in a partnership as a limited partner (except as
discussed below), your share of the partnership's deduction for intangible
drilling costs in 2007 will be a passive loss that cannot be used to offset
"active" income, such as salary and bonuses, or portfolio income, such as
dividends and interest income. Thus, you may not have enough passive income from
the partnership or net passive income from your other passive activities, if
any, in 2007, to offset a portion or all of your passive deduction for
intangible drilling costs in 2007. However, any unused passive loss from
intangible drilling costs may be carried forward by you to offset your passive
income in subsequent taxable years. Also, except as described below, the passive
activity limitations on your share of the partnership's deduction for intangible
drilling costs in 2007 do not apply to you if you invest in the partnership as a
limited partner and you are a C corporation which:

     o    is not a personal service corporation or a closely held corporation;

     o    is a personal service corporation in which employee-owners hold 10%
          (by value) or less of the stock, but is not a closely held
          corporation; or

     o    is a closely held corporation (i.e., five or fewer individuals own
          more than 50% (by value) of the stock), but is not a personal service
          corporation in which employee-owners own more than 10% (by value) of
          the stock, in which case you may use your passive losses to offset
          your net active income (calculated without regard to your passive
          activity income and losses or portfolio income and losses).

(See "Federal Income Tax Consequences - Limitations on Passive Activity Losses
and Credits.")

YOU MAY OWE TAXES IN EXCESS OF YOUR CASH DISTRIBUTIONS FROM YOUR PARTNERSHIP.
You may become subject to income tax liability for your share of your
partnership's income in any taxable year in an amount that is greater than the
cash and any marginal well production credits you receive from the partnership
in which you invest in that taxable year. For example:

     o    if the partnership borrows money, your share of partnership revenues
          used to pay principal on the loan will be included in your income from
          the partnership and will not be deductible;

                                       19
o    income from sales of natural gas and oil may be included in your
          income from the partnership in one tax year, although payment is not
          actually received by the partnership and, thus, cannot be distributed
          to you, until the next tax year;

     o    if there is a deficit in your capital account, the partnership may
          allocate income or gain to you even though you do not receive a
          corresponding distribution of partnership revenues;

     o    the partnership's revenues may be expended by the managing general
          partner for nondeductible costs or retained in the partnership to
          establish a reserve for future estimated costs, including a reserve
          for the estimated costs of eventually plugging and abandoning the
          wells, which will increase your share of the partnership's income
          without a corresponding cash distribution to you; and

     o    the taxable disposition of the partnership's property or your units
          may result in income tax liability to you in excess of the cash you
          receive from the transaction.

INVESTMENT INTEREST DEDUCTIONS OF INVESTOR GENERAL PARTNERS MAY BE LIMITED. If
you invest in a partnership as an investor general partner, your share of the
partnership's deduction for intangible drilling costs will reduce your
investment income and may reduce the amount of your deductible investment
interest expense, if any.

YOUR TAX BENEFITS FROM AN INVESTMENT IN A PARTNERSHIP ARE NOT CONTRACTUALLY
PROTECTED. An investment in a partnership does not give you any contractual
protection against the possibility that part or all of the intended tax benefits
of your investment will be disallowed by the IRS. No one provides any insurance,
tax indemnity or similar agreement for the tax treatment of your investment in a
partnership. You have no right to rescind your investment in a partnership or to
receive a refund of any of your investment in the partnership if a portion or
all of the intended tax consequences of your investment in the partnership are
ultimately disallowed by the IRS or the courts. Also, none of the fees paid by
the partnerships to the managing general partner, its affiliates or independent
third-parties (including special counsel which issued the tax opinion letter)
are refundable or contingent on whether the intended tax consequences of your
investment in a partnership are ultimately sustained if challenged by the IRS.

AN IRS AUDIT OF YOUR PARTNERSHIP MAY RESULT IN AN IRS AUDIT OF YOUR PERSONAL
FEDERAL INCOME TAX RETURNS. The IRS may audit each partnership's annual federal
information income tax returns, particularly since each partnership's investors
will receive a deduction equal to not less than 90% of their investment amount
in 2007, which includes their respective deductions for intangible drilling
costs. If the partnership in which you invest is audited, the IRS also may audit
your personal federal income tax returns, including prior years' returns and
items which are unrelated to the partnership. (See "Federal Income Tax
Consequences - Penalties and Interest.")

EACH PARTNERSHIP'S DEDUCTIONS MAY BE CHALLENGED BY THE IRS. If the IRS audits a
partnership, it may challenge the amount of the partnership's deductions and the
taxable year in which the deductions were claimed, including the deductions for
intangible drilling costs and depreciation. Any adjustments made by the IRS to
the federal information income tax returns of the partnership in which you
invest could lead to adjustments on your personal federal income tax returns and
could reduce the amount of your deductions from the partnership in 2007 and
subsequent tax years. The IRS also could seek to recharacterize a portion of the
partnership's intangible drilling costs for drilling and completing its wells as
some other type of expense, such as lease costs or equipment costs, which would
reduce or defer your share of the partnership's deductions for those costs. (See
"Federal Income Tax Consequences - Business Expenses," "- Depreciation and Cost
Recovery Deductions," and "- Drilling Contracts.")

In addition, depending primarily on when its subscription proceeds are received,
it is possible that each partnership may prepay in 2007 most or all of its
intangible drilling costs for wells the drilling of which will not begin until
2008. In that event, you will not receive a deduction in 2007 for your share of
the partnership's prepaid intangible drilling costs for those wells unless the
drilling of the prepaid wells begins on or before the 90th day following the
close of the partnership's taxable year in which the prepayment was made. Under
the drilling and operating agreement, the drilling of all of each partnership's
prepaid wells, if any, will be required to begin within that 90 day time period.
However, the drilling of any partnership well

                                       20
may be delayed due to circumstances beyond the control of the managing general
partner, acting as general drilling contractor, without liability to the
managing general partner. If for any reason the drilling of a prepaid
partnership well does not begin within the required 90 day time period in 2008,
your deduction for prepaid intangible drilling costs for that well must be
claimed for your 2008 tax year, instead of your 2007 tax year. Also, there is a
greater risk that the IRS will attempt to defer from 2007 to 2008 your share of
the partnership's deduction for intangible drilling costs for drilling and
completing any prepaid partnership wells if there are other additional working
interest owners of a prepaid well, because those other working interest owners
will not be required to prepay their share of the costs of drilling and
completing the wells. (See "Federal Income Tax Consequences - Drilling
Contracts.")

CHANGES IN THE LAW MAY REDUCE YOUR TAX BENEFITS FROM AN INVESTMENT IN A
PARTNERSHIP. Your tax benefits from an investment in a partnership may be
affected by changes in the tax laws. For example, the top four federal income
tax brackets for individuals were reduced in 2003, including reducing the top
bracket to 35% from 38.6%, until December 31, 2010. The lower federal income tax
rates will reduce to some degree the amount of taxes you save by virtue of your
share of the partnership's deductions for intangible drilling costs, depletion,
and depreciation, and its marginal well production credits, if any. However, the
federal income tax rates described above could be changed again, even before
January 1, 2011, and other changes in the tax laws could be made which would
affect your tax benefits from an investment in a partnership.

IT MAY BE MANY YEARS BEFORE YOU RECEIVE ANY MARGINAL WELL PRODUCTION CREDITS, IF
EVER. There is a federal income tax credit for the sale of qualified marginal
natural gas and oil production. Although the managing general partner
anticipates that each partnership's natural gas and oil production will be
qualified production for purposes of this tax credit, the managing general
partner further anticipates any natural gas and oil production sold by Atlas
America Public #16-2007(A) L.P. or Atlas America Public #16-2007(B) L.P. in 2007
will be sold at prices above the applicable reference prices for 2006 at which
the marginal well production credit would be reduced to zero. In addition,
depending primarily on market prices for natural gas and oil, which are
volatile, you may not receive any marginal well production credits from either
partnership in which you invest for many years, if ever. (See "Federal Income
Tax Consequences - Marginal Well Production Credits.")

                             ADDITIONAL INFORMATION

The program and the partnerships composing the program currently are not
required to file reports with the SEC. However, a registration statement on Form
S-1 has been filed on behalf of the program with the SEC. Certain portions of
the registration statement have been deleted from this prospectus under SEC
rules and regulations. You are urged to refer to the registration statement, as
amended, and its exhibits for further information concerning the provisions of
certain documents referred to in this prospectus.

You may read and copy any materials filed as a part of the registration
statement, including the tax opinion included as Exhibit 8, at the SEC's Public
Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The SEC maintains
an internet world wide web site that contains registration statements, reports,
proxy statements, and other information about issuers who file electronically
with the SEC, including the program. The address of that site is
http://www.sec.gov. Also, you may obtain information on the operation of the
Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, a copy
of the tax opinion may be obtained by you or your advisors from the managing
general partner at no cost. The delivery of this prospectus does not imply that
its information is correct as of any time after its date.

                 FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS

Statements, other than statements of historical facts, included in this
prospectus and its exhibits address activities, events or developments that the
managing general partner and the partnerships anticipate will or may occur in
the future. For example, the words "believes," "anticipates," "will" and
"expects" are intended to identify forward-looking statements. These
forward-looking statements include such things as:

     o    investment objectives;

     o    references to future success in a partnership's drilling and marketing
          activities;

                                       21
o    business strategy;

     o    estimated future capital expenditures;

     o    competitive strengths and goals; and

     o    other similar matters.

These statements are based on certain assumptions and analyses made by the
partnerships and the managing general partner in light of their experience and
their perception of historical trends, current conditions, and expected future
developments. However, whether actual results will conform with these
expectations is subject to a number of risks and uncertainties, many of which
are beyond the control of the partnerships and the managing general partner,
including, but not limited to:

     o    general economic, market, or business conditions;

     o    changes in laws or regulations;

     o    the risk that the wells are productive, but do not produce enough
          revenue to return the investment made;

     o    the risk that the wells are dry holes; and

     o    uncertainties concerning the price of natural gas and oil, which may
          decrease.

Thus, all of the forward-looking statements made in this prospectus and its
exhibits are qualified by these cautionary statements. There can be no assurance
that actual results will conform with the managing general partner's and the
partnerships' expectations.

                              INVESTMENT OBJECTIVES

Each partnership's principal investment objectives are to invest its
subscription proceeds in natural gas development wells which will:

     o    Provide monthly cash distributions to you from the partnership in
          which you invest until the wells are depleted, with a minimum annual
          return of capital of 10% during the first five years beginning with
          your partnership's first revenue distribution and based on $10,000 per
          unit for all units sold regardless of the actual subscription price
          you paid for your units. These distributions of a 10% return of
          capital during the first five years are not guaranteed, but are
          subject to the managing general partner's subordination obligation.
          The managing general partner anticipates that investors in a
          partnership will begin to receive monthly cash distributions
          approximately eight months after the offering period for the
          partnership ends and it may take up to 12 months before all of the
          wells in that partnership have been drilled and completed and are
          on-line for the sale of their natural gas or oil production. However,
          if all or the majority of the units are sold in Atlas America Public
          #16-2007(A) L.P., then it may take longer for both cash distributions
          to begin and all of the wells to be drilled, completed and online to
          sell production in that partnership. This will also delay conversion
          of the investor general partner units to limited partner units. Also,
          see "Participation in Costs and Revenues - Subordination of Portion of
          Managing General Partner's Net Revenue Share" for a discussion of the
          subordination feature. The partnerships currently do not hold any
          interests in any prospects on which the wells will be drilled.

     o    Obtain tax deductions from the partnership in which you invest, in the
          year that you invest, from intangible drilling costs to offset a
          portion of your taxable income from sources other than the
          partnership, subject to the passive activity limitations on losses if
          you invest as a limited partner. For example, if you pay $10,000 for a
          unit your investment will produce an income tax deduction for
          intangible drilling costs of $9,000 per unit, 90%, in the year you
          invest against:

                                       22
o    ordinary income, or capital gain in some situations, if you
               invest as an investor general partner in a partnership; or

          o    net passive income from your other passive activity investments,
               if any, and passive income from the partnership in the year you
               invest, if any, if you invest as a limited partner in a
               partnership.

          In 2003,  the top four tax  brackets  for  individual  taxpayers  were
          reduced  from 38.6% to 35%,  35% to 33%,  30% to 28%,  and 27% to 25%.
          These changes are scheduled to expire December 31, 2010. If you are in
          either the 35% or 33% tax bracket,  you will save approximately $3,150
          or $2,970, respectively,  per $10,000 unit, in federal income taxes in
          the year  that you  invest.  Most  states  also  allow  this type of a
          deduction  against the state income tax. If the  partnership  in which
          you invest  begins  selling  natural gas and oil  production  from its
          wells  in the  year in  which  you  invest,  however,  then you may be
          allocated  a share of  partnership  income  in that  year that will be
          offset by a portion of your  intangible  drilling  cost  deduction and
          your share of the other partnership deductions discussed below.

     o    Offset a portion of any gross production income generated by your
          partnership with tax deductions from percentage depletion, which is
          anticipated by the managing general partner to be 15% in 2007. The
          percentage depletion rate may fluctuate from year to year depending on
          the price of oil, but under current tax law it will not be less than
          the statutory rate of 15% nor more than 25%.

     o    Obtain tax deductions of the remaining 10% of your investment over a
          seven-year cost recovery period, beginning in the year the wells are
          drilled, completed and placed in service for the production of natural
          gas or oil in the partnership in which you invest. For example, if you
          pay $10,000 for a unit, you will receive additional income tax
          deductions over the cost recovery period totaling $1,000 per unit for
          depreciation of your partnership's equipment costs for its productive
          wells.

     o    If you are self-employed and invest in a partnership as an investor
          general partner, then you may use your share of the partnership's
          deduction for intangible drilling costs to offset a portion of your
          net earnings from self-employment in the year you invest. Also, if
          wells in the partnership are drilled and completed and placed in
          service in the year you invest, you will begin receiving the
          depreciation deductions discussed above which, to the extent they
          exceed your share of your partnership's income, if any, in the year in
          which you invest, also will reduce your net earnings from
          self-employment in the year you invest, and in your subsequent tax
          years during the seven-year cost recovery period.

Attainment of these investment objectives by a partnership will depend on many
factors, including the ability of the managing general partner to select
suitable wells that will be productive and produce enough revenue to return the
investment made. The success of each partnership depends largely on future
economic conditions, especially the future price of natural gas, which is
volatile and may decrease. Also, the extent to which each partnership attains
the foregoing investment objectives will be different, because each partnership
is a separate business entity which:

     o    generally will drill different wells;

     o    will likely receive a different amount of subscription proceeds, as
          intended by the managing general partner, which generally will be the
          primary factor in determining the number of wells that can be drilled
          by each partnership; and

     o    may drill wells situated in different geographical areas, where the
          wells will be drilled to different formations, reservoirs or depths,
          which will affect the cost of the wells and, thus, will also affect
          the number of wells that can be drilled by each partnership.

There can be no guarantee that the foregoing objectives will be attained.

                                       23
ACTIONS TO BE TAKEN BY MANAGING GENERAL
                     PARTNER TO REDUCE RISKS OF ADDITIONAL
                     PAYMENTS BY INVESTOR GENERAL PARTNERS

You may choose to invest in a partnership as an investor general partner so that
you can receive an immediate tax deduction against any type of income. To help
reduce the risk that you and other investor general partners could be required
to make additional payments to the partnership, the managing general partner
will take the actions set forth below.

     o    INSURANCE. The managing general partner will obtain and maintain
          insurance coverage in amounts and for purposes which would be carried
          by a reasonable, prudent general contractor and operator in accordance
          with industry standards. Each partnership will be included as an
          insured under these general, umbrella, and excess liability policies.
          In addition, the managing general partner requires all of its
          subcontractors to certify that they have acceptable insurance coverage
          for worker's compensation and general, auto, and excess liability
          coverage. Major subcontractors are required to carry general and auto
          liability insurance with a minimum of $1 million combined single limit
          for bodily injury and property damage in any one occurrence or
          accident. In the event of a loss caused by a major subcontractor, the
          managing general partner or partnership may attempt to draw on the
          insurance policy of the particular subcontractor before the insurance
          of the managing general partner or that of the partnership, but
          currently would be unable to do so since none of its major
          subcontractors have insurance which would allow this. Also, even if a
          major subcontractor's insurance was initially available, the managing
          general partner or a partnership may choose to draw on its own
          insurance coverage before that of the major subcontractor so that its
          insurance carrier will control the payment of claims.

          The managing general partner's current insurance coverage satisfies
     the following specifications:

          o    worker's compensation insurance in full compliance with the laws
               of the Commonwealth of Pennsylvania and any other applicable
               state laws where the wells will be drilled;

          o    commercial general liability covering bodily injury and property
               damage third party liability, including products/completed
               operations, blow out, cratering, and explosion with limits of $1
               million per occurrence/$2 million general aggregate; and $1
               million products/completed operations aggregate;

          o    underground resources and equipment property damages liability to
               others with a limit of $1 million;

          o    automobile liability with a $1 million combined single limit;

          o    employer's liability with a $500,000 policy limit;

          o    pollution liability resulting from a "pollution incident," which
               is defined as the discharge, dispersal, seepage, migration,
               release or escape of one or more pollutants directly from a well
               site, with a limit of $1 million for bodily injury and property
               damage and a limit of $100,000 for clean-up for third-parties;
               however, coverage does not apply to pollution damage to the well
               site itself or the property of the insured;

          o    commercial umbrella liability composed of:

               o    primary umbrella limit of $25 million over general
                    liability, automobile liability, and employer's liability
                    and a $10 million sublimit for pollution liability; and

                                       24
o    excess liability providing excess limits of $24 million over
                    the $25 million provided in the commercial umbrella, which
                    is for general liability only.

          Because the managing general partner is driller and operator of wells
          for other partnerships, the insurance available to each partnership
          could be substantially less if insurance claims are made in the other
          partnerships.

          This insurance has deductibles, which would first have to be paid by a
          partnership, of:

          o    $2,500 per occurrence for bodily injury and property damage; and

          o    $10,000 per pollution incident for pollution damage.

          The insurance also has terms, including exclusions, that are standard
          for the natural gas and oil industry. On request the managing general
          partner will provide you or your representative a copy of its
          insurance policies. The managing general partner will use its best
          efforts to maintain insurance coverage that meets its current
          coverage, but it may be unsuccessful if the coverage becomes
          unavailable or too expensive.

          If you are an investor general partner and there is going to be a
          material adverse change in your partnership's insurance coverage,
          which the managing general partner does not anticipate, then the
          managing general partner will notify you at least 30 days before the
          effective date of the change. You will then have the right to convert
          your units into limited partner units before the change in insurance
          coverage by giving written notice to the managing general partner.

     o    CONVERSION OF INVESTOR GENERAL PARTNER UNITS TO LIMITED PARTNER UNITS.
          Your investor general partner units will be automatically converted by
          the managing general partner to limited partner units after all of the
          wells in your partnership have been drilled and completed. In each
          partnership, the managing general partner anticipates that all of the
          wells will be drilled and completed no more than 12 months after a
          partnership closes, and the conversion will occur before the end of
          the succeeding tax year. However, if all or the majority of the units
          are sold in Atlas America Public #16-2007(A) L.P., then it may take
          longer for both cash distributions to begin and all of the wells to be
          drilled, completed and online to sell production in that partnership.
          This will also delay conversion of the investor general partner units
          to limited partner units.

          Once your units are converted, which is a nontaxable event, you will
          have the lesser liability of a limited partner in your partnership
          under Delaware law for obligations and liabilities arising after the
          conversion. However, you will continue to have the responsibilities of
          a general partner for partnership liabilities and obligations incurred
          before the effective date of the conversion. For example, you might
          become liable for partnership liabilities in excess of your
          subscription amount during the time the partnership is engaged in
          drilling activities and for environmental claims that arose during
          drilling activities, but were not discovered until after the
          conversion.

     o    NONRECOURSE DEBT. The partnerships do not anticipate that they will
          borrow funds. However, if borrowings are required, then the
          partnerships will be permitted to borrow funds only from the managing
          general partner or its affiliates and without recourse against
          non-partnership assets. Thus, if there is a default under this loan
          arrangement you cannot be required to contribute funds to the
          partnership. Any borrowings by a partnership will be repaid from that
          partnership's revenues.

          The amount that may be borrowed at any one time by a partnership may
          not exceed an amount equal to 5% of the investors' subscription
          proceeds in the partnership. However, because you do not bear the risk
          of repaying these borrowings with non-partnership assets, the
          borrowings will not increase the extent to which you are allowed to
          deduct your individual share of partnership losses. (See "Federal
          Income Tax Consequences - Tax Basis of Units" and "- 'At Risk'
          Limitation on Losses.")

                                       25
o    INDEMNIFICATION. The managing general partner will indemnify you from
          any liability incurred in connection with your partnership that is in
          excess of your interest in the partnership's:

          o    undistributed net assets; and

          o    insurance proceeds, if any, from all potential sources.

          The managing general partner's indemnification obligation, however,
          will not eliminate your potential liability if the managing general
          partner's assets are insufficient to satisfy its indemnification
          obligation. There can be no assurance that the managing general
          partner's assets, including its liquid assets, will be sufficient to
          satisfy its indemnification obligation.

             CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS

SOURCE OF FUNDS

Each partnership must receive minimum subscription proceeds of $2 million to
close, and the subscription proceeds of both partnerships, in the aggregate, may
not exceed $200 million. There are no other requirements regarding the size of a
partnership, and the subscription proceeds of one partnership may be
substantially more or less than the subscription proceeds of the other
partnership. See the targeted maximum subscription amounts for each partnership
set forth in "Terms of the Offering - Subscription to a Partnership." Also, the
managing general partner has the discretion to accept subscriptions for any
amount up to and including the entire amount in Atlas America Public #16-2007(A)
L.P. and not offer and sell any units in the other partnership. (See "Terms of
the Offering - Subscription to a Partnership.")

On completion of the offering of units in a partnership, the partnership's
source of funds will be as follows assuming each unit is sold for $10,000:

     o    the subscription proceeds of you and the other investors, which will
          be:

          o    $2 million if 200 units are sold; and

          o    $200 million if 20,000 units are sold; and

     o    the managing general partner's capital contribution, which must be at
          least 25% of all capital contributions and includes its credit for
          organization and offering costs and contributing the leases, which
          will be:

          o    not less than approximately $781,233 if 200 units are sold; and

          o    not less than approximately $78,810,820 if 20,000 units are sold.

Thus, the total amount available to a partnership will be not less than
approximately $2,781,233 if 200 units are sold ranging to not less than
approximately $278,810,820 if 20,000 units are sold.

The managing general partner has made the largest single capital contribution in
each of its prior partnerships and no individual investor has contributed more,
although the total investor contributions in each partnership have exceeded the
managing general partner's contribution. The managing general partner also
expects to make the largest single capital contribution in each of the
partnerships.

USE OF PROCEEDS

The subscription proceeds received from you and the other investors will be used
by the partnership in which you invest as follows:

     o    90% of the subscription proceeds will be used to pay 100% of the
          intangible drilling costs of drilling and completing the partnership's
          wells; and

                                       26
o    10% of the subscription proceeds will be used to pay a portion of the
          equipment costs of drilling and completing the partnership's wells.

The managing general partner will contribute all of the leases to each
partnership covering the acreage on which the partnership's wells will be
drilled, and pay all of the equipment costs of drilling and completing the
partnership's wells that exceed 10% of the partnership's subscription proceeds.
Thus, the managing general partner will pay the majority of each partnership's
equipment costs. The managing general partner also will be charged with 100% of
the organization and offering costs for each partnership. A portion of these
contributions to each partnership will be in the form of payments to itself, its
affiliates and third-parties and the remainder will be in the form of services
related to organizing this offering. The managing general partner will receive a
credit towards its required capital contribution to each partnership for these
payments and services as discussed in "Participation in Costs and Revenues."

The following tables present information concerning each partnership's use of
the proceeds provided by both you and the other investors and the managing
general partner. The tables are based in part on the managing general partner's
estimate of its capital contribution to a partnership based on the applicable
number of units sold as shown in the table. The managing general partner's
estimated capital contribution shown in the tables includes its credit for
organization and offering costs and contributing the leases, and exceeds in each
case its required capital contribution of not less than 25% of all capital
contributions to a partnership. Anthem Securities, an affiliate of the managing
general partner, will be the dealer-manager of each offering and it will receive
the dealer-manager fee, the sales commissions and the up to .5% reimbursement
for bona fide due diligence expenses. A portion of these payments and
reimbursements, including all of the up to .5% reimbursement for bona fide due
diligence expenses, will be reallowed by the dealer-manager to the
broker/dealers, which are referred to as selling agents, as discussed in "Plan
of Distribution." Subject to the above, a partnership's organizational costs
will be paid to the managing general partner, its affiliates and various
third-parties, and the intangible drilling costs and tangible costs of drilling
and completing a partnership's wells will be paid to the managing general
partner as general drilling contractor and operator under the drilling and
operating agreement.

The tables are presented based on:

     o    the sale of 200 units ($2 million), which is the minimum number of
          units for each partnership; and

     o    the sale of 20,000 units, which is the maximum number of units, in the
          aggregate, for all the partnerships in the program.

Substantially all of the proceeds available to each partnership will be expended
for the following purposes and in the following manner:

                                INVESTOR CAPITAL
20,000
                                                    200                   UNITS
NATURE OF PAYMENT                                UNITS SOLD   % (1)       SOLD       % (1)
----------------------------------------------   ----------   -----   ------------   -----
ORGANIZATION AND OFFERING EXPENSES
Dealer-manager fee, sales commissions and up to
..5% reimbursement for bona fide due diligence
expenses......................................          -0-     -0-            -0-    -0-
Organization costs............................          -0-     -0-            -0-    -0-
AMOUNT AVAILABLE FOR INVESTMENT:
Intangible drilling costs (2).................   $1,800,000      90%  $180,000,000     90%
Equipment costs (2)...........................     $200,000      10%   $20,000,000     10%
Leases........................................          -0-     -0-            -0-    -0-
                                                 ----------     ---   ------------    ---
TOTAL INVESTOR CAPITAL........................   $2,000,000     100%  $200,000,000    100%
                                                 ==========     ===   ============    ===
27
----------
(1)  The percentage is based on the investors' total subscription proceeds, and
     excludes the managing general partner's estimate of its capital
     contributions in the "- Managing General Partner Capital" table below.

(2)  Ninety percent of the subscription proceeds provided by you and the other
     investors to each partnership will be used to pay 100% of the partnership's
     intangible drilling costs. Ten percent of the subscription proceeds
     provided by you and the other investors to each partnership will be used to
     pay a portion of the partnership's equipment costs. (See "Participation in
     Costs and Revenues.") The managing general partner will pay all of the
     remaining equipment costs of each partnership. In this regard, the managing
     general partner's share of each partnership's equipment costs as set forth
     in the "- Managing General Partner Capital" and the "- Total Partnership
     Capital" tables below is based on the managing general partner's estimate
     of the average cost of drilling and completing wells in each partnership's
     primary areas as discussed in "Compensation - Drilling Contracts."

                        MANAGING GENERAL PARTNER CAPITAL
200                20,000
                                                    UNITS               UNITS
NATURE OF PAYMENT                                   SOLD     % (1)       SOLD      % (1)
-----------------------------------------------   --------   -----   -----------   -----
ORGANIZATION AND OFFERING EXPENSES
Dealer-manager fee, sales commissions and up to
..5% reimbursement for bona fide due diligence
expenses (2)...................................   $200,000   25.60%  $20,000,000   26.65%
Organization costs (2).........................   $100,000   12.80%  $10,000,000   11.42%
AMOUNT AVAILABLE FOR INVESTMENT:
Intangible drilling costs......................        -0-     -0-           -0-     -0-
Equipment costs (3)............................   $402,063   51.47%  $40,780,720   51.74%
Leases (4).....................................   $ 79,170   10.13%  $ 8,030,100   10.19%
                                                  --------   -----   -----------   -----
TOTAL MANAGING GENERAL PARTNER CAPITAL            $781,233     100%  $78,810,820     100%
                                                  ========   =====   ===========   =====
----------
(1)  The percentage is based on the managing general partner's estimate of its
     capital contributions, and excludes the investors' total subscription
     proceeds set forth in the "- Investor Capital" table above.

(2)  As discussed in "Participation in Costs and Revenues," if these fees, sales
     commissions, reimbursements and organization costs exceed 15% of the
     investors' total subscription proceeds in a partnership, then the excess
     will be charged to the managing general partner, but will not be included
     as part of its capital contribution.

(3)  The managing general partner's share of equipment costs is described in
     "Compensation - Drilling Contracts" and "Participation in Costs and
     Revenues." However, these costs will vary depending on the actual equipment
     costs of drilling and completing the wells. Also, see footnote (2) to the
     "- Investor Capital" table above.

(4)  Instead of contributing cash for the leases, the managing general partner
     will assign to each partnership the leases covering the acreage on which
     the partnership's wells will be drilled. Generally, as described in
     "Compensation - Lease Costs," the managing general partner's lease costs
     are approximately $11,310 per prospect. For purposes of this table, the
     managing general partner's lease costs have been quantified using this
     amount based on its estimate of the number of net wells that will be
     drilled with the amount of subscription proceeds available as set forth in
     the table. The actual number of net wells drilled by the partnerships is
     likely to vary from the managing general partner's estimate, based
     primarily on where the wells are drilled and the actual costs of drilling
     and completing the wells. Also, the managing general partner's lease costs
     on a prospect may be significantly higher than the above-referenced amount,
     and its credit for the leases contributed will equal its cost, unless it
     has a reason to believe that cost is materially more than fair market value
     of the property, in which case its credit for its lease contribution must
     not exceed fair market value.

                                       28
TOTAL PARTNERSHIP CAPITAL
200                  20,000
NATURE OF PAYMENT                                            UNITS SOLD   % (1)    UNITS SOLD    % (1)
----------------------------------------------------------   ----------   -----   ------------   -----
ORGANIZATION AND OFFERING EXPENSES
Dealer-manager fee, sales commissions and up to .5%
reimbursement for bona fide due diligence expenses (2) ...   $  200,000    7.19%  $ 20,000,000    7.17%
Organization costs (2) ...................................   $  100,000    3.59%  $ 10,000,000    3.59%
AMOUNT AVAILABLE FOR INVESTMENT:
Intangible drilling costs (3) ............................   $1,800,000   64.72%  $180,000,000   64.56%
Equipment costs (3) ......................................   $  602,063   21.65%  $ 60,780,720   21.80%
Leases (4) ...............................................   $   79,170    2.85%  $  8,030,100    2.88%
                                                             ----------   -----   ------------   -----
TOTAL PARTNERSHIP CAPITAL ................................   $2,781,233     100%  $278,810,820     100%
                                                             ==========   =====   ============   =====
----------
(1)  The percentage is based on investors' total subscription proceeds in the "-
     Investor Capital Table" above, and the managing general partner's estimate
     of its capital contributions in the "- Managing General Partner Capital"
     table above.

(2)  As discussed in "Participation in Costs and Revenues," if these fees, sales
     commissions, reimbursements and organization costs exceed 15% of the
     investors' total subscription proceeds in a partnership, then the excess
     will be charged to the managing general partner, but will not be included
     as part of its capital contribution.

(3)  The managing general partner's share of equipment costs is described in
     "Compensation - Drilling Contracts" and "Participation in Costs and
     Revenues." Although these costs will vary depending on the actual equipment
     costs of drilling and completing the wells, 90% of the subscription
     proceeds provided by you and the other investors will be used to pay
     intangible drilling costs and 10% will be used to pay equipment costs.
     Also, see footnote (2) to the "- Investor Capital" table, above.

(4)  Instead of contributing cash for the leases, the managing general partner
     will assign to each partnership the leases covering the acreage on which
     that partnership's wells will be drilled as set forth in footnote (4) to
     the "- Managing General Partner Capital" table above.

                                  COMPENSATION

The items of compensation to be paid to the managing general partner and its
affiliates from each partnership are set forth below. Most of these items of
compensation depend on how many wells a partnership drills and how much of the
working interest in each of the wells is owned by the partnership. In this
regard, the managing general partner estimates that approximately eight gross
wells, which will be approximately seven net wells, will be drilled if the
minimum required subscription proceeds of $2 million are received by a
partnership, and approximately 777 gross wells, which will be approximately 710
net wells, will be drilled, in the aggregate, if subscription proceeds of $200
million are received by a partnership or the partnerships.

A gross well is a well in which a partnership owns a working interest. This is
compared with a net well, which is the sum of the fractional working interests
owned in the gross wells. For example, a 50% working interest owned in three
wells is three gross wells, but 1.5 net wells. However, the managing general
partner's estimated number of wells to be drilled by a partnership or the
partnerships is subject to risks that can cause the actual number of wells
drilled by a partnership or the partnerships to vary from the managing general
partner's estimate. (See "Risk Factors - Risks Related to an Investment in a
Partnership - The Partnerships Do Not Own Any Prospects, the Managing General
Partner Has Complete Discretion to Select Which Prospects are Acquired By a
Partnership, and The Possible Lack of Information for a Majority of the
Prospects Decreases Your Ability to Evaluate the Feasibility of a Partnership.")

                                       29
NATURAL GAS AND OIL REVENUES

Subject to the managing general partner's subordination obligation, the
investors and the managing general partner will share in each partnership's
revenues in the same percentages as their respective capital contributions bear
to the total partnership capital contributions for that partnership except that
the managing general partner will receive an additional 7% of that partnership's
revenues. However, the managing general partner's total revenue share may not
exceed 40% of that partnership's revenues regardless of the amount of its
capital contribution.

For example, if the managing general partner contributes the minimum of 25% of
the partnership's total capital contributions and the investors contribute 75%
of the partnership's total capital contributions, then the managing general
partner will receive 32% of the partnership's revenues and the investors will
receive 68% of the partnership's revenues. On the other hand, if the managing
general partner contributes 35% of the partnership's total capital contributions
and the investors contribute 65% of the partnership's total capital
contributions, then the managing general partner will receive 40% of the
partnership's revenues, not 42%, because its revenue share cannot exceed 40% of
the partnership's revenues, and the investors will receive 60% of the
partnership's revenues.

As noted above, up to 50% of the managing general partner's revenue share from
each partnership is subject to its subordination obligation as described in
"Participation in Costs and Revenues - Subordination of Portion of Managing
General Partner's Net Revenue Share" and the accompanying tables. For example,
if the managing general partner's revenue share is 35% of the partnership's
revenues, then up to 17.5% of the managing general partner's partnership net
production revenues could be used for its subordination obligation.

LEASE COSTS

Under the partnership agreement the managing general partner will contribute to
each partnership all the undeveloped leases necessary to cover each of the
partnership's prospects. The managing general partner will receive a credit to
its capital account equal to:

     o    the cost of the leases; or

     o    the fair market value of the leases if the managing general partner
          has reason to believe that cost is materially more than the fair
          market value.

In the primary drilling areas, the managing general partner's lease costs are
approximately $11,310 per prospect assuming a partnership acquires 100% of the
working interest in the prospect. The cost of the leases includes a portion of
the managing general partner's reasonable, necessary and actual expenses for
geological, engineering, drafting, accounting, legal and other like services
allocated to the leases in conformity with generally accepted accounting
principles and industry standards. Also, the managing general partner has
averaged the cost of all of its leases to arrive at the average lease cost of
$11,310 per prospect, which the managing general partner believes is less than
fair market value. Notwithstanding, from time to time, the managing general
partner's lease costs on a prospect may be significantly higher than this
amount, and in that event the managing general partner's credit to its capital
contribution to the partnership and its capital account under the partnership
agreement will be the greater amount.

The managing general partner's credit for its lease costs for a prospect will be
proportionally reduced to the extent a partnership acquires less than 100% of
the working interest in the prospect. In this regard, a working interest
generally means an interest in the lease under which the owner of the working
interest must pay some portion of the cost of development, operation, or
maintenance of the well. Assuming all the leases are situated in the primary
areas, the managing general partner estimates that its total credit for lease
costs will be:

     o    $79,170 if subscription proceeds of $2 million are received, which is
          seven net wells times $11,310 per prospect; and

     o    $8,030,100 if subscription proceeds of $200 million are received,
          which is 710 net wells times $11,310 per prospect.

                                       30
Drilling a partnership's wells also may provide the managing general partner
with offset prospects to be drilled by allowing it to determine at the
partnership's expense the value of adjacent acreage in which the partnership
would not have any interest. Further, the managing general partner may drill
wells on leases that are scheduled to expire in order to prevent the expiration
of the lease.

DRILLING CONTRACTS

Each partnership will enter into the drilling and operating agreement with the
managing general partner to drill and complete each partnership's wells for an
amount equal to the sum of the following items: (i) the cost of permits,
supplies, materials, equipment, and all other items used in the drilling and
completion of a well provided by third-parties, or if the foregoing items are
provided by affiliates of the managing general partner, then those items will be
charged at competitive rates; (ii) fees for third-party services; (iii) fees for
services provided by the managing general partner's affiliates, which will be
charged at competitive rates; (iv) an administration and oversight fee of
$15,000 per well, which will be charged to you and the other investors as part
of each well's intangible drilling costs and the portion of equipment costs paid
by you and the other investors; and (v) a mark-up in an amount equal to 15% of
the sum of (i), (ii), (iii) and (iv), above, for the managing general partner's
services as general drilling contractor.

The managing general partner has determined that this is a competitive rate
based on:

     o    information it has concerning drilling rates of third-party operators
          in the Appalachian Basin;

     o    the estimated costs of non-affiliated persons to drill and equip wells
          in the Appalachian Basin as reported for 2004 by an independent
          industry association that surveyed operators in the area, including
          the managing general partner and its affiliates; and

     o    information it has concerning increases in drilling costs in the area
          since 2004.

If this rate subsequently exceeds competitive rates available from
non-affiliated persons in the area engaged in the business of rendering or
providing comparable services or equipment, then the rate will be adjusted to
the competitive rate. Additionally, the 15% mark-up and the managing general
partner's administration and oversight fee in the amount of $15,000 per well
will not be increased by the managing general partner during the term of the
partnership.

The managing general partner expects to subcontract some of the actual drilling
and completion of each partnership's wells to third-parties selected by it as
well as to its affiliates. The managing general partner may not benefit by
interpositioning itself between the partnership and the actual provider of
drilling contractor services, and may not profit by drilling in contravention of
its fiduciary obligations to the partnership. However, the managing general
partner's affiliates may charge a competitive rate if they meet the requirements
described in "Conflicts of Interest - Conflicts Regarding Transactions with the
Managing General Partner and its Affiliates."

The cost of each partnership well includes all of the ordinary costs of
drilling, testing and completing the well. This includes the cost of the
following items with respect to each natural gas well, which will be the
classification of the majority of the wells:

     o    multiple completions, which generally means treating separately all
          potentially productive geological formations in an attempt to enhance
          the natural gas production from the well;

     o    installing gathering lines of up to 2,500 feet per well to connect the
          well's natural gas production to a pipeline; and

     o    the necessary surface facilities for producing natural gas from the
          well.

The amount paid to the managing general partner for drilling and completing a
partnership well will be proportionately reduced to the extent the partnership
acquires less than 100% of the working interest in the prospect. In addition,
the amount

                                       31
of compensation that the managing general partner could earn as a result of
these arrangements depends on many other factors as well, including the
following:

     o    where the wells are drilled and their depths;

     o    the method used to complete the well; and

     o    the number of wells drilled.

Assuming the maximum subscription proceeds of $200 million are received, the
managing general partner anticipates that the partnerships' weighted average
cost of drilling and completing approximately 710 net wells and 777 gross wells,
excluding lease costs, will be approximately $339,128 per net well, which
includes the administration and oversight fee of $15,000 per well (included as
part of the intangible drilling costs and the portion of the equipment costs of
the well charged to the investors) and the 15% mark-up per well paid to the
managing general partner for its services as general drilling contractor. This
estimate also was based on the managing general partner's estimate of:

     o    the number of wells that will be drilled in each area by the
          partnerships;

     o    the percentage of working interest that the partnerships will acquire
          in the prospects in each area; and

     o    the estimated drilling and completion costs of the wells to be drilled
          by the partnerships, which are different for wells in each area,
          primarily because of different depths of the wells and different
          completion methods.

Thus, the managing general partner's estimated weighted average cost of drilling
and completing one net well as set forth above, in all likelihood, will vary
from the actual average cost of the wells in each of the primary areas and for a
partnership's wells as a whole.

Based on the assumptions and the estimated weighted average cost for one net
well as set forth above, the managing general partner expects that its 15%
mark-up will be approximately $42,254 per net well with respect to the
intangible drilling costs and the portion of equipment costs paid by you and the
other investors. The actual compensation received by the managing general
partner as a result of each partnership's drilling operations will vary from
these estimates, and the managing general partner anticipates that the
partnerships will acquire less than 100% of the working interest in some of
their respective prospects.

Subject to the foregoing, the managing general partner estimates that its
administration and oversight fee of $15,000 and its 15% mark-up of approximately
$42,254 for one net well, which totals $57,254 per net well, will be:

     o    $400,778 if subscription proceeds of $2 million are received, which is
          seven net wells times $57,254; and

     o    $40,650,340 if subscription proceeds of $200 million are received,
          which is 710 net wells times $57,254.

Additionally, affiliates of the general partner will provide subcontracting
services, equipment and materials in drilling, completing or operating the
partnership's wells for which they will receive competitive rates, because they
meet the requirements described in "Conflicts of Interest - Conflicts Regarding
Transactions with the Managing General Partner and its Affiliates." Thus, the
total compensation paid to the managing general partner and its affiliates per
net well will be greater than the estimated amount to be paid to the managing
general partner as described above to the extent compensation is paid by the
partnerships to the managing general partner's affiliates for services,
equipment or supplies they provide to the partnerships.

The managing general partner's estimated weighted average cost of $339,128 for
one net well to be drilled by a partnership as discussed above consists of:

     o    intangible drilling costs of approximately $253,521 (75%); and

                                       32
o    equipment costs of approximately $85,607 (25%).

The managing general partner further anticipates that a partnership's cost of
drilling and completing any given well in the primary areas as described in
"Proposed Activities," excluding lease costs, may be considerably more or less
than the average weighted cost of approximately $339,128 to drill and complete
one net well, excluding lease costs, depending primarily on the area where the
well is situated, the partnership's percentage ownership of the working interest
in the well and unanticipated cost overruns.

PER WELL CHARGES

Under the drilling and operating agreement the managing general partner, as
operator of the wells, will receive the following compensation from each
partnership when the wells begin producing natural gas or oil:

     o    reimbursement at actual cost for all direct expenses incurred on
          behalf of the partnership; and

     o    well supervision fees at a competitive rate for operating and
          maintaining the wells during producing operations.

Currently the competitive rate for well supervision fees is $362 per well per
month in the primary and secondary areas discussed in "Proposed Activities." The
well supervision fees will be proportionately reduced to the extent the
partnership acquires less than 100% of the working interest in the well. Also,
the managing general partner's well supervision fees may be adjusted annually
beginning with the first calendar year after a partnership closes for inflation
since January 1, 2007. If the managing general partner's well supervision fee
would exceed a competitive rate in the area where the well is situated, then the
rate will be adjusted to the competitive rate. Conversely, if in the future the
managing general partner's well supervision fee set forth above would be less
than a competitive rate in the area where the well is situated, then regardless
of the inflation adjustment, the rate may be increased automatically to the
competitive rate from time to time by the managing general partner, as operator,
as determined in its sole discretion. The managing general partner may not
benefit by interpositioning itself between the partnership and the actual
provider of operator services. In no event will any consideration received for
operator services be duplicative of any consideration or reimbursement received
under the partnership agreement.

The well supervision fee covers all normal and regularly recurring operating
expenses for the production, delivery, and sale of natural gas and oil, such as:

     o    well tending, routine maintenance, and adjustment;

     o    reading meters, recording production, pumping, maintaining appropriate
          books and records; and

     o    preparing reports to the partnership and to government agencies.

The well supervision fees do not include costs and expenses related to: o the
purchase of equipment, materials, or third-party services;

     o    brine disposal; and

     o    rebuilding of access roads.

These costs will be charged to a partnership at the invoice cost of the
materials purchased or the third-party services performed.

The managing general partner estimates that it will receive well supervision
fees for a partnership's first 12 months of operation after all of the wells
have been placed in production of:

                                       33
o    $30,408 if subscription proceeds of $2 million are received, which is
          seven net wells at $362 per well per month; and

     o    $3,084,240 if subscription proceeds of $200 million are received,
          which is 710 net wells at $362 per well per month.

GATHERING FEES

Under the partnership agreement the managing general partner will be responsible
for gathering and transporting the natural gas produced by the partnerships to
interstate pipeline systems, local distribution companies, and/or end-users in
the area (the "gathering services"). The managing general partner anticipates
that it will use the gathering system owned by Atlas Pipeline Partners for the
majority of the partnerships' natural gas production as described in "Proposed
Activities - Sale of Natural Gas and Oil Production - Gathering of Natural Gas."
The managing general partner's affiliate, Atlas America, Inc., which is
sometimes referred to in this prospectus as "Atlas America," or another
affiliate controls and manages the gathering system for Atlas Pipeline Partners.
(See "Management - Organizational Diagram and Security Ownership of Beneficial
Owners.") Also, Atlas America and the managing general partner's affiliates,
Resource Energy, LLC, sometimes referred to in this prospectus as "Resource
Energy," and Viking Resources LLC, sometimes referred to in this prospectus as
"Viking Resources," which are sometimes referred to collectively in this
prospectus as the "Atlas Entities," which do not include the partnerships, have
an agreement with Atlas Pipeline Partners under which generally all of the gas
produced by their affiliated partnerships, which does include the partnerships,
will be gathered and transported through the gathering system owned by Atlas
Pipeline Partners, and that the Atlas Entities must pay the greater of $.35 per
mcf or 16% of the gross sales price for each mcf transported by these affiliated
partnerships through Atlas Pipeline Partners' gathering system. Gross sales
price means the price that is actually received, adjusted to take into account
proceeds received or payments made pursuant to hedging arrangements. Subject to
the agreement with Atlas Pipeline Partners described above, in providing the
gathering services the managing general partner may use gathering systems owned
by Atlas Pipeline Partners, independent third-parties and/or affiliates of Atlas
America other than Atlas Pipeline Partners.

Each partnership will pay a gathering fee directly to the managing general
partner at competitive rates for the gathering services. The gathering fee paid
by the partnership to the managing general partner may be increased from
time-to-time by the managing general partner, in its sole discretion, but may
not be increased beyond competitive rates as determined by the managing general
partner. Currently, the managing general partner has determined that the
competitive rate in each of its primary and secondary areas where it drills its
wells as described in "Proposed Activities" is an amount equal to 10% of the
gross sales price received by each partnership for its natural gas.

The payment of a competitive fee to the managing general partner for its
gathering services shall be subject to the following conditions:

     o    If the gathering system owned by Atlas Pipeline Partners is used by a
          partnership, then the managing general partner will apply the
          gathering fee it receives from the partnership towards the payments
          owed by the Atlas Entities under their agreement with Atlas Pipeline
          Partners.

     o    If a third-party gathering system is used by a partnership, the
          managing general partner will pay a portion or all of the gathering
          fee it receives from the partnership to the third-party gathering the
          natural gas. The managing general partner may retain the excess of any
          gathering fees it receives from the partnership over the payments it
          makes to third-party gas gatherers. If the third-party's gathering
          system charges more than an amount equal to 10% of the gross sales
          price, then the managing general partner's gathering fee charged to a
          partnership will be the actual transportation and compression fees
          charged by the third-party gathering system with respect to the
          partnership's natural gas in the area.

     o    If both a third-party gathering system and the Atlas Pipeline Partners
          gathering system (or a gas gathering system owned by an affiliate of
          Atlas America other than Atlas Pipeline Partners) are used by a
          partnership, then the managing general partner will receive an amount
          equal to 10% of the gross sales price plus the amount charged by the
          third-party gathering system. For purposes of illustration, but not
          limitation, certain

                                       34
wells drilled by a partnership in the Upper Devonian Sandstone
          Reservoirs in the McKean County, Pennsylvania secondary area will
          deliver natural gas produced in this area into a gathering system, a
          segment of which will be provided by Atlas Pipeline Partners and a
          segment of which will be provided by a third-party. In this area, the
          managing general partner's competitive gathering fee will include the
          third-party's fee of $.35 per mcf for transportation and compression,
          including any increase in the fee by the third-party gatherer from
          time-to-time, which it will then pay to the third-party gatherer, and
          the managing general partner will also receive a gathering fee equal
          to 10% of the gross sales price.

Finally, in connection with the Knox project in the Mississippian and Devonian
Shale Reservoirs in the Anderson, Campbell, Morgan, Roane and Scott Counties,
Tennessee area, as discussed in "Proposed Activities - Primary Areas of
Operations - Mississippian Carbonate and Devonian Shale Reservoirs in Anderson,
Campbell, Morgan, Roane and Scott Counties, Tennessee," a partnership will
deliver natural gas into a gathering system provided by Knox Energy, which is
referred to as the Coalfield Pipeline. The Coalfield Pipeline will receive
gathering fees of $.55 per mcf plus fees for compression, which it may increase
from time-to-time. If the Coalfield Pipeline does not have sufficient capacity
to compress and transport the natural gas produced from a partnership's wells as
determined by Atlas America, then Atlas America or an affiliate other than Atlas
Pipeline Partners may construct an additional gathering system and/or
enhancements to the Coalfield Pipeline. On completion of the construction, Atlas
America will transfer its ownership in the additional gathering system and/or
enhancements to the owners of the Coalfield Pipeline, which will then pay Atlas
America an amount equal to $.12 per mcf of natural gas transported through the
newly constructed and/or enhanced gathering system. If the events described
above occur, Coalfield Pipeline will pay this amount to Atlas America from the
gathering and compression fees it charges to a partnership. The managing general
partner's gathering fee in this area also will be 10% of the gross sales price
of the partnership's natural gas, but will be increased to include the amount of
the Coalfield Pipeline fees, if greater, which the managing general partner will
then pay to the Coalfield Pipeline.

The actual amount of gathering fees to be paid by a partnership to the managing
general partner cannot be quantified, because the volume of natural gas that
will be produced and transported from the partnership's wells cannot be
predicted.

DEALER-MANAGER FEES

Subject to certain exceptions described in "Plan of Distribution," Anthem
Securities, the dealer-manager and an affiliate of the managing general partner,
will receive on each unit sold to an investor:

     o    a 2.5% dealer-manager fee;

     o    a 7% sales commission; and

     o    an up to .5% reimbursement of the selling agents' bona fide due
          diligence expenses.

Assuming the above amounts are paid for all units sold, the dealer-manager will
receive:

     o    $200,000 if subscription proceeds of $2 million are received by a
          partnership; and

     o    $20 million if subscription proceeds of $200 million are received by
          the partnerships.

All of the reimbursement of the selling agents' bona fide due diligence
expenses, and generally all of the sales commissions, will be reallowed to the
selling agents. A portion of the 2.5% dealer-manager fee will be reallowed to
the wholesalers who are associated with the managing general partner and
registered through Anthem Securities for subscriptions obtained through their
efforts. Also, a portion of the dealer-manager fee may be reallowed to the
selling agents as described in "Plan of Distribution." The dealer-manager will
retain any of the compensation which is not reallowed. See "Management" for the
ownership of Anthem Securities.

INTEREST AND OTHER COMPENSATION

The managing general partner or an affiliate will have the right to charge a
competitive rate of interest on any loan it may make to or on behalf of a
partnership. If the managing general partner provides equipment, supplies, and
other services to a

                                       35
partnership, then it may do so at competitive industry rates. The managing
general partner will determine competitive industry rates for equipment,
supplies and other services by conducting a survey of the interest and/or fees
charged by unaffiliated third-parties in the same geographic area engaged in
similar businesses. If possible, the managing general partner will contact at
least two unaffiliated third-parties, however, the managing general partner will
have sole discretion in determining the amount to be charged a partnership.

ESTIMATE OF ADMINISTRATIVE COSTS AND DIRECT COSTS TO BE BORNE BY THE
PARTNERSHIPS

The managing general partner and its affiliates will receive from each
partnership a nonaccountable, fixed payment reimbursement for their
administrative costs, which has been determined by the managing general partner
to be $75 per well per month. This payment per well is subject to the following:

     o    it will not be increased in amount during the term of the partnership;

     o    it will be proportionately reduced to the extent the partnership
          acquires less than 100% of the working interest in the well;

     o    it will be the entire payment to reimburse the managing general
          partner for the partnership's administrative costs; and

     o    it will not be received for plugged or abandoned wells.

The managing general partner estimates that the nonaccountable, fixed payment
reimbursement for administrative costs allocable to a partnership's first 12
months of operation after all of its wells have been placed into production will
not exceed approximately:

     o    $6,300 if subscription proceeds of $2 million are received, which is
          seven net wells at $75 per well per month; and

     o    $639,000 if subscription proceeds of $200 million are received, which
          is 710 net wells at $75 per well per month.

Direct costs will be determined by the managing general partner, in its sole
discretion, including the provider of the services or goods and the amount of
the provider's compensation. Direct costs will be billed directly to and paid by
each partnership to the extent practicable. The anticipated direct costs set
forth below for a partnership's first 12 months of operation after all of its
wells have been placed into production may vary from the estimates shown for
numerous reasons that cannot accurately be predicted. These reasons include:

     o    the number of the partnership's investors;

     o    the number of wells drilled by the partnership;

     o    the partnership's degree of success in its activities;

     o    the extent of any production problems encountered by the partnership;

     o    inflation; and

     o    various other factors involving the administration of the partnership.

                                       36
Minimum            Maximum
                                                       Subscriptions      Subscriptions
                                                       of $2 million   of $200 million (1)
                                                       -------------   -------------------
DIRECT COSTS
   External Legal ..................................      $ 6,000            $ 24,000
   Accounting Fees for Audit and Tax Preparation ...       25,000             150,000
   Independent Engineering Reports .................        1,500              40,000
                                                          -------            --------
   TOTAL ...........................................      $32,500            $214,000
                                                          =======            ========
----------
(1)  This assumes two partnerships are formed as described below in "Terms of
     the Offering - Subscription to a Partnership" and the targeted nonbinding
     subscriptions of each partnership are received.

                              TERMS OF THE OFFERING

SUBSCRIPTION TO A PARTNERSHIP

Atlas America Public #16-2007 Program was formed to offer for sale an aggregate
of $200 million of units in a series of up to two limited partnerships, each of
which has been formed under the Delaware Revised Uniform Limited Partnership
Act.

The targeted subscriptions for each partnership are set forth below. These
targeted amounts are not mandatory, and the managing general partner may
determine the final subscription amount for each partnership in its sole
discretion. The maximum subscription of any partnership, however, must be the
lesser of:

     o    $200 million; or

     o    $200 million less the total subscription proceeds received by any
          prior partnership in the program.

Also, set forth below are the targeted ending dates for each partnership, which
are not binding except that the units in each partnership may not be offered
beyond that partnership's offering termination date as set forth below. The
managing general partner may close the offering of units in a partnership at any
time before that partnership's offering termination date once the partnership is
in receipt of the minimum required subscriptions, and the managing general
partner may withdraw the offering of units in any partnership at any time.
REQUIRED       TARGETED       TARGETED      OFFERING
                                      MINIMUM     SUBSCRIPTION      ENDING     TERMINATION
PARTNERSHIP NAME                   SUBSCRIPTION     PROCEEDS     DATE (1)(2)   DATE (1)(2)
--------------------------------   ------------   ------------   -----------   -----------
Atlas America Public #16-2007(A)   $2 million     $100 million     06/30/07      12/31/07
Atlas America Public #16-2007(B)   $2 million     $100 million     12/31/07      12/31/07
----------
(1)  The units in the above partnerships will be offered and sold only during
     2007.

(2)  Units in Atlas America Public #16-2007(B) L.P. will not be offered until
     the offering of units in Atlas America Public #16-2007(A) L.P. has
     terminated.

Units are offered at a subscription price of $10,000 per unit, subject to
certain exceptions described in "Plan of Distribution," and must be paid 100% in
cash at the time of subscribing. The subscription price of the units has been
arbitrarily determined by the managing general partner because the partnerships
do not have any prior operations, assets, earnings, liabilities or present
value. Your minimum subscription is one unit ($10,000). Larger fractional
subscriptions will be accepted in $1,000 increments, beginning with $11,000,
$12,000, etc.

You may elect to purchase units in a partnership as either an investor general
partner or a limited partner. However, even though you may elect to subscribe as
an investor general partner the managing general partner will have exclusive
management authority for each partnership. Each partnership will be a separate
business entity from the other partnership.

                                       37
Thus, as an investor, you will be a partner only in the partnership in which you
invest. You will have no interest in the business, distributions, assets or tax
benefits of the other partnership unless you also invest in the other
partnership. Your investment return will depend solely on the operations and
success or lack of success of the particular partnership in which you invest.

PARTNERSHIP CLOSINGS AND ESCROW

You and the other investors should make your checks for units payable to "Atlas
America Public #16-2007(A) L.P., Escrow Agent, National City Bank of PA" or
"Atlas America Public #16-2007(B) L.P., Escrow Agent, National City Bank of PA,"
depending on which partnership is then being offered at the time you subscribe
for units, and give your check to your broker/dealer for submission to the
dealer-manager and escrow agent. Subscription proceeds for each partnership will
be held in a separate interest bearing escrow account at National City Bank of
Pennsylvania until each partnership has received subscription proceeds of at
least $2 million, excluding the subscription price discounts described in "Plan
of Distribution" and excluding any subscriptions by the managing general partner
or its affiliates. However, on receipt of the minimum subscription proceeds and
written instructions to the escrow agent from the managing general partner and
the dealer-manager, the managing general partner on behalf of a partnership may
break escrow and transfer the escrowed subscription proceeds to a partnership
account, enter into the drilling and operating agreement with itself or an
affiliate as operator, and begin drilling operations for the partnership.

If the minimum subscription proceeds are not received by the offering
termination date of a partnership, then the subscription proceeds deposited in
the escrow account will be promptly returned to you and the other subscribers in
that partnership with interest and without deduction for any fees. In this
regard, the latest offering termination date for each partnership is December
31, 2007. Although the managing general partner and its affiliates may buy up to
5% of the total units sold in this offering, currently they do not anticipate
purchasing any units. If they do buy units, then those units will not be applied
towards the minimum subscription proceeds required for a partnership to break
escrow and begin operations. Also, any units purchased by the managing general
partner and its affiliates must be purchased for investment purposes only, and
not with a view toward redistribution.

You will receive interest on your subscription proceeds from the time they are
deposited in the escrow account, or the partnership account if you subscribe
after the minimum subscription proceeds have been received and escrow has been
broken, until the final closing of the offering period for the partnership to
which you subscribed. The interest will be paid to you not later than your
partnership's first cash distribution from operations.

During each partnership's escrow period its subscription proceeds will be
invested only in institutional investments comprised of, or secured by,
securities of the United States government. After the funds are transferred to a
partnership account and before their use in partnership operations, they may be
temporarily invested in income producing short-term, highly liquid investments,
in which there is appropriate safety of principal, such as U.S. Treasury Bills.
If the managing general partner determines that a partnership may be deemed to
be an investment company under the Investment Company Act of 1940, then the
investment activity will cease. Subscription proceeds will not be commingled
with the funds of the managing general partner or its affiliates, nor will
subscription proceeds be subject to their creditors' claims, before they are
paid to the managing general partner under the drilling and operating agreement.

ACCEPTANCE OF SUBSCRIPTIONS

Your execution of the subscription agreement constitutes your offer to buy units
in the partnership then being offered and to hold the offer open until either:

o    your subscription is accepted or rejected by the managing general partner;
     or

o    you withdraw your offer.

To rescind or withdraw your subscription agreement, you must give written notice
to the managing general partner before your subscription agreement is accepted
by the managing general partner.

Also, the managing general partner will:

                                       38
o    not complete a sale of units to you until at least five business days
          after the date you receive a final prospectus; and

     o    send you a confirmation of purchase.

Subject to the foregoing, your subscription agreement will be accepted or
rejected by the partnership within 30 days of its receipt. The managing general
partner's acceptance of your subscription is discretionary, and the managing
general partner may reject your subscription for any reason without incurring
any liability to you for this decision. If your subscription is rejected, then
all of your funds will be promptly returned to you together with any interest
earned on your subscription proceeds and without deduction for any fees.

When you will be admitted to a partnership depends on whether your subscription
is accepted before or after a partnership breaks escrow. If your subscription is
accepted:

     o    before breaking escrow, then you will be admitted to the partnership
          to which you subscribed not later than 15 days after the release from
          escrow of the investors' subscription proceeds to that partnership; or

     o    after breaking escrow, then you will be admitted to the partnership to
          which you subscribed not later than the last day of the calendar month
          in which your subscription was accepted by that partnership.

Your execution of the subscription agreement and the managing general partner's
acceptance also constitutes your:

     o    execution of the partnership agreement and agreement to be bound by
          its terms as a partner; and

     o    grant of a special power of attorney to the managing general partner
          to file amended certificates of limited partnership and governmental
          reports, and perform certain other actions on behalf of you and the
          other investors as partners of a partnership.

SUITABILITY STANDARDS

IN GENERAL. It is the obligation of persons selling the units to make every
reasonable effort to assure that the units are suitable for you based on your
investment objectives and financial situation, regardless of your income or net
worth. However, you should invest in a partnership only if you are willing to
assume the risk of a speculative, illiquid, and long-term investment. Also,
subscriptions to a partnership will not be accepted from IRAs, Keogh plans and
qualified retirement plans, because the partnership's income would be
characterized as unrelated business taxable income, which is subject to federal
income tax.

The decision to accept or reject your subscription will be made by the managing
general partner, in its sole discretion, and is final. The managing general
partner will not accept your subscription until it has reviewed your apparent
qualifications, and the suitability determination must be maintained by the
managing general partner during the partnership's term and for at least six
years thereafter.

GENERAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF LIMITED PARTNER UNITS. If you
are a resident of any of the following states or jurisdictions:

                                       39
o    ALABAMA,

     o    ALASKA,

     o    ARIZONA,

     o    ARKANSAS,

     o    COLORADO,

     o    CONNECTICUT,

     o    DELAWARE,

     o    DISTRICT OF COLUMBIA,

     o    FLORIDA,

     o    GEORGIA,

     o    HAWAII,

     o    IDAHO,

     o    ILLINOIS,

     o    INDIANA,

     o    IOWA,

     o    KANSAS,

     o    KENTUCKY,

     o    LOUISIANA,

     o    MAINE,

     o    MARYLAND,

     o    MASSACHUSETTS,

     o    MINNESOTA,

     o    MISSISSIPPI,

     o    MISSOURI,

     o    MONTANA,

     o    NEBRASKA,

     o    NEVADA,

     o    NEW MEXICO,

     o    NEW YORK,

     o    NORTH DAKOTA,

     o    OKLAHOMA,

     o    OREGON,

     o    PENNSYLVANIA,

     o    RHODE ISLAND,

     o    SOUTH CAROLINA,

     o    SOUTH DAKOTA,

     o    TENNESSEE,

     o    TEXAS,

     o    UTAH,

     o    VERMONT,

     o    VIRGINIA,

     o    WASHINGTON,

     o    WEST VIRGINIA,

     o    WISCONSIN, OR

     o    WYOMING,

then limited partner units may be sold to you if you meet either of the
following requirements:

     o    a minimum net worth of $225,000, exclusive of home, home furnishings,
          and automobiles; or

     o    a minimum net worth of $60,000, exclusive of home, home furnishings,
          and automobiles, and had during the last tax year or estimate that you
          will have during the current tax year "taxable income" as defined in
          Section 63 of the Internal Revenue Code of at least $60,000, without
          regard to an investment in the partnership.

In addition, if you are a resident of PENNSYLVANIA, then you must not make an
investment in a partnership which is in excess of 10% of your net worth,
exclusive of home, home furnishings and automobiles. Finally, if you are a
resident of KANSAS, it is recommended by the Office of the Kansas Securities
Commissioner that Kansas investors should limit their investment in the program
and substantially similar programs to no more than 10% of their net worth,
excluding home, furnishings and automobiles.

However, if you are a resident of the states set forth below, then different
suitability requirements apply to you.

SPECIAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF LIMITED PARTNER UNITS.

     o    If you are a resident of CALIFORNIA or NEW JERSEY and you subscribe
          for limited partner units, then you must meet any one of the following
          special suitability requirements:

          o    a net worth of not less than $250,000, exclusive of home, home
               furnishings, and automobiles, and expect to have gross income in
               the current tax year of $65,000 or more; or

                                       40
o    a net worth of not less than $500,000, exclusive of home, home
               furnishings, and automobiles; or

          o    a net worth of not less than $1 million; or

          o    expected gross income in the current tax year of not less than
               $200,000.

     o    If you are a resident of MICHIGAN or NORTH CAROLINA and you subscribe
          for limited partner units, then you must meet either of the following
          special suitability requirements:

          o    a net worth of not less than $225,000, exclusive of home, home
               furnishings, and automobiles; or

          o    a net worth of not less than $60,000, exclusive of home, home
               furnishings, and automobiles, and estimated current tax year
               taxable income as defined in Section 63 of the Internal Revenue
               Code of $60,000 or more without regard to an investment in the
               partnership.

          Additionally, if you are a resident of MICHIGAN, then you must not
          make an investment in a partnership which is in excess of 10% of your
          net worth, exclusive of home, home furnishings and automobiles.

     o    If you are a resident of NEW HAMPSHIRE and you subscribe for limited
          partner units, then you must meet either of the following special
          suitability requirements:

          o    a net worth of not less than $250,000, exclusive of home, home
               furnishings, and automobiles; or

          o    a net worth of not less than $125,000, exclusive of home, home
               furnishings, and automobiles and $50,000 of taxable income.

     o    If you are a resident of OHIO and you subscribe for limited partner
          units, then you must meet, without regard to your investment in a
          partnership, either of the following special suitability requirements:

          o    a net worth of not less than $330,000, exclusive of home, home
               furnishings, and automobiles; or

          o    a net worth of not less than $85,000, exclusive of home, home
               furnishings, and automobiles, and an annual gross income during
               the current tax year of at least $85,000.

          Additionally, if you are a resident of OHIO you must not make an
          investment in a partnership which would, after including your previous
          investments in prior Atlas Resources programs, if any, and any other
          similar natural gas and oil drilling programs, exceed 10% of your net
          worth, exclusive of home, home furnishings and automobiles.

GENERAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF INVESTOR GENERAL PARTNER
UNITS. If you are a resident of any of the following states or jurisdictions:

                                       41
o    ALASKA,

     o    COLORADO,

     o    CONNECTICUT,

     o    DELAWARE,

     o    DISTRICT OF COLUMBIA,

     o    FLORIDA,

     o    GEORGIA,

     o    HAWAII,

     o    IDAHO,

     o    ILLINOIS,

     o    LOUISIANA,

     o    MARYLAND,

     o    MONTANA,

     o    NEBRASKA,

     o    NEVADA,

     o    NEW YORK,

     o    NORTH DAKOTA,

     o    RHODE ISLAND,

     o    SOUTH CAROLINA,

     o    UTAH,

     o    VIRGINIA,

     o    WEST VIRGINIA,

     o    WISCONSIN, OR

     o    WYOMING,

then investor general partner units may be sold to you if you meet either of the
following requirements:

     o    a minimum net worth of $225,000, exclusive of home, home furnishings,
          and automobiles; or

     o    a minimum net worth of $60,000, exclusive of home, home furnishings,
          and automobiles, and had during the last tax year or estimate that you
          will have during the current tax year "taxable income" as defined in
          Section 63 of the Internal Revenue Code of at least $60,000, without
          regard to an investment in the partnership.

However, if you are a resident of the states set forth below, then different
suitability requirements apply to you if you purchase investor general partner
units.

SPECIAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF INVESTOR GENERAL PARTNER
UNITS.

     o    If you are a resident of any of the following states:

          o    ALABAMA,

          o    ARKANSAS,

          o    INDIANA,

          o    MAINE,

          o    MASSACHUSETTS,

          o    MINNESOTA,

          o    NORTH CAROLINA,

          o    OKLAHOMA,

          o    PENNSYLVANIA,

          o    TENNESSEE,

          o    TEXAS, OR

          o    WASHINGTON

          and you subscribe for investor general partner units, then you must
          meet any one of the following special suitability requirements:

          o    an individual or joint net worth with your spouse of $225,000 or
               more, without regard to the investment in the partnership,
               exclusive of home, home furnishings, and automobiles, and A
               COMBINED GROSS INCOME OF $100,000 OR MORE FOR THE CURRENT YEAR
               AND FOR THE TWO PREVIOUS YEARS; or

          o    an individual or joint net worth with your spouse in excess of $1
               million, inclusive of home, home furnishings, and automobiles; or

          o    an individual or joint net worth with your spouse in excess of
               $500,000, exclusive of home, home furnishings, and automobiles;
               or

                                       42
o    a combined "gross income" as defined in Internal Revenue Code
               Section 61 in excess of $200,000 in the current year and the two
               previous years.

          o    In addition, if you are a resident of PENNSYLVANIA, then you must
               not make an investment in a partnership which is in excess of 10%
               of your net worth, exclusive of home, home furnishings, and
               automobiles.

     o    If you are a resident of any of the following states:

          o    ARIZONA,

          o    IOWA,

          o    KANSAS,

          o    KENTUCKY,

          o    MICHIGAN,

          o    MISSISSIPPI,

          o    MISSOURI,

          o    NEW MEXICO,

          o    OREGON,

          o    SOUTH DAKOTA, OR

          o    VERMONT

          and you subscribe for investor general partner units, then you must
          meet any one of the following special suitability requirements:

          o    an individual or joint net worth with your spouse of $225,000 or
               more, without regard to the investment in the partnership,
               exclusive of home, home furnishings, and automobiles, and A
               COMBINED "TAXABLE INCOME" OF $60,000 OR MORE FOR THE PREVIOUS
               YEAR AND EXPECT TO HAVE A COMBINED "TAXABLE INCOME" OF $60,000 OR
               MORE FOR THE CURRENT YEAR AND FOR THE SUCCEEDING YEAR; or

          o    an individual or joint net worth with your spouse in excess of $1
               million, inclusive of home, home furnishings, and automobiles; or

          o    an individual or joint net worth with your spouse in excess of
               $500,000, exclusive of home, home furnishings, and automobiles;
               or

          o    a combined "gross income" as defined in Internal Revenue Code
               Section 61 in excess of $200,000 in the current year and the two
               previous years.

          o    In addition, if you are a resident of IOWA OR MICHIGAN, then you
               must not make an investment in a partnership which is in excess
               of 10% of your net worth, exclusive of home, home furnishings,
               and automobiles.

          o    Finally, if you are a resident of KANSAS, it is recommended by
               the Office of the Kansas Securities Commissioner that Kansas
               investors should limit their investment in the program and
               substantially similar programs to no more than 10% of their net
               worth, excluding home, furnishings and automobiles.

     o    If you are a resident of CALIFORNIA or NEW JERSEY and you subscribe
          for investor general partner units, then you must meet any one of the
          following special suitability requirements:

          o    a net worth of not less than $250,000, exclusive of home, home
               furnishings, and automobiles, and expect to have gross income in
               the current tax year of $120,000 or more; or

          o    a net worth of not less than $500,000, exclusive of home, home
               furnishings, and automobiles; or

          o    a net worth of not less than $1 million; or

                                       43
o    expected gross income in the current tax year of not less than
               $200,000.

     o    If you are a resident of NEW HAMPSHIRE and you subscribe for investor
          general partner units, then you must meet either of the following
          special suitability requirements:

          o    a net worth of not less than $250,000, exclusive of home, home
               furnishings, and automobiles; or

          o    a net worth of not less than $125,000, exclusive of home, home
               furnishings, and automobiles, and $50,000 of taxable income.

     o    If you are a resident of OHIO and you subscribe for investor general
          partner units, then you must meet, without regard to your investment
          in a partnership, either of the following special suitability
          requirements:

          o    a net worth of not less than $750,000, exclusive of home, home
               furnishings, and automobiles; or

          o    a net worth of not less than $330,000, exclusive of home, home
               furnishings, and automobiles, and an annual gross income of at
               least $150,000 for the current year and the two previous years.

          Additionally, if you are a resident of OHIO you must not make an
          investment in a partnership which would, after including your previous
          investments in prior Atlas Resources programs, if any, and any other
          similar natural gas and oil drilling programs, exceed 10% of your net
          worth, exclusive of home, home furnishings and automobiles.

FIDUCIARY ACCOUNTS. If there is a sale of a unit to a fiduciary account, then
all of the suitability standards set forth above must be met by the beneficiary,
the fiduciary account, or the donor or grantor who directly or indirectly
supplies the funds to purchase the units if the donor or grantor is the
fiduciary.

Generally, you are required to execute your own subscription agreement, and the
managing general partner will not accept any subscription agreement that has
been executed by someone other than you. The only exception is if you have given
someone else the legal power of attorney to sign on your behalf and you meet all
of the conditions in this prospectus.

                                PRIOR ACTIVITIES

The following tables reflect certain historical data with respect to the private
drilling partnerships and the public drilling partnerships that the managing
general partner has sponsored. The tables also reflect certain historical data
with respect to 1999 Viking Resources LP, a private drilling program that raised
$4,555,210, and is the only drilling program sponsored by Viking Resources after
it was acquired by Resource America, Inc. in August 1999. Information concerning
this program and other programs sponsored by Viking Resources before it was
acquired by Resource America will be provided to you on written request to the
managing general partner. The tables also do not include information concerning
wells acquired by Atlas Resources through merger or other form of acquisition,
and this information also will be available to you on written request to the
managing general partner.

Although past performance is no guarantee of future results, the investor
general partners in the managing general partner's prior partnerships have not
had to make additional capital contributions to their partnerships because of
their status as investor general partners.

IT SHOULD NOT BE ASSUMED THAT YOU AND THE OTHER INVESTORS IN A PARTNERSHIP WILL
EXPERIENCE RETURNS, IF ANY, COMPARABLE TO THOSE EXPERIENCED BY INVESTORS IN THE
PRIOR DRILLING PARTNERSHIPS FOR SEVERAL REASONS, INCLUDING, BUT NOT LIMITED TO,
DIFFERENCES IN:

     o    PARTNERSHIP TERMS;

     o    PROPERTY LOCATIONS;

                                       44
o    PARTNERSHIP SIZE; AND

     o    ECONOMIC CONSIDERATIONS.

THE RESULTS OF THE PRIOR DRILLING PARTNERSHIPS SHOULD BE VIEWED ONLY AS A
MEASURE OF THE LEVEL OF ACTIVITY AND EXPERIENCE OF THE MANAGING GENERAL PARTNER
WITH RESPECT TO DRILLING PARTNERSHIPS.

                                       45
Table 1 sets forth certain sales information of previous development drilling
partnerships sponsored by the managing general partner and its affiliates.

                                     TABLE 1
                           EXPERIENCE IN RAISING FUNDS
                            AS OF SEPTEMBER 15, 2006
Managing
                                             Number                      General
                                          of Original     Investor       Partner         Total
              Partnership                  Investors       Capital       Capital        Capital
---------------------------------------   -----------   ------------   -----------   ------------
1.    Atlas L.P. #1 - 1985                      19      $    600,000   $   114,800   $    714,800
2.    A.E. Partners 1986                        24           631,250       120,400        751,650
3.    A.E. Partners 1987                        17           721,000       158,269        879,269
4.    A.E. Partners 1988                        21           617,050       135,450        752,500
5.    A.E. Partners 1989                        21           550,000       120,731        670,731
6.    A.E. Partners 1990                        27           887,500       244,622      1,132,122
7.    A.E. Nineties-10                          60         2,200,000       484,380      2,684,380
8.    A.E. Nineties-11                          25           750,000       268,003      1,018,003
9.    A.E. Partners 1991                        26           868,750       318,063      1,186,813
10.   A.E. Nineties-12                          87         2,212,500       791,833      3,004,333
11.   A.E. Nineties-JV 92                      155         4,004,813     1,414,917      5,419,730
12.   A.E. Partners 1992                        21           600,000       176,100        776,100
13.   A.E. Nineties-Public #1                  221         2,988,960       528,934      3,517,894
14.   A.E. Nineties-1993 Ltd.                  125         3,753,937     1,264,183      5,018,120
15.   A.E. Partners 1993                        21           700,000       219,600        919,600
16.   A.E. Nineties-Public #2                  269         3,323,920       587,340      3,911,260
17.   A.E. Nineties-14                         263         9,940,045     3,584,027     13,524,072
18.   A.E. Partners 1994                        23           892,500       231,500      1,124,000
19.   A.E. Nineties-Public #3                  391         5,800,990       928,546      6,729,536
20.   A.E. Nineties-15                         244        10,954,715     3,435,936     14,390,651
21.   A.E. Partners 1995                       23            600,000       244,725        844,725
22.   A.E. Nineties-Public #4                  324         6,991,350     1,287,752      8,279,102
23.   A.E. Nineties-16                         274        10,955,465     1,643,320     12,598,785
24.   A.E. Partners 1996                        21           800,000       367,416      1,167,416
25.   A.E. Nineties-Public #5                  378         7,992,240     1,654,740      9,646,980
26.   A.E. Nineties-17                         217         8,813,488     2,113,947     10,927,435
27.   A.E. Nineties-Public #6                  393         9,901,025     1,950,345     11,851,370
28.   A.E. Partners 1997                        13           506,250       231,050        737,300
29.   A.E. Nineties-18                         225        11,391,673     3,448,751     14,840,424
30.   A.E. Nineties-Public #7                  366        11,988,350     3,812,150     15,800,500
31.   A.E. Partners 1998                        26         1,740,000       756,360      2,496,360
32.   A.E. Nineties-19                         288        15,720,450     4,776,598     20,497,048
33.   A.E. Nineties-Public #8                  380        11,088,975     3,148,181     14,237,156
34.   A.E. Partners 1999                         8           450,000       196,500        646,500
35.   1999 Viking Resources LP                 131         4,555,210     1,678,038      6,233,248
36.   Atlas America-Series 20                  361        18,809,150     6,297,945     25,107,095
37.   Atlas America - Public #9                530        14,905,465     6,256,271     21,161,736
38.   Atlas America - Series 21-A              282        12,510,713     4,535,799     17,046,512
39.   Atlas America - Series 21-B              360        17,411,825     6,442,761     23,854,586
40.   Atlas America - Public #10               818        21,281,170     7,227,432     28,508,602
41.   Atlas America - Series 22                258        10,156,375     3,481,591     13,637,966
42.   Atlas America - Series 23                246         9,644,550     3,214,850     12,859,400
43.   Atlas America - Public #11-2002         1017        31,178,145    13,295,226     44,473,371
44.   Atlas America - Series 24-2003(A)        325        14,363,955     4,949,143     19,313,098
45.   Atlas America - Series 24-2003(B)        422        20,542,850     7,300,020     27,842,870
46.   Atlas America - Public #12-2003         1102        40,170,308    13,708,076     53,878,384
47.   Atlas America Series 25-2004(A)          635        27,601,053    10,266,771     37,867,824
48.   Atlas America Series 25-2004(B)          634        31,531,035    16,006,953     47,537,988
49.   Atlas America Public #14-2004           1494        52,506,570    25,971,721     78,478,291
50.   Atlas America Public #14-2005(A)        2192        69,674,900    30,912,583    100,587,483
51.   Atlas America Series 26-2005             579        34,886,465    15,903,570     50,790,035
52.   Atlas America Public #15-2005(A)        1625        52,245,720    21,412,609     73,658,329
53.   Atlas America Public #15-2006(B)        4108       147,513,130    55,159,085    202,672,215
Years
                                             Date         Date of         Wells     Previous
                                          Operations       First           In        Assess-
              Partnership                    Began     Distributions   Production     ments
---------------------------------------   ----------   -------------   ----------   --------
1.    Atlas L.P. #1 - 1985                 12/31/85       07/02/86       20.13         -0-
2.    A.E. Partners 1986                   12/31/86       04/02/87       19.13         -0-
3.    A.E. Partners 1987                   12/31/87       04/02/88       18.13         -0-
4.    A.E. Partners 1988                   12/31/88       04/02/89       17.13         -0-
5.    A.E. Partners 1989                   12/31/89       04/02/90       16.13         -0-
6.    A.E. Partners 1990                   12/31/90       04/02/91       15.13         -0-
7.    A.E. Nineties-10                     12/31/90       03/31/91       14.91         -0-
8.    A.E. Nineties-11                     09/30/91       01/31/92       14.08         -0-
9.    A.E. Partners 1991                   12/31/91       04/02/92       13.91         -0-
10.   A.E. Nineties-12                     12/31/91       04/30/92       13.83         -0-
11.   A.E. Nineties-JV 92                  10/28/92       04/05/93       13.16         -0-
12.   A.E. Partners 1992                   12/14/92       07/02/93       12.66         -0-
13.   A.E. Nineties-Public #1              12/31/92       07/15/93       12.41         -0-
14.   A.E. Nineties-1993 Ltd.              10/08/93       02/10/94       12.08         -0-
15.   A.E. Partners 1993                   12/31/93       07/02/94       11.83         -0-
16.   A.E. Nineties-Public #2              12/31/93       06/15/94       11.58         -0-
17.   A.E. Nineties-14                     08/11/94       01/10/95       11.08         -0-
18.   A.E. Partners 1994                   12/31/94       07/02/95       10.83         -0-
19.   A.E. Nineties-Public #3              12/31/94       06/05/95       10.83         -0-
20.   A.E. Nineties-15                     09/12/95       02/07/96       10.00         -0-
21.   A.E. Partners 1995                   12/31/95       10/02/96        9.58         -0-
22.   A.E. Nineties-Public #4              12/31/95       07/08/96        9.83         -0-
23.   A.E. Nineties-16                     07/31/96       01/12/97        9.16         -0-
24.   A.E. Partners 1996                   12/31/96       07/02/97        8.83         -0-
25.   A.E. Nineties-Public #5              12/31/96       06/08/97        8.83         -0-
26.   A.E. Nineties-17                     08/29/97       12/12/97        8.25         -0-
27.   A.E. Nineties-Public #6              12/31/97       06/08/98        7.83         -0-
28.   A.E. Partners 1997                   12/31/97       07/02/98        7.66         -0-
29.   A.E. Nineties-18                     07/31/98       01/07/99        6.91         -0-
30.   A.E. Nineties-Public #7              12/31/98       07/10/99        6.58         -0-
31.   A.E. Partners 1998                   12/31/98       07/02/99        6.58         -0-
32.   A.E. Nineties-19                     09/30/99       01/14/00        6.08         -0-
33.   A.E. Nineties-Public #8              12/31/99       06/09/00        5.58         -0-
34.   A.E. Partners 1999                   12/31/99       10/02/00        5.58         -0-
35.   1999 Viking Resources LP             12/31/99       06/01/00        5.58         -0-
36.   Atlas America-Series 20              09/30/00       01/30/01        5.33         -0-
37.   Atlas America - Public #9            12/31/00       07/13/01        4.93         -0-
38.   Atlas America - Series 21-A          05/15/01       11/16/01        4.68         -0-
39.   Atlas America - Series 21-B          09/19/01       03/02/02        4.08         -0-
40.   Atlas America - Public #10           12/31/01       06/20/02        3.83         -0-
41.   Atlas America - Series 22            05/31/02       11/12/02        3.33         -0-
42.   Atlas America - Series 23            09/30/02       02/18/03        3.08         -0-
43.   Atlas America - Public #11-2002      12/31/02      7/15/2003        2.83         -0-
44.   Atlas America - Series 24-2003(A)    05/31/03       12/05/03        2.33         -0-
45.   Atlas America - Series 24-2003(B)    08/29/03       02/05/04        2.08         -0-
46.   Atlas America - Public #12-2003      12/31/03        6/15/04        1.83         -0-
47.   Atlas America Series 25-2004(A)      05/31/04        11/5/04        1.58         -0-
48.   Atlas America Series 25-2004(B)      08/31/04         2/5/05        1.17         -0-
49.   Atlas America Public #14-2004        11/15/04        7/15/05         0.7         -0-
50.   Atlas America Public #14-2005(A)     06/17/05        2/15/06        0.50         -0-
51.   Atlas America Series 26-2005         09/16/05         6/5/06        0.33         -0-
52.   Atlas America Public #15-2005(A)     12/31/05        8/15/06        0.17         -0-
53.   Atlas America Public #15-2006(B)     08/31/06            (1)          (1)        -0-
----------
(1)  This program closed August 31, 2006, and its first distribution is expected
     early spring 2007.

                                       46
Table 2 reflects the drilling activity of previous development drilling
partnerships sponsored by the managing general partner and its affiliates. All
the wells were development wells. You should not assume that the past
performance of prior partnerships is indicative of the future results of the
partnerships.

                                     TABLE 2
                       WELL STATISTICS - DEVELOPMENT WELLS
                            AS OF SEPTEMBER 15, 2006
GROSS WELLS (1)          NET WELLS (2)
                                           --------------------   -----------------------
              Partnership                  Oil    Gas   Dry (3)   Oil     Gas     Dry (3)
---------------------------------------    ---   ----   -------   ---   -------   -------
1.  Atlas L.P. #1 - 1985                    0       6       1      0       2.83     0.50
2.  A.E. Partners 1986                      0       8       0      0       3.50     0.00
3.  A.E. Partners 1987                      0       9       0      0       4.10     0.00
4.  A.E. Partners 1988                      0       9       0      0       3.80     0.00
5.  A.E. Partners 1989                      0      10       0      0       3.30     0.00
6.  A.E. Partners 1990                      0      12       0      0       5.00     0.00
7.  A.E. Nineties-10                        0      12       0      0      11.50     0.00
8.  A.E. Nineties-11                        0      14       0      0       4.30     0.00
9.  A.E. Partners 1991                      0      12       0      0       4.95     0.00
10. A.E. Nineties-12                        0      14       0      0      12.50     0.00
11. A.E. Nineties-JV 92                     0      52       0      0      24.44     0.00
12. A.E. Partners 1992                      0       7       0      0       3.50     0.00
13. A.E. Nineties-Public #1                 0      14       0      0      14.00     0.00
14. A.E. Nineties-1993 Ltd.                 0      20       1      0      19.40     1.00
15. A.E. Partners 1993                      0       8       0      0       4.00     0.00
16. A.E. Nineties-Public #2                 0      16       0      0      15.31     0.00
17. A.E. Nineties-14                        0      53       2      0      53.00     2.00
18. A.E. Partners 1994                      0      12       0      0       5.00     0.00
19. A.E. Nineties-Public #3                 0      26       1      0      25.50     1.00
20. A.E. Nineties-15                        0      61       1      0      55.50     1.00
21. A.E. Partners 1995                      0       6       0      0       3.00     0.00
22. A.E. Nineties-Public #4                 0      32       0      0      30.50     0.00
23. A.E. Nineties-16                        0      51       6      0      40.50     4.50
24. A.E. Partners 1996                      0      13       0      0       4.84     0.00
25. A.E. Nineties-Public #5                 0      36       0      0      35.91     0.00
26. A.E. Nineties-17                        0      47       5      0      42.00     3.50
27. A.E. Nineties-Public #6                 0      55       0      0      44.45     0.00
28. A.E. Partners 1997                      0       6       0      0       2.81     0.00
29. A.E. Nineties-18                        0      63       0      0      58.00     0.00
30. A.E. Nineties-Public #7                 0      64       0      0      57.50     0.00
31. A.E. Partners 1998                      0      19       0      0       9.50     0.00
32. A.E. Nineties-19                        0      82       4      0      75.75     4.00
33. A.E. Nineties-Public #8                 0      58       0      0      54.66     0.00
34. A.E. Partners 1999                      0       5       0      0       2.50     0.00
35. 1999 Viking Resources LP                0      23       2      0      23.00     2.00
36. Atlas America - Series 20               0     106       1      0     100.25     1.00
37. Atlas America - Public #9               0      83       2      0      78.75     2.00
38. Atlas America - Series 21-A             0      68       0      0      62.50     0.00
39. Atlas America - Series 21-B             0      89       2      0      84.05     1.00
40. Atlas America - Public #10              0     107       3      0     103.15     3.00
41. Atlas America - Series 22               0      51       1      0      49.55     1.00
42. Atlas America - Series 23               0      47       1      0      47.00     1.00
43. Atlas America - Public #11-2002         0     167       0      0     160.50     0.00
44. Atlas America - Series 24-2003(A)       0      76       0      0      69.50     0.00
45. Atlas America - Series 24-2003(B)       0     121       1      0     113.00     1.00
46. Atlas America-Public #12-2003           0     226       1      0     214.25     1.00
47. Atlas America Series 25-2004(A)         0     137       4      0     130.80     4.00
48. Atlas America Series 25-2004(B)         0     171       4      0     153.40     4.00
49. Atlas America Public #14-2004           0     256      11      0     233.50    11.00
50. Atlas America Public #14-2005(A)        0     338       5      0     315.49     5.00
51. Atlas America Series 26-2005            0     142       2      0     132.31     2.00
52. Atlas America Public #15-2005(A)        0     187       1      0     181.50     1.00
53. Atlas America Public #15-2006(B) (4)    0     243       1      0     228.18     1.00
                                           ---   ----     ---     ---   -------    -----
                                            0    3550      63      0    3218.03    58.50
                                           ---   ----     ---     ---   -------    -----
----------
(1)  A "gross well" is one in which a leasehold interest is owned.

(2)  A "net well" equals the actual leasehold interest owned in one gross well
     divided by one hundred. For example, a 50% leasehold interest in a well is
     one gross well, but a .50 net well.

(3)  For purposes of this Table only, a "Dry Hole" means a well which is plugged
     and abandoned with or without a completion attempt because the operator has
     determined that it will not be productive of gas and/or oil in commercial
     quantities.

(4)  This partnership closed August 31, 2006, as of the date of this table this
     is the number of wells drilled. The total tentative gross well count is
     638.

                                       47
TABLE 3 PROVIDES INFORMATION CONCERNING THE OPERATING RESULTS OF PREVIOUS
DEVELOPMENT DRILLING PARTNERSHIPS SPONSORED BY THE MANAGING GENERAL PARTNER AND
ITS AFFILIATES. YOU SHOULD NOT ASSUME THAT THE PAST PERFORMANCE OF PRIOR
PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF THE PARTNERSHIPS.

                                     TABLE 3
                 INVESTOR OPERATING RESULTS - INCLUDING EXPENSES
                            AS OF SEPTEMBER 15, 2006
TOTAL COSTS
                                                            ---------------------------------          Cash
              Partnership                 Investor Capital  Operating (5)   Admin.    Direct   Distributions (1)(3)
----------------------------------------  ----------------  -------------  --------  --------  --------------------
1.  Atlas L.P. #1 - 1985                    $    600,000      $  246,260   $ 49,967  $ 17,678     $ 1,717,271
2.  A.E. Partners 1986                           631,250         197,025     82,316    16,196         852,501
3.  A.E. Partners 1987                           721,000         198,889     68,752    16,350         845,668
4.  A.E. Partners 1988                           617,050         168,710     66,684    14,778         771,388
5.  A.E. Partners 1989                           550,000         165,526     71,726    15,415         955,193
6.  A.E. Partners 1990                           887,500         249,952    104,450    23,602       1,426,035
7.  A.E. Nineties - 10                         2,200,000         533,309    121,585    59,407       2,190,506
8.  A.E. Nineties - 11                           750,000         201,069    105,922    73,996       1,193,605
9.  A.E. Partners 1991                           868,750         227,964    135,067    34,813       1,526,499
10. A.E. Nineties - 12                         2,212,500         520,878    109,334   143,133       2,331,334
11. A.E. Nineties - JV 92                      4,004,813         922,806    184,470   242,597       4,866,243 (2)
12. A.E. Partners 1992                           600,000         129,828     67,013    19,466       1,000,961
13. A.E. Nineties - Public #1                  2,988,960         581,781    116,566   146,119       2,618,662
14. A.E. Nineties - 1993 Ltd.                  3,753,937         635,915    123,548    71,437       2,361,866
15. A.E. Partners 1993                           700,000         171,899     49,763    19,086       1,178,306
16. A.E. Nineties - Public #2                  3,323,920         580,711    104,698   110,927       2,540,499
17. A.E. Nineties - 14                         9,940,045       1,807,042    336,152   113,405       6,750,557
18. A.E. Partners 1994                           892,500         185,487     62,924    26,609       1,320,908
19. A.E. Nineties - Public #3                  5,800,990         991,061    182,985   130,204       4,538,918
20. A.E. Nineties - 15                        10,954,715       1,884,667    344,261   127,317       8,897,138
21. A.E. Partners 1995                           600,000         106,556     25,383    14,620         427,548
22. A.E. Nineties - Public #4                  6,991,350       1,117,338    203,928   120,643       3,710,556
23. A.E. Nineties - 16                        10,955,465       1,641,546    266,642   141,148       6,765,625
24. A.E. Partners 1996                           800,000         153,259     33,713    54,833         640,836
25. A.E. Nineties - Public #5                  7,992,240       1,140,608    203,538   135,393       4,710,605
26. A.E. Nineties - 17                         8,813,488       1,287,100    207,159   207,902       6,447,218
27. A.E. Nineties - Public #6                  9,901,025       1,493,313    242,910   179,899       7,107,063
28. A.E. Partners 1997                           506,250          90,167     19,823    38,043         514,426
29. A.E. Nineties - 18                        11,391,673       1,669,791    262,007   314,187       7,327,951
30. A.E. Nineties - Public #7                 11,988,350       1,450,751    225,489   107,945       5,479,124
31. A.E. Partners 1998                         1,740,000         280,963     36,200    74,686       1,402,588
32. A.E. Nineties - 19                        15,720,450       1,952,845    295,250    85,481       8,310,083
33. A.E. Nineties - Public #8                 11,088,975       1,329,345    204,089   142,233       6,076,885
34. A.E. Partners 1999                           450,000          58,826      6,366    21,934         418,504
35. 1999 Viking Resources LP                   4,555,210       1,487,131          0   216,784       7,542,360
36. Atlas America - Series 20                 18,809,150       3,299,254    337,934   298,679      16,267,754
37. Atlas America - Public #9                 14,905,465       2,121,813    239,046   117,761       9,778,961
38. Atlas America - Series 21-A               12,510,713       1,451,012    176,823    18,289       7,701,889
39. Atlas America - Series 21-B               17,411,825       1,807,214    211,516    18,966       9,229,676
40. Atlas America - Public #10                21,281,170       2,230,967    263,178   111,093      12,728,308
41. Atlas America - Series 22                 10,156,375         975,362    113,029    16,623       6,504,235
42. Atlas America - Series 23                  9,644,550         886,545    104,040    16,799       5,154,434
43. Atlas America - Public #11-2002           31,178,145       2,599,868    294,130    97,250      15,645,315
44. Atlas America - Series 24-2003(A)         14,363,955         974,675    114,634    12,523       6,789,533
45. Atlas America - Series 24-2003(B)         20,542,850       1,571,054    158,769    11,157      11,080,773
Present Value of
                                                                               Estimated Future          Estimated Future Net
                                                        Latest Quarterly     Net Cash Flows from        Cash Flows from Proved
                                             Cash      Cash Distribution    Proved Reserves as of     Reserves Discounted at 10%
               Partnership                Return (3)  As of Date of Table  January 1, 2006 (7) (8)  as of January 1, 2006 (7) (9)
----------------------------------------  ----------  -------------------  -----------------------  -----------------------------
1.  Atlas L.P. #1 - 1985                     286%           $ 18,038                       (6)                         (6)
2.  A.E. Partners 1986                       135%              9,713                       (6)                         (6)
3.  A.E. Partners 1987                       117%             12,063                       (6)                         (6)
4.  A.E. Partners 1988                       125%              9,016                       (6)                         (6)
5.  A.E. Partners 1989                       174%              9,966                       (6)                         (6)
6.  A.E. Partners 1990                       161%             23,050                       (6)                         (6)
7.  A.E. Nineties - 10                       100%             32,620              2,786,335                   1,338,459
8.  A.E. Nineties - 11                       159%             12,942              1,216,578                     550,127
9.  A.E. Partners 1991                       176%             22,395                       (6)                         (6)
10. A.E. Nineties - 12                       105%             28,306              2,323,292                   1,087,659
11. A.E. Nineties - JV 92                    122%             46,776              2,271,517                   2,271,517
12. A.E. Partners 1992                       167%             11,171                       (6)                         (6)
13. A.E. Nineties - Public #1                 88%             38,046              3,159,562                   1,474,933
14. A.E. Nineties - 1993 Ltd.                 63%             12,500              1,344,478                     710,020
15. A.E. Partners 1993                       168%             15,053                       (6)                         (6)
16. A.E. Nineties - Public #2                 76%             19,335              1,947,940                     926,225
17. A.E. Nineties - 14                        68%             77,279              8,282,295                   4,122,517
18. A.E. Partners 1994                       148%             26,732                       (6)                         (6)
19. A.E. Nineties - Public #3                 78%             67,170              6,576,342                   2,957,611
20. A.E. Nineties - 15                        81%            153,709             14,614,389                   6,587,541
21. A.E. Partners 1995                        71%              6,360                       (6)                         (6)
22. A.E. Nineties - Public #4                 53%             86,881              6,936,030                   3,187,313
23. A.E. Nineties - 16                        62%            151,489             14,968,351                   6,464,413
24. A.E. Partners 1996                        80%             23,178                       (6)                         (6)
25. A.E. Nineties - Public #5                 59%             93,240              8,082,368                   3,784,776
26. A.E. Nineties - 17                        73%            178,045             15,285,565                   6,704,964
27. A.E. Nineties - Public #6                 72%            188,078             15,277,189                   6,955,093
28. A.E. Partners 1997                       102%             20,637                       (6)                         (6)
29. A.E. Nineties - 18                        64%            187,234             15,555,530                   7,214,431
30. A.E. Nineties - Public #7                 46%            145,083             10,902,072                   5,216,299
31. A.E. Partners 1998                        81%             43,408                       (6)                         (6)
32. A.E. Nineties - 19                        53%            228,618             18,262,903                   8,531,658
33. A.E. Nineties - Public #8                 55%            140,803             11,229,630                   5,491,322
34. A.E. Partners 1999                        93%             12,756                       (6)                         (6)
35. 1999 Viking Resources LP                 166%            161,075             10,938,303                   4,868,453
36. Atlas America - Series 20                 86%            449,685             32,188,897                  15,135,852
37. Atlas America - Public #9                 66%            311,229             23,408,497                  10,948,104
38. Atlas America - Series 21-A               62%            314,790             21,577,560                  10,082,423
39. Atlas America - Series 21-B               53%            383,276             27,352,982                  12,644,429
40. Atlas America - Public #10                60%            522,588             35,891,965                  16,628,127
41. Atlas America - Series 22                 64%            297,033             19,796,477                   9,053,570
42. Atlas America - Series 23                 53%            245,055             14,063,560                   6,906,104
43. Atlas America - Public #11-2002           50%            760,984             45,868,431                  22,353,045
44. Atlas America - Series 24-2003(A)         47%            519,571             26,989,322                  12,330,024
45. Atlas America - Series 24-2003(B)         54%            653,565             36,780,376                  17,910,462
48
TABLE 3 PROVIDES INFORMATION CONCERNING THE OPERATING RESULTS OF PREVIOUS
DEVELOPMENT DRILLING PARTNERSHIPS SPONSORED BY THE MANAGING GENERAL PARTNER AND
ITS AFFILIATES. YOU SHOULD NOT ASSUME THAT THE PAST PERFORMANCE OF PRIOR
PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF THE PARTNERSHIPS.

                                     TABLE 3
                 INVESTOR OPERATING RESULTS - INCLUDING EXPENSES
                            AS OF SEPTEMBER 15, 2006
TOTAL COSTS
                                                            ---------------------------------          Cash
               Partnership                Investor Capital  Operating (5)   Admin.    Direct   Distributions (1)(3)
----------------------------------------  ----------------  -------------  --------  --------  --------------------
46. Atlas America - Public #12-2003           40,170,308       2,309,645    257,283    81,371      15,786,993
47. Atlas America Series 25-2004(A)           27,601,053       1,373,402    114,762    60,140      11,893,622
48. Atlas America Series 25-2004(B)           31,531,035       1,207,893    114,202    63,778       8,130,183
49. Atlas America Public #14-2004             52,506,570       1,311,067    111,806    59,329       8,648,613
50. Atlas America Public #14-2005(A) (4)      69,674,900       1,132,841     86,116    39,734       7,117,275
51. Atlas America Series 26-2005 (4)          34,886,465         273,477     22,365    37,418       1,146,583
52. Atlas America Public #15-2005(A) (4)      52,245,720         223,282     14,612   27940.2         880,735
53. Atlas America Public #15-2006(B) (4)     147,513,130               0          0         0               0
Present Value of
                                                                               Estimated Future          Estimated Future Net
                                                        Latest Quarterly     Net Cash Flows from        Cash Flows from Proved
                                             Cash      Cash Distribution    Proved Reserves as of     Reserves Discounted at 10%
               Partnership                Return (3)  As of Date of Table  January 1, 2006 (7) (8)  as of January 1, 2006 (7) (9)
----------------------------------------  ----------  -------------------  -----------------------  -----------------------------
46. Atlas America - Public #12-2003           39%          1,255,983             44,426,619                  24,311,567
47. Atlas America Series 25-2004(A)           43%          1,552,570             47,244,326                  25,810,186
48. Atlas America Series 25-2004(B)           26%          1,309,287             42,121,836                  23,328,766
49. Atlas America Public #14-2004             16%          2,437,821             71,009,319                  39,354,877
50. Atlas America Public #14-2005(A) (4)      10%          3,332,777            114,641,497                  62,932,887
51. Atlas America Series 26-2005 (4)           3%            993,525             39,721,982                  21,181,210
52. Atlas America Public #15-2005(A) (4)       2%            880,735              3,240,412                   1,858,667
53. Atlas America Public #15-2006(B) (4)       0%                  0                       (6)                         (6)
----------
(1)  All cash distributions were from the sale of gas. The following
     partnerships also include revenue from the sale of properties: A.E.
     Nineties-16 ($4,776), A.E. Nineties-19 ($1,607), Atlas America Series 20
     ($6,662), Atlas America Series 24-2003(A) ($9,066), Atlas America Series
     24-2003(B) ($ 9,904), Atlas America Series 25-2004(A) ($595), Atlas America
     Series 25-2004(B) ($3,813), A.E. Nineties-Public #1 ($2,453), A.E.
     Nineties-Public #2 ($3,292), A.E. Nineties-Public #3 ($2,491), A.E.
     Nineties-Public #5 ($8,639), A.E. Nineties-Public #7 ($2,206), Atlas
     America Public #11-2002 ($2,789) and Atlas America Public #12-2003
     ($1,568).

(2)  A portion of the cash distributions was used to drill three reinvestment
     wells at a cost of $307,434 in accordance with the terms of the offering.

(3)  This column reflects total cash distributions beginning with the first
     production from the program as a percentage of the total amount invested in
     the program and includes the return of the investors' capital.

(4)  As of the date of this table there is not twelve months of production
     and/or not all of the wells are drilled or on-line to sell production.

(5)  Operating costs consist of gathering fees, water hauling fees, meter
     reading fees, repairs and maintenance, insurance and severance tax.

(6)  Current reserve information is either not available for these partnerships.
     The most current reserve report is dated 1/1/06. Also, reserve information
     for Public # 15-2005(A) which closed at 12/31/05 is incomplete since not
     all of its wells were drilled at 1/1/06.

(7)  The information presented in this column has been prepared in conformity
     with SEC guidelines by making the standardized estimates of future net cash
     flow from proved td.,rAtlausing natural gas and oil prices in effect as of
     the date of the estimates, which was a weighted average price of $10.08 per
     mcf for the natural gas, and which are held constant throughout the life of
     the properties. The information presented for future net cash flows based
     on estimated proved reserves has been prepared by the managing general
     partner's petroleum engineers and reviewed by an independent petroleum
     consultant, Wright & Company, Inc., as noted below with respect to the
     managing general partner's prior public partnerships and three Regulation D
     offerings which were registered under Section 12(g) of the Securities
     Exchange Act of 1934: Atlas-Energy for the Nineties-Public #1 Ltd.,
     Atlas-Energy for the Nineties-Public #2 Ltd., Atlas-Energy for the
     Nineties-Public #3 Ltd., Atlas-Energy for the Nineties-Public #4 L #12-2003
     Limited Partnership, Atlas America Series 25-2004(A) L.P., Atlas America
     Series 25-2004(B) L.P., Atlas America Public #14-2004 L.P., Atlas America
     Public #14-2005(A) L.P., Atlas America Series 26-2005 L.P., and Atlas
     America Public #15-2005(A) L.P. The other partnerships have not been
     reviewed by Wright & Company, Inc. You should understand that reserve
     estimates are imprecise and may change. There are inherent uncertainties in
     interpreting the engineering data and the projection of future rates of
     production. Also, prices received from the sale of natural gas and oil may
     be different from those estimates in preparing the reports, and the amounts
     and timing of future operating and development costs may also differ from
     those used. The cash flow information based on estimated proved reserves
     shown for a partnership does not include this information for the managing
     general partner.

(8)  This column represents a partnership's estimate of future net cash flows
     from its proved reserves using natural gas sales prices in effect as of the
     dates of the estimates which are held constant throughout the life of the
     partnership's properties. As natural gas prices change, these estimates
     will change. The information in this column has not been discounted.

(9)  This column represents a partnership's estimate of future net cash flows
     from its proved reserves using natural gas sales prices in effect as of the
     dates of the estimates which are held constant throughout the life of the
     partnership's properties. As natural gas prices change, these estimates
     will change. The present value of estimated future net cash flows is
     calculated by discounting estimated future net cash flows by 10% annually
     in accordance with SEC guidelines. You should not construe the estimated
     PV-10 values as representative of the fair market value of a partnership's
     properties.

                                       49
Table 3A provides information concerning the operating results of previous
development drilling partnerships sponsored by the managing general partner and
its affiliates.

                                    TABLE 3A
                            MANAGING GENERAL PARTNER
                     OPERATING RESULTS - INCLUDING EXPENSES
                            AS OF SEPTEMBER 15, 2006
Total Costs
                                          Managing General  ----------------------------------
              Partnership                  Partner Capital  Operating (3)   Admin.     Direct
----------------------------------------  ----------------  -------------  --------  ---------
1.  Atlas L.P. #1 - 1985                     $   114,800      $   46,907   $  9,517  $   3,367
2.  A.E. Partners 1986                           120,400          37,528     15,679      3,085
3.  A.E. Partners 1987                           158,269          57,345     19,823      4,714
4.  A.E. Partners 1988                           135,450          54,333     21,476      4,759
5.  A.E. Partners 1989                           120,731          36,335     15,745      3,384
6.  A.E. Partners 1990                           244,622          83,317          0          0
7.  A.E. Nineties - 10                           484,380         177,770          0          0
8.  A.E. Nineties - 11                           268,003          86,173     45,395     26,655
9.  A.E. Partners 1991                           318,063          75,988          0          0
10. A.E. Nineties - 12                           791,833         223,233     46,857     35,836
11. A.E. Nineties - JV 92                      1,414,917         454,516     90,859     37,948
12. A.E. Partners 1992                           176,100          43,276          0          0
13. A.E. Nineties - Public #1                    528,934         183,720     36,810     34,336
14. A.E. Nineties - 1993 Ltd.                  1,264,183         272,535     52,949     27,034
15. A.E. Partners 1993                           219,600          57,300          0          0
16. A.E. Nineties - Public #2                    587,340         183,382     33,062     35,030
17. A.E. Nineties - 14                         3,584,027         890,036    165,567     48,677
18. A.E. Partners 1994                           231,500          61,829          0          0
19. A.E. Nineties - Public #3                    928,546         330,354     60,995     43,401
20. A.E. Nineties - 15                         3,435,936         807,715    147,540     54,565
21. A.E. Partners 1995                           244,725          35,519          0          0
22. A.E. Nineties - Public #4                  1,287,752         372,446     67,976     40,214
23. A.E. Nineties - 16                         1,643,320         449,595     73,029     33,853
24. A.E. Partners 1996                           367,416          51,086          0          0
25. A.E. Nineties - Public #5                  1,654,740         380,203     67,846     45,131
26. A.E. Nineties - 17                         2,113,947         464,057     74,690     45,613
27. A.E. Nineties - Public #6                  1,950,345         497,771     80,970     59,966
28. A.E. Partners 1997                           231,050          30,056          0          0
29. A.E. Nineties - 18                         3,448,751         767,860    120,485     31,609
30. A.E. Nineties - Public #7                  3,812,150         651,787    101,307     48,497
31. A.E. Partners 1998                           756,360          93,654          0          0
32. A.E. Nineties - 19                         4,776,598         898,024    135,772     39,309
33. A.E. Nineties - Public #8                  3,148,181         542,972     83,360     58,095
34. A.E. Partners 1999                           196,500          19,609          0          0
35. 1999 Viking Resources LP                   1,678,038         495,710          0     72,261
36. Atlas America - Series 20                  6,297,945       1,220,272    124,989    110,470
37. Atlas America - Public #9                  6,256,271         891,005    100,759     48,100
38. Atlas America - Series 21-A                4,535,799         741,962     90,417      9,352
39. Atlas America - Series 21-B                6,442,761         930,989    108,963      9,770
40. Atlas America - Public #10                 7,227,432       1,049,871    123,849     52,279
41. Atlas America - Series 22                  3,481,591         470,263     53,190      8,014
42. Atlas America - Series 23                  3,214,850         417,206     48,960      7,906
43. Atlas America - Public #11-2002           13,295,226       1,339,326    154,621     50,098
44. Atlas America - Series 24-2003(A)          4,949,143         472,074     55,522      6,066
45. Atlas America - Series 24-2003(B)          7,300,020         781,527     78,981      5,550
Latest Quarterly Cash
                                                 Cash                       Distribution As of
              Partnership                 Distributions (1)  Cash Return      Date of Table
----------------------------------------  -----------------  -----------  ---------------------
1.  Atlas L.P. #1 - 1985                      $  327,099         285%           $    3,436
2.  A.E. Partners 1986                           162,381         135%                1,850
3.  A.E. Partners 1987                           243,830         154%                3,478
4.  A.E. Partners 1988                           248,456         183%                2,904
5.  A.E. Partners 1989                           285,170         236%                2,188
6.  A.E. Partners 1990                           435,070         178%                8,654
7.  A.E. Nineties - 10                           784,136         162%               12,131
8.  A.E. Nineties - 11                           511,780         191%                5,547
9.  A.E. Partners 1991                           546,289         172%                8,579
10. A.E. Nineties - 12                           999,144         126%               12,131
11. A.E. Nineties - JV 92                      1,468,616         104%               23,039
12. A.E. Partners 1992                         1,000,961         568%                4,437
13. A.E. Nineties - Public #1                    784,716         148%               12,014
14. A.E. Nineties - 1993 Ltd.                    542,568          43%                5,357
15. A.E. Partners 1993                           410,171         187%                5,848
16. A.E. Nineties - Public #2                    636,225         108%                6,106
17. A.E. Nineties - 14                         2,159,572          60%               38,063
18. A.E. Partners 1994                           465,059         201%                9,569
19. A.E. Nineties - Public #3                  1,450,980         156%               22,390
20. A.E. Nineties - 15                         2,893,896          84%               65,875
21. A.E. Partners 1995                           154,941          63%                2,683
22. A.E. Nineties - Public #4                  1,119,663          87%               28,960
23. A.E. Nineties - 16                         1,454,645          89%               41,491
24. A.E. Partners 1996                           243,222          66%                8,390
25. A.E. Nineties - Public #5                  1,223,820          74%               31,080
26. A.E. Nineties - 17                         2,177,234         103%               64,193
27. A.E. Nineties - Public #6                  2,271,798         116%               62,693
28. A.E. Partners 1997                           182,535          79%                7,611
29. A.E. Nineties - 18                         3,163,902          92%               86,100
30. A.E. Nineties - Public #7                  1,543,414          40%               65,182
31. A.E. Partners 1998                           491,253          65%               15,333
32. A.E. Nineties - 19                         3,681,168          77%              105,131
33. A.E. Nineties - Public #8                  2,261,028          72%               57,511
34. A.E. Partners 1999                           148,888          76%                4,684
35. 1999 Viking Resources LP                   2,514,120         150%               53,692
36. Atlas America - Series 20                  6,022,060          96%              166,322
37. Atlas America - Public #9                  4,104,730          66%              171,297
38. Atlas America - Series 21-A                3,938,292          87%              160,965
39. Atlas America - Series 21-B                4,748,410          74%              197,445
40. Atlas America - Public #10                 5,989,220          83%              245,925
41. Atlas America - Series 22                  3,135,963          90%              143,212
42. Atlas America - Series 23                  2,425,667          75%              115,322
43. Atlas America - Public #11-2002            8,184,812          62%              406,979
44. Atlas America - Series 24-2003(A)          3,301,620          67%              252,885
45. Atlas America - Series 24-2003(B)          5,505,659          75%              325,118
50
Table 3A provides information concerning the operating results of previous
development drilling partnerships sponsored by the managing general partner and
its affiliates.

                                    TABLE 3A
                            MANAGING GENERAL PARTNER
                     OPERATING RESULTS - INCLUDING EXPENSES
                            AS OF SEPTEMBER 15, 2006
Total Costs
                                          Managing General  ----------------------------------
              Partnership                  Partner Capital  Operating (3)   Admin.     Direct
----------------------------------------  ----------------  -------------  --------  ---------
46. Atlas America - Public #12-2003           13,708,076       1,109,013    133,148     39,072
47. Atlas America Series 25-2004(A)           10,266,771         739,524     61,795     32,383
48. Atlas America Series 25-2004(B)           16,006,953         650,404     61,493     34,342
49. Atlas America Public #14-2004             25,971,721         705,959     60,203     31,947
50. Atlas America Public #14-2005(A) (2)      30,912,583         609,991     46,370     21,395
51. Atlas America Series 26-2005 (2)          15,903,570         169,832     13,889     23,237
52. Atlas America Public #15-2005(A) (2)      21,412,609         125,978      8,244   15044.72
52. Atlas America Public #15-2006(B) (2)               0               0          0          0
Latest Quarterly Cash
                                                 Cash                       Distribution As of
              Partnership                 Distributions (1)  Cash Return      Date of Table
----------------------------------------  -----------------  -----------  ---------------------
46. Atlas America - Public #12-2003            8,198,524          60%              676,936
47. Atlas America Series 25-2004(A)            6,403,391          62%              835,701
48. Atlas America Series 25-2004(B)            4,385,152          27%              712,739
49. Atlas America Public #14-2004              4,656,946          18%            1,312,673
50. Atlas America Public #14-2005(A) (2)       3,832,379          12%            1,794,572
51. Atlas America Series 26-2005 (2)             712,038           4%              616,987
52. Atlas America Public #15-2005(A) (2)         496,920           2%              496,920
52. Atlas America Public #15-2006(B) (2)               0           0%                    0
----------
(1)  All cash distributions were from the sale of gas. The following
     partnerships also include revenue from the sale of properties: A.E. for the
     Nineties-1993 LTD ($6,337), A.E. Nineties-14 ($7,964), A.E. Nineties-15
     ($4,776), A.E. Nineties-19 ($2,473), Atlas America Series 20 ($8,562),
     Atlas America Series 24-2003(B) ($17,598), Atlas America Series 24-2003(B)
     ($19,226), Atlas America Series 25-2004(A) ($1,445), Atlas America Series
     25-2004(B) ($1,761), A.E. Nineties-Public #1 ($25), A.E. Nineties-Public #2
     ($33), A.E. Nineties-Public #3 ($25), A.E. Nineties-Public #5 ($1,406),
     A.E. Nineties-Public #7 ($2,296), Atlas America Public #9 ($4,446), Atlas
     America Public #11-2002 ($5,696) and Atlas America Public #12-2003
     ($3,582).

(2)  As of the date of this table there is not twelve months of production
     and/or not all wells are drilled or on-line to sell production.

(3)  Operating costs consist of gathering fees, water hauling fees, meter
     reading fees, repairs and maintenance, insurance and severance tax.

                                       51
Table 4 sets forth the managing general partner's estimate of the federal tax
savings to investors in the managing general partner's prior development
drilling partnerships, based on the maximum marginal tax rate in each year, the
share of tax deductions as a percentage of their subscriptions, and the
aggregate cash distributions. YOU ARE URGED TO CONSULT WITH YOUR OWN TAX
ADVISORS CONCERNING YOUR SPECIFIC TAX SITUATION AND SHOULD NOT ASSUME THAT THE
PAST PERFORMANCE OF PRIOR PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF
THE PARTNERSHIPS.

                                     TABLE 4
         SUMMARY OF INVESTOR TAX BENEFITS AND CASH DISTRIBUTION RETURNS
                            AS OF SEPTEMBER 15, 2006
Estimated Federal Tax Savings From (1):
                                                                          --------------------------------------------------------
                                                         1st Year    Eff    1st Year                                    Section 29
                                             Investor      Tax       Tax     I.D.C.      Depletion                         Tax
              Partnership                    Capital    Deduct.(2)  Rate  Deduct. (3)  Allowance (3)  Depreciation (3)  Credit (4)
----------------------------------------   -----------  ----------  ----  -----------  -------------  ----------------  ----------
1.   Atlas L.P. #1 - 1985                     $600,000      99%     50.0%   $298,337      $134,206           N/A           $55,915
2.   A.E. Partners 1986                        631,250      99%     50.0%    312,889        77,378           N/A           13,507
3.   A.E. Partners 1987                        721,000      99%     38.5%    356,895        59,520           N/A             N/A
4.   A.E. Partners 1988                        617,050      99%     33.0%    244,351        53,846           N/A             N/A
5.   A.E. Partners 1989                        550,000      99%     33.0%    179,685        73,294           N/A             N/A
6.   A.E. Partners 1990                        887,500      99%     33.0%    275,125       106,390           N/A           281,660
7.   A.E. Nineties - 10                      2,200,000     100%     33.0%    726,000       172,936           N/A           521,602
8.   A.E. Nineties - 11                        750,000     100%     31.0%    232,500       105,638           N/A           329,800
9.   A.E. Partners 1991                        868,750     100%     31.0%    269,313       119,815           N/A           315,893
10.  A.E. Nineties - 12                      2,212,500     100%     31.0%    685,875       214,464           N/A           617,285
11.  A.E. Nineties - JV 92                   4,004,813    92.5%     31.0%  1,322,905       379,240           N/A         1,002,109
12.  A.E. Partners 1992                        600,000     100%     31.0%    186,000        84,409           N/A           224,631
13.  A.E. Nineties - Public  #1              2,988,960    80.5%     36.0%    877,511       238,350         254,729           N/A
14.  A.E. Nineties - 1993 Ltd.               3,753,937    92.5%     39.6%  1,378,377       217,988           N/A             N/A
15.  A.E. Partners 1993                        700,000     100%     39.6%    273,216        92,558           N/A             N/A
16.  A.E. Nineties - Public  #2              3,323,920    78.7%     39.6%  1,036,343       214,344         279,039           N/A
17.  A.E. Nineties - 14                      9,940,045      95%     39.6%  3,739,445       566,141           N/A             N/A
18.  A.E. Partners 1994                        892,500     100%     39.6%    353,430        93,923           N/A             N/A
19.  A.E. Nineties - Public  #3              5,800,990    76.2%     39.6%  1,752,761       374,267         521,115           N/A
20.  A.E. Nineties - 15                     10,954,715    90.0%     39.6%  3,904,261       690,471           N/A             N/A
21.  A.E. Partners 1995                        600,000     100%     39.6%    237,600        30,162           N/A             N/A
22.  A.E. Nineties - Public  #4              6,991,350    80.0%     39.6%  2,214,860       329,901         537,551           N/A
23.  A.E. Nineties - 16                     10,955,465    86.8%     39.6%  3,361,289       498,319         872,185           N/A
24.  A.E. Partners 1996                        800,000     100%     39.6%    316,800        49,573           N/A             N/A
25.  A.E. Nineties - Public  #5              7,992,240    84.9%     39.6%  2,530,954       352,048         602,746           N/A
26.  A.E. Nineties - 17                      8,813,488    85.2%     39.6%  2,966,366       474,038         453,739           N/A
27.  A.E. Nineties - Public  #6              9,901,025    80.0%     39.6%  3,166,406       523,630         728,024           N/A
28.  A.E. Partners 1997                        506,250     100%     39.6%    200,475        35,302           N/A             N/A
29.  A.E. Nineties - 18                     11,391,673    90.0%     39.6%  4,030,884       397,479         433,716           N/A
30.  A.E. Nineties - Public  #7             11,988,350    85.0%     39.6%  4,043,670       366,218         623,927           N/A
31.  A.E. Partners 1998                      1,740,000   100.0%     39.6%    689,040       100,924           N/A             N/A
32.  A.E. Nineties - 19                     15,720,450    90.0%     39.6%  5,602,767       557,977         523,962           N/A
33.  A.E. Nineties - Public  #8             11,088,975    85.0%     39.6%  3,734,654       414,476         540,985           N/A
34.  A.E. Partners 1999                        450,000   100.0%     39.6%    178,200        26,609           N/A             N/A
35.  1999 Viking Resources LP                4,555,210    92.0%     39.6%  1,678,038       500,421           N/A             N/A
36.  Atlas America - Series 20              18,809,150    90.0%     39.6%  6,712,802       973,619         544,217           N/A
37.  Atlas America - Public  #9             14,905,465    90.0%     39.6%  5,349,744       633,024           N/A             N/A
38.  Atlas America - Series 21-A            12,510,713    91.0%     39.1%  4,468,617       439,859         275,025           N/A
39.  Atlas America - Series 21-B            17,411,825    91.0%     39.1%  6,197,907       523,241         351,033           N/A
40.  Atlas America - Public #10             21,281,170    91.0%     39.1%  7,550,729       685,415         563,453           N/A
41.  Atlas America - Series 22              10,156,375    91.0%     38.6%  3,564,312       318,593         261,761           N/A
42.  Atlas America - Series 23               9,644,550    91.0%     38.6%  3,404,803       252,265         230,415           N/A
43.  Atlas America - Public #11-2002        31,178,145    91.0%     38.6%  1,003,503       776,817         671,955           N/A
44.  Atlas America - Series 24-2003(A)      14,363,955    91.0%     35.0%  4,578,250       265,230         301,871           N/A
45.  Atlas America - Series 24-2003(B)      20,542,850    91.0%     35.0%  6,514,764       484,032         494,559           N/A
46.  Atlas America - Public #12-2003        40,170,308    91.0%     35.0%  2,879,332       632,604         890,093           N/A
Total      Cumulative Percent
                                                        Cash Distribution     Cash Dist.    of Cash Dist. And
                                                              As of            And Tax         Tax Savings
              Partnership                     Total    Date of Table(5)(6)  Savings(5)(6)  to Date (5)(6)(7)
----------------------------------------   ----------  -------------------  -------------  ------------------
1.   Atlas L.P. #1 - 1985                    $488,458       $1,717,271         $2,205,729         368%
2.   A.E. Partners 1986                       403,774          852,501          1,256,275         199%
3.   A.E. Partners 1987                       416,415          845,668          1,262,084         175%
4.   A.E. Partners 1988                       298,197          771,388          1,069,585         173%
5.   A.E. Partners 1989                       252,979          955,193          1,208,172         220%
6.   A.E. Partners 1990                       663,175        1,426,035          2,089,210         235%
7.   A.E. Nineties - 10                     1,420,538        2,190,506          3,611,044         153%
8.   A.E. Nineties - 11                       667,938        1,193,605          1,861,543         236%
9.   A.E. Partners 1991                       705,022        1,526,499          2,231,521         257%
10.  A.E. Nineties - 12                     1,517,624        2,331,334          3,848,958         164%
11.  A.E. Nineties - JV 92                  2,704,253        4,866,243          7,570,496         189%
12.  A.E. Partners 1992                       495,040        1,000,961          1,496,001         249%
13.  A.E. Nineties - Public  #1             1,370,590        2,618,662          3,989,252         125%
14.  A.E. Nineties - 1993 Ltd.              1,596,365        2,361,866          3,958,231         105%
15.  A.E. Partners 1993                       365,774        1,178,306          1,544,080         221%
16.  A.E. Nineties - Public  #2             1,529,726        2,540,499          4,070,225         122%
17.  A.E. Nineties - 14                     4,305,586        6,750,557         11,056,143         111%
18.  A.E. Partners 1994                       447,353        1,320,908          1,768,261         198%
19.  A.E. Nineties - Public  #3             2,648,143        4,538,918          7,187,061         124%
20.  A.E. Nineties - 15                     4,594,732        8,897,138         13,491,870         123%
21.  A.E. Partners 1995                       267,762          427,548            695,310         116%
22.  A.E. Nineties - Public  #4             3,082,312        3,710,556          6,792,868          97%
23.  A.E. Nineties - 16                     4,731,793        6,765,625         11,497,417         105%
24.  A.E. Partners 1996                       366,373          640,836          1,007,209         126%
25.  A.E. Nineties - Public  #5             3,485,748        4,710,605          8,196,353         103%
26.  A.E. Nineties - 17                     3,894,143        6,447,218         10,341,361         117%
27.  A.E. Nineties - Public  #6             4,418,059        7,107,063         11,525,123         116%
28.  A.E. Partners 1997                       235,777          514,426            750,204         148%
29.  A.E. Nineties - 18                     4,862,079        7,327,951         12,190,030         107%
30.  A.E. Nineties - Public  #7             5,033,816        5,479,124         10,512,940          87%
31.  A.E. Partners 1998                       789,964        1,402,588          2,192,552         126%
32.  A.E. Nineties - 19                     6,684,706        8,310,083         14,994,789          95%
33.  A.E. Nineties - Public  #8             4,690,115        6,076,885         10,767,000          97%
34.  A.E. Partners 1999                       204,809          418,504            623,313         139%
35.  1999 Viking Resources LP               2,178,459        7,542,360          9,720,819         213%
36.  Atlas America - Series 20              8,230,638       16,267,754         24,498,392         130%
37.  Atlas America - Public  #9             5,982,768        9,778,961         15,761,729          99%
38.  Atlas America - Series 21-A            5,183,501        7,701,889         12,885,391         103%
39.  Atlas America - Series 21-B            7,072,182        9,229,676         16,301,858          93%
40.  Atlas America - Public #10             8,799,597       12,728,308         21,527,905         101%
41.  Atlas America - Series 22              4,144,666        6,504,235         10,648,901         105%
42.  Atlas America - Series 23              3,887,483        5,154,434          9,041,917          93%
43.  Atlas America - Public #11-2002       12,452,275       15,645,315         28,097,590          90%
44.  Atlas America - Series 24-2003(A)      5,145,351        6,789,533         11,934,884          83%
45.  Atlas America - Series 24-2003(B)      7,493,356       11,080,773         18,574,129          90%
46.  Atlas America - Public #12-2003       14,402,029       15,786,993         30,189,022          75%
52
Table 4 sets forth the managing general partner's estimate of the federal tax
savings to investors in the managing general partner's prior development
drilling partnerships, based on the maximum marginal tax rate in each year, the
share of tax deductions as a percentage of their subscriptions, and the
aggregate cash distributions. YOU ARE URGED TO CONSULT WITH YOUR OWN TAX
ADVISORS CONCERNING YOUR SPECIFIC TAX SITUATION AND SHOULD NOT ASSUME THAT THE
PAST PERFORMANCE OF PRIOR PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF
THE PARTNERSHIPS.

                                     TABLE 4
         SUMMARY OF INVESTOR TAX BENEFITS AND CASH DISTRIBUTION RETURNS
                            AS OF SEPTEMBER 15, 2006
Estimated Federal Tax Savings From (1):
                                                                          --------------------------------------------------------
                                                         1st Year    Eff    1st Year                                    Section 29
                                             Investor      Tax       Tax     I.D.C.      Depletion                         Tax
              Partnership                    Capital    Deduct.(2)  Rate  Deduct. (3)  Allowance (3)  Depreciation (3)  Credit (4)
----------------------------------------   -----------  ----------  ----  -----------  -------------  ----------------  ----------
47.  Atlas America Series 25-2004(A)        27,601,053    91.0%     35.0%   8,694,332      452,773         891,447           N/A
48.  Atlas America Series 25-2004(B)        31,531,035    91.0%     35.0%   9,932,276      265,868       1,089,408           N/A
49.  Atlas America Public #14-2004          52,506,570    91.0%     35.0%  16,543,643      316,342         471,926           N/A
50.  Atlas America Public #14-2005(A) (8)   69,674,900    91.0%     35.0%  22,107,994      101,748         276,015           N/A
51.  Atlas America Series 26-2005 (8)       34,886,465    91.0%     35.0%  10,989,458            0          21,461           N/A
52.  Atlas America Public #15-2005(A) (8)   52,245,720    91.0%     35.0%  16,457,402            0               0           N/A
53.  Atlas America Public #15-2006(B) (8)  147,513,130    91.0%     35.0%           0            0               0           N/A
Total      Cumulative Percent
                                                        Cash Distribution     Cash Dist.    of Cash Dist. And
                                                              As of            And Tax         Tax Savings
              Partnership                     Total    Date of Table(5)(6)  Savings(5)(6)  to Date (5)(6)(7)
----------------------------------------   ----------  -------------------  -------------  ------------------
47.  Atlas America Series 25-2004(A)       10,038,552       11,893,622         21,932,175          79%
48.  Atlas America Series 25-2004(B)       11,287,552        8,130,183         19,417,735          61%
49.  Atlas America Public #14-2004         17,331,912        8,648,613         25,980,525          49%
50.  Atlas America Public #14-2005(A) (8)  22,485,757        7,117,275         29,603,032          42%
51.  Atlas America Series 26-2005 (8)      11,010,919        1,146,583         12,157,502          35%
52.  Atlas America Public #15-2005(A) (8)  16,457,402          880,735         17,338,137          33%
53.  Atlas America Public #15-2006(B) (8)           0                                0
----------
1.   These columns reflect the savings in taxes which would have been paid by an
     investor, assuming full use of deductions available to the investor.

2.   Atlas Resources anticipates that approximately 90% of an investor general
     partner's subscription to a partnership will be deductible in the year in
     which he invests.

3.   The I.D.C. Deductions, Depletion Allowance and MACRS depreciation
     deductions have been reduced to credit equivalents.

4.   The Section 29 tax credit is not available with respect to wells drilled
     after December 31, 1992. N/A means not applicable.

5.   These distributions were all from production revenues. The following
     partnerships also include revenue from the sale of properties: A.E.
     Nineties-16 ($4,776), A.E. Nineties-19 ($1,607), Atlas America Series 20
     ($6,662), Atlas America Series 24-2003(A) ($9,066), Atlas America Series
     24-2003(B) ($9,904), Atlas America Series 25-2004(A) ($595), Atlas America
     Series 25-2004(B) ($3,813), A.E. Nineties-Public #1 ($2,453), A.E.
     Nineties-Public #2 ($3,292), A.E. Nineties-Public #3 ($2,491), A.E.
     Nineties-Public #5 ($8,639), A.E. Nineties-Public #7 ($2,206), Atlas
     America Public #11 ($2,789) and Atlas America Public #12-2003 ($1,568).

6.   This column reflects total cash distributions beginning with the first
     production from the program and includes the return of investor's capital.

7.   These percentages are calculated by dividing the entry for each partnership
     in the "Total Cash Dist. And Tax Savings" column by that partnership 's
     entry in the "Investor Capital" column.

8.   As of the date of this table there is not twelve months of production
     and/or not all wells are drilled or on-line to sell production.

                                       53
Table 5 sets forth payments made to the managing general partners and its
affiliates from its previous partnerships.

                                     TABLE 5
       SUMMARY OF PAYMENTS TO THE MANAGING GENERAL PARTNER AND AFFILIATES
                           FROM PRIOR PARTNERSHIPS (1)
                            AS OF SEPTEMBER 15, 2006
Cumulative
                                                                      Leasehold                    Reimbursement
                                                       Cumulative   Drilling and     Cumulative   of General and
                                          Investor      Gathering    Completion      Operator's   Administrative
              Partnership                  Capital      Fees (1)      Costs (2)        Charges       Overhead
-------------------------------------   ------------   ----------   ------------     ----------   --------------
1. Atlas L.P. #1 - 1985                $    600,000            0   $    600,000     $  293,167      $ 59,484
 2. A.E. Partners 1986                       631,250            0        631,250        234,553        97,996
 3. A.E. Partners 1987                       721,000            0        721,000        256,235        88,576
 4. A.E. Partners 1988                       617,050            0        617,050        223,043        88,160
 5. A.E. Partners 1989                       550,000            0        550,000        201,861        87,470
 6. A.E. Partners 1990                       887,500            0        887,500        333,269       104,450
 7. A.E. Nineties-10                       2,200,000            0      2,200,000        711,079       121,585
 8. A.E. Nineties-11                         750,000            0        761,802(3)     287,242       151,317
 9. A.E. Partners 1991                       868,750            0        867,500        303,952       135,067
10. A.E. Nineties-12                       2,212,500            0      2,272,017(3)     744,111       156,191
11. A.E. Nineties-JV 92                    4,004,813            0      4,157,700      1,377,322       275,329
12. A.E. Partners 1992                       600,000            0        600,000        173,104        67,013
13. A.E. Nineties-Public #1                2,988,960            0      3,026,348(3)     765,502       153,376
14. A.E. Nineties-1993 Ltd.                3,753,937            0      3,480,656(3)     908,451       176,498
15. A.E. Partners 1993                       700,000            0        689,940        229,199        49,763
16. A.E. Nineties-Public #2                3,323,920            0      3,324,668(3)     764,093       137,760
17. A.E. Nineties-14                       9,940,045            0      9,512,015(3)   2,697,078       501,719
18. A.E. Partners 1994                       892,500            0        892,500        247,316        62,924
19. A.E. Nineties-Public #3                5,800,990            0      5,800,990      1,321,414       243,980
20. A.E. Nineties-15                      10,954,715            0      9,859,244(3)   2,692,382       491,801
21. A.E. Partners 1995                       600,000            0        600,000        142,075        25,383
22. A.E. Nineties-Public #4                6,991,350            0      6,991,350      1,489,783       271,904
23. A.E. Nineties-16                      10,955,465            0     10,955,465      2,091,142       339,671
24. A.E. Partners 1996                       800,000            0        800,000        204,345        33,713
25. A.E. Nineties-Public #5                7,992,240            0      7,992,240      1,520,810       271,384
26. A.E. Nineties-17                       8,813,488            0      8,813,488      1,751,157       281,849
27. A.E. Nineties-Public #6                9,901,025            0      9,901,025      1,991,084       323,880
28. A.E. Partners 1997                       506,250            0        506,250        120,223        19,823
29. A.E. Nineties-18                      11,391,673            0     11,391,673      2,437,652       382,492
30. A.E. Nineties-Public #7               11,988,350            0     11,988,350      2,102,538       326,796
31. A.E. Partners 1998                     1,740,000            0      1,740,000        374,617        36,200
32. A.E. Nineties-19                      15,720,450            0     15,720,450      2,850,869       431,022
33. A.E. Nineties-Public #8               11,088,975            0     11,088,975      1,872,317       287,450
34. A.E. Partners 1999                       450,000            0        450,000         78,434         6,366
35. 1999 Viking Resources LP               4,555,210            0      4,555,210      1,982,841             0
36. Atlas America-Series 20               18,809,150            0     18,809,150      4,519,526       462,923
37. Atlas America-Public #9               14,905,465    1,014,515     14,905,465      1,998,304       305,719
38. Atlas America-Series 21-A             12,510,713      709,002     12,510,713      1,483,972       267,240
39. Atlas America-Series 21-B             17,411,825      919,399     17,411,825      1,818,803       320,480
40. Atlas America-Public #10              21,281,170    1,283,921     21,281,170      1,996,917       387,027
41. Atlas America-Series 22               10,156,375      591,474     10,156,375        854,151       166,219
42. Atlas America-Series 23                9,644,550      553,080      9,644,550        750,670       153,000
43. Atlas America-Public #11-2002         31,178,145    1,411,829     31,178,145      2,527,364       448,751
44. Atlas America - Series 24-2003(A)     14,363,955      507,095     14,363,955        939,654       170,156
45. Atlas America - Series 24-2003(B)     20,542,850      869,235     20,542,850      1,483,346       237,750
46. Atlas America - Public 12-2003        40,170,308    1,366,333     40,170,308      2,052,125       390,431
47. Atlas America Series 25-2004(A)       27,601,053    1,073,685     27,601,053      1,039,242       176,558
48. Atlas America Series 25-2004(B)       31,531,035      694,459     31,531,035      1,163,838       175,695
49. Atlas America Public #14-2004         52,506,570      882,979     52,506,570      1,134,047       172,009
50. Atlas America Public #14-2005(A)      69,674,900    1,077,515     69,674,900        665,317       132,486
51. Atlas America Series 26-2005          34,886,465      201,123     34,886,465        242,186        36,253
52. Atlas America Public #15-2005(A)      52,245,720      173,725     52,245,720        175,536        22,856
53. Atlas America Public #15-2006(B)     147,513,130            0    147,513,130              0             0
----------
(1)  The amount of gathering fees paid to the managing general partner and its
     affiliates from 2001 to the date of this table are shown for those
     partnerships which began operations on or after December 31, 2000. The
     books and records of the earlier partnerships do not separately allocate
     all of the gathering fees paid by them. Additional information concerning
     the gathering fees paid by those partnerships will be provided to you on
     written request to the managing general partner.

(2)  Excluding the managing general partner's capital contributions.

(3)  Includes additional drilling costs paid with production revenues.

                                       54
MANAGEMENT

MANAGING GENERAL PARTNER AND OPERATOR

The partnerships will have no officers, directors or employees. Instead, Atlas
Resources, LLC, a Pennsylvania limited liability company, which was originally
formed as a corporation in 1979 and then changed to a limited liability company
on March 28, 2006, will serve as the managing general partner of each
partnership. However, see "- Transactions with Management and Affiliates,"
below, regarding the managing general partner's dependence on its indirect
parent company, Atlas America and its affiliates, for facilities, management and
administrative functions and financing for capital expenditures. The managing
general partner and its affiliates operate more than 5,100 natural gas and oil
wells located in the Appalachian Basin in the states of Ohio, Pennsylvania, New
York and Tennessee.

In addition, Atlas America (ATLS) has announced that it intends to transfer to
Atlas Energy Resources, LLC, a newly-formed, wholly-owned limited liability
company subsidiary of Atlas America, substantially all of its natural gas and
oil exploration and production assets. On July 28, 2006, Atlas Energy Resources,
LLC filed a registration statement with the SEC for an initial public offering
of 5,750,000 of its limited partner units. After the offering has concluded,
Atlas America will retain 83% of the limited partner units of Atlas Energy
Resources, LLC, which will continue to provide Atlas America control over Atlas
Energy Resources, LLC and its assets and business. This prospectus does not
constitute an offer to sell or a solicitation of an offer to buy any such
securities. Rather than transferring its energy assets directly to Atlas Energy
Resources, LLC, Atlas America intends to change its subsidiaries that currently
own those assets, including the managing general partner, into limited liability
company subsidiaries of Atlas Energy Resources, LLC, which would make Atlas
Energy Resources, LLC the indirect owner of the energy assets currently owned by
Atlas America's subsidiaries, including the managing general partner. Atlas
America anticipates that all of these transactions will be completed sometime
during 2007 on or following the closing of the public offering of limited
partner interests in Atlas Energy Resources, LLC discussed above. The
anticipated effect of Atlas America's intended transactions in connection with
Atlas Energy Resources, LLC can be seen by comparing the "- Current
Organizational Diagram" with the "- Pro Forma Organizational Diagram (Subject to
Change)" in "- Organizational Diagrams and Security Ownership of Beneficial
Owners," below.

Since 1985 the managing general partner has sponsored 16 public and 37 private
partnerships to conduct natural gas drilling and development activities in
Pennsylvania, Ohio, New York and Tennessee. In these partnerships the managing
general partner and its affiliates acted as the operator and the general
drilling contractor and were responsible for drilling, completing, and operating
the wells. Atlas Resources has a 97% completion rate for wells drilled by its
development partnerships.

In September 1998, Atlas Energy Group, Inc., the former parent company of the
managing general partner, merged into Atlas America, Inc., a Delaware holding
company, which was a subsidiary of Resource America, Inc., a publicly-traded
company, which is sometimes referred to in this private placement memorandum as
Resource America. In May 2004 Resource America conducted a public offering of a
portion of its common stock (the "shares") in Atlas America. Two million six
hundred forty-five thousand shares were registered and sold at a price of at
$15.50 per share resulting in gross proceeds of $41 million. Further, in May
2004, in connection with the Atlas America offering, the following officers and
key employees of the managing general partner and Atlas America set forth in "-
Officers, Directors and Other Key Personnel," below, resigned their positions
with Resource America and all of its subsidiaries that are not also subsidiaries
of Atlas America: Mr. Freddie M. Kotek, Mr. Frank P. Carolas, Mr. Jeffrey C.
Simmons, Ms. Nancy J. McGurk, Mr. Michael L. Staines, and Ms. Marci Bleichmar.

After the public offering, Resource America continued to own approximately 80.2%
of Atlas America's common stock until it distributed all of its remaining 10.7
million shares of common stock in Atlas America to its common stockholders on
June 30, 2005. The distribution was in the form of a spin-off by means of a tax
free dividend of approximately 0.6 shares of Atlas America to Resource America
common stockholders for each share of Resource America common stock owned. As a
result of the spin-off, Resource America is no longer in a position to determine
the outcome of corporate actions requiring the approval of Atlas America's
stockholders, such as:

     o    the election and removal of directors;

                                       55
o    mergers or other business combinations involving Atlas America;

     o    future issuances of Atlas America's common stock or other securities;
          and

     o    amendments to Atlas America's certificate of incorporation and bylaws.

These actions will be passed on by Atlas America's stockholders existing at the
record dates for such matters. Resource America's rights following the
distribution are defined by agreements between Resource America and Atlas
America.

Atlas America is headquartered at 311 Rouser Road, Moon Township, Pennsylvania
15108, near the Pittsburgh International Airport, which is also the managing
general partner's primary office.

OFFICERS, DIRECTORS AND OTHER KEY PERSONNEL OF MANAGING GENERAL PARTNER

The officers and directors of the managing general partner will serve until
their successors are elected. The officers, directors, and key personnel of the
managing general partner are as follows:
NAME                  AGE   POSITION OR OFFICE
----                  ---   ------------------
Freddie M. Kotek       50   Chairman of the Board of Directors, Chief Executive Officer and President
Frank P. Carolas       47   Executive Vice President - Land and Geology and a Director
Jeffrey C. Simmons     48   Executive Vice President - Operations and a Director
Jack L. Hollander      50   Senior Vice President - Direct Participation Programs
Nancy J. McGurk        50   Senior Vice President, Chief Financial Officer and Chief Accounting Officer
Michael L. Staines     57   Senior Vice President, Secretary and a Director
Michael G. Hartzell    51   Vice President - Land Administration
Donald R. Laughlin     58   Vice President - Drilling and Production
Marci F. Bleichmar     36   Vice President of Marketing
Sherwood S. Lutz       55   Senior Geologist/Manager of Geology
Michael W. Brecko      48   Director of Energy Sales
Karen A. Black         46   Vice President - Partnership Administration
Justin T. Atkinson     33   Director of Due Diligence
Winifred C. Loncar     65   Director of Investor Services
With respect to the biographical information set forth below:

     o    The approximate amount of an individual's professional time devoted to
          the business and affairs of the managing general partner, Atlas
          America, Atlas Energy Resources, LLC and Atlas Energy Management,
          Inc., as set forth below, on completion of Atlas Energy Resources,
          LLC's initial public offering have been aggregated because there is no
          reasonable method for them to distinguish their activities between the
          companies.

     o    For those individuals who also hold senior positions with other
          affiliates of the managing general partner, if it is stated that they
          devote approximately 100% of their professional time to the managing
          general partner and Atlas America, it is because there is no
          reasonable method to distinguish their activities between the managing
          general partner and Atlas America as compared with the other
          affiliates of the managing general partner.

FREDDIE M. KOTEK. President and Chief Executive Officer since January 2002 and
Chairman of the Board of Directors since September 2001. Mr. Kotek has been
Executive Vice President of Atlas America since February 2004, and served as a
director from September 2001 until February 2004 and served as Chief Financial
Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice
President of Resource America and President of Resource Leasing, Inc. (a
wholly-owned subsidiary of Resource America) from 1995 until May 2004 when he
resigned from Resource America and all of its

                                       56
subsidiaries which are not subsidiaries of Atlas America. Mr. Kotek was
President of Resource Properties from September 2000 to October 2001 and its
Executive Vice President from 1993 to August 1999. Mr. Kotek received a Bachelor
of Arts degree from Rutgers College in 1977 with high honors in Economics. He
also received a Master in Business Administration degree from the Harvard
Graduate School of Business Administration in 1981. Mr. Kotek will devote
approximately 95% of his professional time to the business and affairs of the
managing general partner and Atlas America, and the remainder of his
professional time to the business and affairs of the managing general partner's
affiliates.

FRANK P. CAROLAS. Executive Vice President - Land and Geology and a Director
since January 2001. Mr. Carolas has been an Executive Vice President of Atlas
America since January 2001 and served as a Director of Atlas America from
January 2002 until February 2004. Mr. Carolas has been a Senior Vice President
of Atlas Energy Management, Inc. since 2006. Mr. Carolas was a Vice President of
Resource America from April 2001 until May 2004 when he resigned from Resource
America. Mr. Carolas served as Vice President of Land and Geology for the
managing general partner from July 1999 until December 2000 and for Atlas
America from 1998 until December 2000. Before that Mr. Carolas served as Vice
President of Atlas Energy Group, Inc. from 1997 until 1998, which was the former
parent company of the managing general partner. Mr. Carolas is a certified
petroleum geologist and has been with the managing general partner and its
affiliates since 1981. He received a Bachelor of Science degree in Geology from
Pennsylvania State University in 1981 and is an active member of the American
Association of Petroleum Geologists. Mr. Carolas devotes approximately 100% of
his professional time to the business and affairs of the managing general
partner and Atlas America.

JEFFREY C. SIMMONS. Executive Vice President - Operations and a Director since
January, 2001. Mr. Simmons has been an Executive Vice President of Atlas America
since January 2001 and was a Director of Atlas America from January 2002 until
February 2004. Mr. Simmons has been a Senior Vice President of Atlas Energy
Management, Inc. since 2006. Mr. Simmons was a Vice President of Resource
America from April 2001 until May 2004 when he resigned from Resource America.
Mr. Simmons served as Vice President of Operations for the managing general
partner from July 1999 until December 2000 and for Atlas America from 1998 until
December 2000. Mr. Simmons joined Resource America in 1986 as a senior petroleum
engineer and has served in various executive positions with its energy
subsidiaries since then. Mr. Simmons received his Bachelor of Science degree
with honors in Petroleum Engineering from Marietta College in 1981 and his
Masters degree in Business Administration from Ashland University in 1992. Mr.
Simmons devotes approximately 90% of his professional time to the business and
affairs of the managing general partner and Atlas America, and the remainder of
his professional time to the business and affairs of the managing general
partner's affiliates, primarily Viking Resources and Resource Energy.

JACK L. HOLLANDER. Senior Vice President - Direct Participation Programs since
January 2002 and before that he served as Vice President - Direct Participation
Programs from January 2001 until December 2001. Mr. Hollander also serves as
Senior Vice President - Direct Participation Programs of Atlas America since
January 2002. Mr. Hollander practiced law with Rattet, Hollander & Pasternak,
concentrating in tax matters and real estate transactions, from 1990 to January
2001, and served as in-house counsel for Integrated Resources, Inc. (a
diversified financial services company) from 1982 to 1990. Mr. Hollander earned
a Bachelor of Science degree from the University of Rhode Island in 1978, his
law degree from Brooklyn Law School in 1981, and a Master of Law degree in
Taxation from New York University School of Law Graduate Division in 1982. Mr.
Hollander is a member of the New York State bar and the Chairman of the
Investment Program Association, which is an industry association, as of March
2005. Mr. Hollander devotes approximately 100% of his professional time to the
business and affairs of the managing general partner and Atlas America.

NANCY J. MCGURK. Senior Vice President since January 2002, Chief Financial
Officer and Chief Accounting Officer since January 2001. Ms. McGurk also serves
as Senior Vice President since January 2002 and Chief Accounting Officer of
Atlas America since January 2001. Ms. McGurk has been Chief Accounting Officer
of Atlas Energy Resources, LLC and Atlas Energy Management, Inc. since 2006. Ms.
McGurk served as Chief Financial Officer for Atlas America from January 2001
until February 2004. Ms. McGurk was a Vice President of Resource America from
1992 until May 2004 and its Treasurer and Chief Accounting Officer from 1989
until May 2004 when she resigned from Resource America. Also, since 1995 Ms.
McGurk has served as Vice President - Finance of Resource Energy, Inc. Ms.
McGurk received a Bachelor of Science degree in Accounting from Ohio State
University in 1978, and has been a Certified Public Accountant since 1982. Ms.

                                       57
McGurk will devote approximately 80% of her professional time to the business
and affairs of the managing general partner and Atlas America, and the remainder
of her professional time to the business and affairs of the managing general
partner's affiliates.

MICHAEL L. STAINES. Senior Vice President, Secretary, and a Director since 1998.
Mr. Staines has been an Executive Vice President and Secretary of Atlas America
since 1998. Mr. Staines was a Senior Vice President of Resource America from
1989 until May 2004 when he resigned from Resource America. Mr. Staines was a
director of Resource America from 1989 to February 2000 and Secretary from 1989
to October 1998. Mr. Staines has been President of Atlas Pipeline Partners GP
since January 2001 and its Chief Operating Officer and a member of its Managing
Board since its formation in November 1999. Mr. Staines is a member of the Ohio
Oil and Gas Association and the Independent Oil and Gas Association of New York.
Mr. Staines received a Bachelor of Science degree from Cornell University in
1971 and a Master of Business degree from Drexel University in 1977. Mr. Staines
will devote approximately 5% of his professional time to the business and
affairs of the managing general partner and Atlas America, and the remainder of
his professional time to the business and affairs of the managing general
partner's affiliates, including Atlas Pipeline Partners GP.

MICHAEL G. HARTZELL. Vice President - Land Administration since September 2001.
Mr. Hartzell has been Vice President - Land Administration of Atlas America
since January 2002, and before that served as Senior Land Coordinator from
January 1999 to January 2002. Mr. Hartzell has been Vice President - Land
Administration of Atlas Energy Management, Inc. since 2006. Mr. Hartzell has
been with the managing general partner and its affiliates since 1980 when he
began his career as a land department representative. Mr. Hartzell manages all
Land Department functions. Mr. Hartzell serves on the Environmental Committee of
the Independent Oil and Gas Association of Pennsylvania and is a past Chairman
of the Committee. Mr. Hartzell received his Bachelor of Science degree in
Business Management from the University of Phoenix in 2004. Mr. Hartzell devotes
approximately 100% of his professional time to the business and affairs of the
managing general partner and Atlas America.

DONALD R. LAUGHLIN. Vice President - Drilling and Production since September
2001. Mr. Laughlin also serves as Vice President - Drilling and Production for
Atlas America since January 2002, and before that served as Senior Drilling
Engineer since May 2001 when he joined Atlas America. Mr. Laughlin has been Vice
President - Drilling and Production of Atlas Energy Management, Inc. since 2006.
Mr. Laughlin has over thirty years of experience as a petroleum engineer in the
Appalachian Basin, having been employed by Columbia Gas Transmission Corporation
from October 1995 to May 2001 as a senior gas storage engineer and team leader,
Cabot Oil & Gas Corporation from 1989 to 1995 as Manager of Drilling Operations
and Technical Services, Doran & Associates, Inc. from 1977 until 1989 as Vice
President--Operations, and Columbia Gas from 1970 to 1977 as Drilling Engineer
and Gas Storage Engineer. Mr. Laughlin received his Petroleum Engineering degree
from the University of Pittsburgh in 1970. He is a member of the Society of
Petroleum Engineers. Mr. Laughlin devotes approximately 100% of his professional
time to the business and affairs of the managing general partner and Atlas
America.

MARCI F. BLEICHMAR. Vice President of Marketing since February 2001. Ms.
Bleichmar also serves as Vice President of Marketing for Atlas America since
February 2001 and was with Resource America from February 2001 until May 2004
when she resigned from Resource America. From March 2000 until February 2001,
Ms. Bleichmar served as Director of Marketing for Jacob Asset Management (a
mutual fund manager), and from March 1998 until March 2000, she was an account
executive at Bloomberg Financial Services LP. From November 1994 until 1998, Ms.
Bleichmar was an Associate on the Derivatives Trading Desk of JP Morgan. Ms.
Bleichmar received a Bachelor of Arts degree from the University of Wisconsin in
1992. Ms. Bleichmar devotes approximately 100% of her professional time to the
business and affairs of the managing general partner and Atlas America.

SHERWOOD S. LUTZ. Senior Geologist/Manager of Geology. In 1996 Mr. Lutz joined
Viking Resources, which was purchased by Resource America in 1999 as senior
geologist. Since 1999 Mr. Lutz has been a senior geologist for the managing
general partner and Atlas America. Mr. Lutz received his Bachelor of Science
degree in Geological Sciences from the Pennsylvania State University in 1973.
Mr. Lutz is a certified petroleum geologist with the American Association of
Petroleum Geologists as well as a licensed professional geologist in
Pennsylvania. Mr. Lutz devotes approximately 100% of his professional time to
the business and affairs of the managing general partner and Atlas America.

                                       58
MICHAEL W. BRECKO. Director of Energy Sales since November 2002. Mr. Brecko has
over 19 years of natural gas marketing experience in the oil and natural gas
industry. Mr. Brecko is a 1980 graduate from The Pennsylvania State University
with a Bachelor of Science degree in Civil Engineering. His career in natural
gas marketing began when he joined Equitable Gas Company, a local distribution
company, as a marketing representative in the commercial/ industrial marketing
division from May 1986 to August 1992. He subsequently joined O&R Energy, a
subsidiary of Orange and Rockland Utilities, as regional marketing manager from
August 1992 to November 1993. Beginning in December 1993 through July 2001, Mr.
Brecko worked for Cabot Oil & Gas Corporation, a mid-sized Appalachian oil and
natural gas producer, as an account executive and he was promoted in August 1998
to natural gas trader. In November 2001, he joined Sprague Energy Corporation, a
multi-energy sourced company, as a regional account manager before joining Atlas
America in 2002. Mr. Brecko devotes approximately 100% of his professional time
to the business and affairs of the managing general partner and Atlas America.

KAREN A. BLACK. Vice President - Partnership Administration since February 2003.
Ms. Black is also Vice President and Financial and Operations Principal of
Anthem Securities since October 2002. Ms. Black joined the managing general
partner and Atlas America in July 2000 and served as manager of production,
revenue and partnership accounting from July 2000 through October 2001, after
which she served as manager and financial analyst until her appointment as Vice
President - Partnership Administration. Before joining the managing general
partner in 2000, Ms. Black was associated with Texas Keystone, Inc. as
controller from April 1997 through June 2000. Ms. Black was employed as a tax
accountant for Sobol Bosco & Associates, Inc. from May 1996 through March 1997.
Ms. Black received a Bachelor of Arts degree from the University of Pittsburgh,
Johnstown in 1982. Ms. Black devotes approximately 50% of her professional time
to the business and affairs of the managing general partner and Atlas America,
and the remainder of her professional time to the business and affairs of Anthem
Securities.

JUSTIN T. ATKINSON. Director of Due Diligence since February 2003. Mr. Atkinson
also serves as President of Anthem Securities since February 2004 and as Chief
Compliance Officer since October 2002. Before that Mr. Atkinson served as
assistant compliance officer of Anthem Securities from December 2001 until
October 2002 and Vice President from October 2002 until February 2004. Before
his employment with the managing general partner, Mr. Atkinson was a manager of
investor and broker/dealer relations with Viking Resources Corporation from 1996
until November 2001. Mr. Atkinson earned a Bachelor of Arts degree in Business
Management in 1995 from Walsh University in North Canton, Ohio. Mr. Atkinson
devotes approximately 25% of his professional time to the business and affairs
of the managing general partner and Atlas America, and the remainder of his
professional time to the business and affairs of Anthem Securities.

WINIFRED C. LONCAR, Director of Investor Services since February 2003. Ms.
Loncar previously held the position of manager of investor services from the
inception of the investor service department in 1990 to February 2003. Before
that she was executive secretary to the managing general partner. Ms. Loncar
received a Bachelor of Science degree in Business from Point Park University in
1998. Ms. Loncar devotes approximately 100% of her professional time to the
business and affairs of the managing general partner and Atlas America.

ATLAS AMERICA, INC., A DELAWARE COMPANY

As of August 24, 2006, the officers and directors for Atlas America include the
following:

NAME                   AGE   POSITION
----                   ---   --------
Edward E. Cohen         67   Chairman, Chief Executive Officer and President
Frank P. Carolas        47   Executive Vice President
Freddie M. Kotek        50   Executive Vice President
Jeffrey C. Simmons      47   Executive Vice President
Michael L. Staines      57   Executive Vice President and Secretary
Matthew A. Jones        44   Chief Financial Officer
Nancy J. McGurk         50   Senior Vice President and Chief Accounting Officer
Jonathan Z. Cohen       36   Vice Chairman
Carlton M. Arrendell    44   Director

                                       59
NAME                   AGE   POSITION
----                   ---   --------
William R. Bagnell      43   Director
Donald W. Delson        55   Director
Nicholas DiNubile       54   Director
Dennis A. Holtz         66   Director
Harmon S. Spolan        70   Director

See "- Officers, Directors and Other Key Personnel," above, for biographical
information on certain of these individuals who are also officers of the
managing general partner. Biographical information on the other officers and
directors will be provided by the managing general partner on request.

The managing general partner and its affiliates under Atlas America employ more
than 205 persons.

ORGANIZATIONAL DIAGRAMS AND SECURITY OWNERSHIP OF BENEFICIAL OWNERS

Atlas America owns 100% of the common stock of AIC, LLC, which owns 100% of the
common stock of the managing general partner. The directors of AIC, LLC are
Jonathan Z. Cohen, Michael L. Staines, and Jeffrey C. Simmons. The biographies
of Messrs. Staines and Simmons are set forth above. Although Atlas Energy
Resources, LLC and Atlas Energy Management, Inc. have been formed as described
in "- Pro Forma Organizational Diagram (Subject to Change)," below, as of the
date of this private placement memorandum not all of the transfers have been
made that will result in the entities described under Atlas America other than
Atlas Pipeline Holdings, L.P. (AHD), and its subsidiaries, and Atlas Pipeline
Holdings GP, LLC becoming subsidiaries of Atlas Energy Resources, LLC on or
after completing its initial public offering as discussed in "- Managing General
Partner and Operator," above.

                         CURRENT ORGANIZATIONAL DIAGRAM
----------------------------------
                                                  Atlas America, Inc. (Delaware)
                                                (driller and operator in Ohio) (3)
                                                ----------------------------------
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        |                 |              |          |             |                 |            |          |               |
-----------------  --------------  -------------  ----  -------------------  --------------  --------  ------------  ------------
 Atlas Pipeline    Atlas Pipeline  Atlas Energy   AIC,  Atlas America, Inc.      Viking      Resource  Atlas Noble,       AED
 Holdings, L.P.     Holdings GP,     Management,  LLC      (Pennsylvania)    Resources, LLC   Energy,    LLC (2)     Investments,
       (2)            LLC, non-    Inc. (Manager  ----  (operating company)        (1)        LLC (1)                    Inc.
-----------------     economic       of Atlas       |   -------------------  --------------  --------  ------------  ------------
        |             general         Energy        |                                            |
        |             partner       Resources,      |--------------------------------------      |
        |           interest in         LLC         |                 |                   |       --------------------
        |          Atlas Pipeline  -------------    |                 |                   |              |           |
-----------------      Holdings,        -------------------  ------------------  ------------------  -------  -------------
 Atlas Pipeline        L.P.                Atlas Resources,     Atlas Energy,    Anthem Securities,  REI-NY,  Resource Well
   Partners GP,    --------------           LLC, managing       LLC, managing          Inc.,          LLC     Services, LLC
  LLC, general                           general partner of  general partner of     registered       -------  -------------
partner interest                           Atlas America          exploratory      broker/dealer
in Atlas Pipeline                          Series 27-2006        drilling           and dealer-
  Partners, L.P.                         L.P., driller and   partnerships and          manager
-----------------                            operator in         driller and
        |                                   Pennsylvania          operator
        |                               -------------------  ------------------  ------------------
        |
        |
-----------------
  Atlas Pipeline
  Partners, L.P.
-----------------
        |
        |
        |
        |
-----------------
 Atlas Pipeline
    Operating
  Partnership,
       L.P.
-----------------
60
(1)  Viking Resources, Resource Energy, and Atlas Noble, LLC are also engaged in
     the oil and gas business. Atlas America manages their assets and employees
     including sharing common employees. Also, many of the officers and
     directors of the managing general partner serve as officers and directors
     of those entities.

(2)  On January 12, 2006, Atlas Pipeline Holdings, L.P., a wholly-owned
     subsidiary of Atlas America, filed a registration statement with the SEC
     for an initial public offering of 3.6 million of its common units, which
     represented an approximate 17.1% limited partner interest in the company.
     On July 26, 2006, Atlas Pipeline Holdings, L.P. issued 3.6 million common
     units, representing a 17.1% ownership interest, in the initial public
     offering at a price of $23 per unit, and the underwriters were granted a
     30-day option to purchase up to an additional 540,000 common units.
     Substantially all of the net proceeds from this offering, approximately $77
     million, have been paid to Atlas America. Atlas America continues to own
     approximately 82.9% of Atlas Pipeline Holdings GP, LLC, which gives Atlas
     America indirect general partner control over Atlas Pipeline Partners
     (APL).

(3)  See "- Managing General Partner and Operator," above, and "- Pro Forma
     Organizational Diagram (Subject to Change)," below, regarding Atlas
     America's new subsidiary, Atlas Energy Resources, LLC, which recently filed
     a registration statement with the SEC for an initial public offering of
     5,750,000 common units representing an approximate 17% limited partner
     interest in the company. After the offering, Atlas America will retain
     approximately 83% of the limited partner units and all of the net proceeds
     of the offering will be paid to Atlas America. This private placement
     memorandum does not constitute an offer to sell or a solicitation of an
     offer to buy any securities in Atlas Energy Resources, LLC.

              PRO FORMA ORGANIZATIONAL DIAGRAM (SUBJECT TO CHANGE)

The following pro forma organizational diagram is subject to change, because it
reflects certain transactions that Atlas America anticipates will happen in the
near future, but which have not yet happened as of the date of this prospectus.
The anticipated transactions set forth in the following diagram include, for
example, Atlas America's changing many of its subsidiaries to limited liability
subsidiaries of Atlas Energy Resources, LLC. The changes in the following
organizational diagram from the "- Current Organizational Diagram" set forth
above, relate to Atlas America's intention to transfer to Atlas Energy
Resources, LLC, substantially all of its natural gas and oil exploration and
production assets. Atlas America anticipates that all of these transactions will
be completed before or on the closing of Atlas Energy Resources, LLC's public
offering as described in "- Managing General Partner and Operator," above. This
prospectus does not constitute an offer to sell or a solicitation of an offer to
buy those securities.

                                       61
------------------------
                               Atlas America, Inc.
                            (A Delaware corporation)
                            ------------------------
                                        |
        |-------------------------------------------------------------------------------------------------------------|
        |                    |                     |                        |                       |                 |
-------------------  --------------------  ------------------  ------------------------------  ------------  ------------------
  Atlas Pipeline        Atlas Pipeline        Atlas Energy     Atlas Energy Management, Inc.,       AED        Atlas America,
Holdings, L.P. (2)    Holdings GP, LLC,    Resources, LLC (1)      manager of Atlas Energy     Investments,         Inc.
-------------------  non-economic general    (Pennsylvania)          Resources, LLC (1)            Inc.      (Pennsylvania) (1)
        |            partner interest in   ------------------  ------------------------------  ------------  ------------------
        |               Atlas Pipeline
-------------------     Holdings, L.P.        |-------------------------------------------|
  Atlas Pipeline     --------------------     |            |             |                |
     Partners                              ---------  ------------  -----------   --------------
 GP, LLC, general                          AIC, LLC   Atlas Noble,   Resource         Viking
partner interest in                          (1)         LLC (1)    Energy, LLC   Resources, LLC
  Atlas Pipeline                           ---------  ------------      (1)             (1)
  Partners, L.P.                              |                      ------------  --------------
-------------------                           |    -----------------------  |
        |                                     |    Atlas Energy Ohio, LLC   |
        |                                     |---      (1) (Ohio)          |
-------------------                           |    ----------------------   |    ----------------
  Atlas Pipeline                              |                             |---  REI-NY, LLC (1)
  Partners, L.P.                              |    -----------------------  |    ----------------
-------------------                           |    Atlas Resources, LLC     |
        |                                     |---          (1)             |    -----------------
        |                                     |    -----------------------  |       Resource Well
-------------------                           |                             |--- Services, LLC (1)
  Atlas Pipeline                              |    -----------------------       -----------------
    Operating                                 |--- Anthem Securities, Inc.
 Partnership, L.P.                                 -----------------------
-------------------
(1)  All of these companies would be engaged in the oil and gas exploration and
     production business. Atlas America would continue to manage their assets
     and employees including sharing common employees. Also, many of the
     officers and directors of the managing general partner would serve as
     officers and directors of those entities.

(2)  See footnote (2) to "- Current Organizational Diagram," above.

ATLAS ENERGY RESOURCES, LLC, A DELAWARE LIMITED LIABILITY COMPANY

As of July 28, 2006, the directors, nominees and executive officers for Atlas
Energy Resources, LLC include the following:

NAME                AGE   POSITION OR OFFICE
----                ---   ------------------
Edward E. Cohen      67   Chairman of the Board and Chief Executive Officer
Jonathan Z. Cohen    36   Vice Chairman of the Board
Richard D. Weber     43   President, Chief Operating Officer and Director
Matthew A. Jones     44   Chief Financial Officer and Director
Nancy J. McGurk      50   Chief Accounting Officer
Walter C. Jones      43   Director Nominee
Ellen F. Warren      50   Director Nominee
Bruce M. Wolf        58   Director Nominee

See "- Officers, Directors and Other Key Personnel," above, for biographical
information on Ms. McGurk, who also is an officer of the managing general
partner. Also, on May 9, 2006 Mr. Richard Weber was appointed President, Chief
Operating Officer and a director of Atlas Energy Resources, LLC. In conjunction
with Mr. Weber's appointment, Atlas America and Mr. Weber entered into an
employment agreement dated April 5, 2006. Mr. Weber served from June 1997 until
March 2006 as Managing Director and Group Head of the Energy Group of KeyBanc
Capital Markets, a division of KeyCorp, and its predecessor, McDonald & Company
Securities, Inc. As part of his duties, he oversaw the bank's activities with
oil and gas producers, pipeline companies and utilities. He has a particular
expertise in the Appalachian Basin, where he led over 40 transactions, including
the IPOs of Atlas America and Atlas Pipeline and the sale of Viking Resources
Corporation to Atlas America.

Biographical information on the other officers and directors of Atlas Energy
Resources, LLC will be provided by the managing general partner on request.

                                       62
ATLAS ENERGY MANAGEMENT, INC., A DELAWARE COMPANY

As of July 28, 2006, the officers for Atlas Energy Management, LLC include the
following:

NAME                  AGE   POSITION OR OFFICE
----                  ---   ------------------
Edward E. Cohen        67   Chairman of the Board and Chief Executive Officer
Richard D. Weber       43   President, Chief Operating Officer and Director
Jeffrey C. Simmons     48   Senior Vice President
Frank P. Carolas       47   Senior Vice President
Matthew A. Jones       44   Chief Financial Officer
Nancy J. McGurk        50   Chief Accounting Officer
Donald R. Laughlin     58   Vice President - Drilling and Production
Michael G. Hartzell    51   Vice President - Land Administration
Lisa Washington        39   Chief Legal Officer and Secretary

See "- Officers, Directors and Other Key Personnel," above, for biographical
information on certain of these individuals who are also officers of the
managing general partner. Biographical information on the other officers and
directors will be provided by the managing general partner on request.

REMUNERATION OF OFFICERS AND DIRECTORS

No officer or director of the managing general partner will receive any direct
remuneration or other compensation from the partnerships. These persons will
receive compensation solely from affiliated companies of the managing general
partner.

CODE OF BUSINESS CONDUCT AND ETHICS

Because the partnerships do not directly employ any persons, the managing
general partner has determined that the partnerships will rely on a Code of
Business Conduct and Ethics adopted by Atlas America, Inc. that applies to the
principal executive officer, principal financial officer and principal
accounting officer of the managing general partner, as well as to persons
performing services for the managing general partner generally. You may obtain a
copy of this Code of Business Conduct and Ethics by a request to the managing
general partner at Atlas Resources, LLC, 311 Rouser Road, Moon Township,
Pennsylvania 15108.

TRANSACTIONS WITH MANAGEMENT AND AFFILIATES

The managing general partner depends on its indirect parent company, Atlas
America and its affiliates, for management and administrative functions and
financing for capital expenditures. The managing general partner currently pays
a management fee to Atlas America for management and administrative services,
which amounted to $45.7 million, $21.6 million, and $13.1 million for the years
ended September 30, 2005, 2004, and 2003, respectively. (See "Financial
Information Concerning the Managing General Partner and Atlas America Public
#16-2007(A) L.P.," including the indebtedness owed by the managing general
partner to Atlas America.)

The managing general partner and its officers, directors and affiliates have in
the past invested, and may in the future invest, in partnerships sponsored by
the managing general partner. They may also subscribe for units in the
partnerships as described in "Plan of Distribution."

                     MANAGEMENT'S DISCUSSION AND ANALYSIS OF
                  FINANCIAL CONDITION, RESULTS OF OPERATIONS,
                        LIQUIDITY AND CAPITAL RESOURCES

Both of the partnerships have been formed as limited partnerships under the
Delaware Revised Uniform Limited Partnership Act. The partnerships, however,
have not included any historical information in this prospectus since they have
no net worth, do not own any properties on which wells will be drilled, have no
third-party investors, and have not conducted any operations. (See
"Capitalization and Source of Funds and Use of Proceeds," "Proposed Activities,"
"Competition, Markets

                                       63
and Regulation," and "Financial Information Concerning the Managing General
Partner and Atlas America Public #16-2007(A) L.P.")

Each partnership will depend on the proceeds of this offering and the managing
general partner's capital contributions to carry out its proposed activities.
Each partnership intends to use its subscription proceeds to pay the following:

     o    the intangible drilling costs of the partnership's wells;

     o    the investors' share of equipment costs of the partnership's wells;
          and

     o    the investors' share of any cost overruns of drilling and completing
          the partnership's wells.

The managing general partner believes that each partnership's liquidity
requirements will be satisfied from the following:

     o    subscription proceeds of this offering;

     o    the managing general partner's capital contributions;

     o    cash flow from future operations; and

     o    partnership borrowings, if necessary.

The managing general partner also anticipates that no additional funds will be
required for operating costs before a partnership begins receiving production
revenues from its wells.

Substantially all of the subscription proceeds of you and the other investors in
a partnership will be committed or expended after the offering of the
partnership closes. If a partnership requires additional funds for cost overruns
or additional development or remedial work after a well begins producing, then
these funds may be provided by:

     o    subscription proceeds, if available;

     o    drilling fewer wells, or acquiring a lesser working interest in one or
          more wells;

     o    borrowings from the managing general partner or its affiliates; or

     o    retaining partnership revenues.

There will be no borrowings from third-parties. The amount that may be borrowed
by a partnership from the managing general partner and its affiliates may not at
any time exceed 5% of the partnership's subscription proceeds from you and the
other investors and must be without recourse to you and the other investors. The
partnership's repayment of any borrowings would be from partnership production
revenues and would reduce or delay your cash distributions.

If the managing general partner loans money to a partnership, which it is not
required to do, then:

     o    the interest charged to the partnership must not exceed the managing
          general partner's interest cost or the interest that would be charged
          to the partnership without reference to the managing general partner's
          financial abilities or guarantees by unrelated lenders, on comparable
          loans for the same purpose; and

     o    the managing general partner may not receive points or other financing
          charges or fees, although the actual amount of the charges incurred
          from third-party lenders may be reimbursed to the managing general
          partner.

                                       64
As of the date of this prospectus, Atlas America (the "borrower") has a $200
million revolving credit facility with a group of banks with Wachovia Bank, N.A.
as the administrative agent and issuing bank. The managing general partner and
various energy subsidiaries of Atlas America are guarantors of the credit
agreement. As of April 27, 2006, this facility had a borrowing base of $130
million. Borrowings under the facility are collateralized by substantially all
of the assets of Atlas America and the other guarantors, including the managing
general partner (collectively the "obligors"). These assets include the managing
general partner's interests in the partnerships, but do not include any
investor's interest in a partnership. A breach of the credit agreement by the
borrower is a default under the loan. The credit facility's term ends in April
2010. At May 9, 2006, the borrower had an outstanding balance of approximately
$54 million and also had a $6.5 million letter of credit issued under the
facility. Under the credit facility, the obligors are subject to substantial
restrictions and financial covenants and ratios. For example, the credit
facility restricts the ability of the obligors to obtain additional financing,
make investments, lease equipment, sell assets and engage in business
combinations. The failure to comply with any of the restrictions and covenants
under the credit facility could result in a default, which could cause all of
the existing indebtedness to be immediately due.

The managing general partner depends on its indirect parent company, Atlas
America and its affiliates, for management and administrative functions and
financing for capital expenditures. The managing general partner pays a
management fee to Atlas America for management and administrative services, as
described in "Management - Transactions with Management and Affiliates." See the
footnotes to the managing general partner's audited financial statements and the
footnotes to the managing general partner's unaudited financial statements for
more details concerning the credit facility and inter-company borrowings in
"Financial Information Concerning the Managing General Partner and Atlas America
Public #16-2007(A) L.P."

                              PROPOSED ACTIVITIES

OVERVIEW OF DRILLING ACTIVITIES

The managing general partner anticipates that the subscription proceeds of each
partnership will be used to drill primarily natural gas development wells, which
means a well drilled within the proved area of a natural gas or oil reservoir to
the depth of a stratigraphic horizon known to be productive. Stratigraphic means
a layer of rock which has characteristics that differentiate it from the rocks
above and below it. Stratigraphic horizon generally means that part of a
formation or layer of rock with sufficient porosity and permeability to form a
petroleum reservoir. Currently, the partnerships do not hold any interests in
any properties or prospects on which the wells will be drilled.

Although the majority of the wells to be drilled by each partnership will be
classified as natural gas wells, which may produce a small amount of oil, some
of the wells, such as wells drilled in McKean County, Pennsylvania, if any, may
be classified as oil or combination oil and natural gas wells.

Each partnership will be a separate business entity from the other partnership,
and you will be a partner only in the partnership in which you invest. You will
have no interest in the business, assets or tax benefits of the other
partnership unless you also invest in the other partnership. Thus, your
investment return will depend solely on the operations and success or lack of
success of the particular partnership in which you invest.

Each partnership generally will drill different wells, but they may own working
interests and participate in drilling and completing one or more of the same
wells. The number of wells to be drilled by a partnership cannot be determined
precisely before the funding of the partnership and is determined primarily by:

     o    the amount of subscription proceeds raised by the partnership;

     o    the geographical areas in which wells are drilled by the partnership;

     o    the partnership's percentage of working interest owned in the wells,
          which could range from 25% to 100%; and

                                       65
o    the cost of the partnership's wells, including any cost overruns for
          intangible drilling costs and equipment costs of the wells which are
          charged to you and the other investors under the partnership
          agreement.

For the estimated number of wells to be drilled at the minimum subscription
proceeds of $2 million and the maximum subscription proceeds of $200 million for
a partnership, see "Risk Factors - Risks Related to an Investment in a
Partnership - Spreading the Risks of Drilling Among a Number of Wells Will be
Reduced if Less than the Maximum Subscription Proceeds are Received and Fewer
Wells are Drilled."

Before the managing general partner selects a prospect on which a well will be
drilled by a partnership, it will review all available geologic and production
data for wells located in the vicinity of the proposed well including, but not
limited to:

     o    various well logs;

     o    completion reports;

     o    plugging reports; and

     o    production reports.

For example, production information from surrounding wells in the area is an
important indicator in evaluating the economic potential of a proposed well to
be drilled. It has been the managing general partner's experience that natural
gas production from wells drilled to the formations or the reservoirs in the
areas of operations discussed below in "- Primary Areas of Operations," is
reasonably consistent with nearby wells, although from time to time there can be
great differences in the natural gas volumes and performance of wells located on
contiguous prospects. However, production information is only one factor, and
the managing general partner may propose a well to be drilled by a partnership
because geologic trends in the immediate area, such as sand thickness,
porosities and water saturations, lead the managing general partner to believe
that the proposed well locations will be productive.

PRIMARY AREAS OF OPERATIONS

The managing general partner will not decide on all of the specific wells to be
drilled by a partnership until the offering of units in that partnership has
ended. However, the managing general partner intends that Atlas America Public
#16-2007(A) L.P. will drill the prospects described in "Appendix A - Information
Regarding Currently Proposed Prospects for Atlas America Public #16-2007(A)
L.P." These prospects represent the wells to be drilled if a portion of the
nonbinding targeted subscription proceeds for that partnership, as described in
"Terms of the Offering - Subscription to a Partnership," are received. If there
are material adverse events with respect to any of the currently proposed
prospects, the managing general partner will substitute a new prospect as
discussed below in "- Interests of Parties." Also, the managing general partner
has the sole discretion to sell up to and including all of the units in Atlas
America Public #16-2007(A) L.P., and it may and not offer and sell any units in
Atlas America Public #16-2007(B) L.P. In that event, the number of prospects
identified in "Appendix A - Information Regarding Currently Proposed Prospects
for Atlas America Public #16-2007(A) L.P." as a percentage of the total number
of prospects to be drilled by Atlas America Public #16-2007(A) L.P. would be
reduced. The managing general partner also anticipates that it will designate a
portion of the prospects in the partnership designated Atlas America Public
#16-2007(B) L.P., if units in that partnership are offered, by a supplement or
an amendment to the registration statement of which this prospectus is a part.

Because not all of the prospects for each partnership will be specified, you
will not be able to evaluate all of the prospects that will be drilled by your
partnership. However, by waiting as long as possible before selecting all of the
prospects to be drilled by a partnership, the managing general partner may
acquire additional information to help it select better prospects for the
partnership, and it may be able to include prospects that were not available
when this prospectus was written or even when the offering of units in the
partnership is closed.

The following discussion includes a general description of the areas where the
managing general partner anticipates partnership wells may be drilled. All of
the areas are situated in the Appalachian Basin, which is a mature producing
region

                                       66
in the United States overlaying the states of New York, Pennsylvania, Ohio,
Tennessee, West Virginia, Maryland, Kentucky and Virginia. The Appalachian Basin
has well known geologic characteristics as described below, although with
respect to each area listed below, the geological aspects are continually being
evaluated by the managing general partner. Thus, each area discussed may
ultimately include other counties which are not set forth below. For purposes of
this prospectus, however, the counties listed below are generally descriptive of
the specific drilling area being discussed. With the exception of the north
central Tennessee area, the primary areas are situated in western Pennsylvania
as discussed below. The three primary areas for the partnerships' drilling
activities are:

     o    the Mississippian/Upper Devonian Sandstone reservoirs in Fayette,
          Greene and Westmoreland Counties, Pennsylvania;

     o    the Clinton/Medina geological formation which includes western
          Pennsylvania, primarily Crawford and Mercer Counties, Pennsylvania and
          also includes an area in eastern Ohio situated primarily in Stark,
          Mahoning, Trumbull and Portage Counties, Ohio; and

     o    the Mississippian (carbonates) and Devonian Shale reservoirs in
          Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee.

All of the primary areas described above have the following similarities:

     o    geological features such as structure and faulting generally are not
          factors used to find commercial production from a well drilled to this
          formation or these reservoirs and the governing factors appear to be
          sand or oolite (carbonate sand) quality in terms of net pay zone
          thickness, porosity, and the effectiveness of fracture stimulation in
          the well;

     o    a well drilled to this formation or these reservoirs usually requires
          hydraulic fracturing of the formation to stimulate productive
          capacity;

     o    generally, natural gas from a well drilled to this formation or these
          reservoirs is produced at rates which decline rapidly during the first
          few years of operations and, although the well can produce for many
          years, a proportionately larger amount of the well's production can be
          expected within the first several years; and

     o    it has been the managing general partner's experience that natural gas
          production from wells drilled to this formation or these reservoirs is
          reasonably consistent with nearby wells, although from time to time
          there can be great differences in the natural gas volumes and
          performance of wells on contiguous prospects. Thus, as drilling
          progresses, reserves from newly completed wells are reclassified from
          the proved undeveloped to the proved developed category and additional
          adjacent locations are added to proved undeveloped reserves.

The managing general partner anticipates that the majority of the subscription
proceeds of each partnership will be expended in the primary areas, although
some of the subscription proceeds of each partnership may be expended in the
secondary areas or in areas that are not currently known. Among the primary
areas, the managing general partner anticipates that each partnership will drill
more prospects in the Fayette County, Pennsylvania area than in the other areas.

MISSISSIPPIAN/UPPER DEVONIAN SANDSTONE RESERVOIRS, FAYETTE COUNTY, PENNSYLVANIA.
The Mississippian/Upper Devonian Sandstone reservoirs are discontinuous
lens-shaped accumulations found throughout most of the Appalachian Basin. These
reservoirs have porosities ranging from 5% to 20% with attendant permeabilities.
Porosity is the percentage of void space between sand grains that is available
for occupancy by either liquids or gases; and permeability is the property of
porous rock that allows fluids or gas to flow through it. See the geologic
evaluation prepared by United Energy Development Consultants, Inc., an
independent geological and engineering firm in "Appendix A - Information
Regarding Currently Proposed Prospectus for Atlas America Public #16-2007(A)
L.P.", for a discussion of the development of the Mississippian/Upper Devonian
Sandstone reservoirs in Fayette, Greene and Westmoreland Counties, Pennsylvania.

                                       67
The wells in the Mississippian/Upper Devonian Sandstone reservoirs will be:

     o    situated on approximately 20 acres, subject to adjustment to take into
          account lease boundaries;

     o    drilled at least 1,000 feet from a producing well, although a
          partnership may drill a new well or re-enter an existing well that is
          closer than 1,000 feet to a plugged and abandoned well;

     o    drilled to approximately 1,900 to 6,000 feet in depth;

     o    classified as natural gas wells that may produce a small amount of
          oil; and

     o    primarily connected to the gathering system owned by Atlas Pipeline
          Partners and have their natural gas production primarily marketed to
          UGI Energy Services, Colonial Energy, ConocoPhillips Company and
          Equitable Gas Company as discussed below in "- Sale of Natural Gas and
          Oil Production."

CLINTON/MEDINA GEOLOGICAL FORMATION IN WESTERN PENNSYLVANIA. The Clinton/Medina
geological formation is a blanket sandstone found throughout most of the
northwestern edge of the Appalachian Basin. The Clinton/Medina geological
formation in Pennsylvania and Ohio is the same geological formation, although in
Pennsylvania it is often referred to as the Medina/Whirlpool geological
formation. For purposes of this prospectus, the term Clinton/Medina geological
formation is used for both Ohio and Pennsylvania. The Clinton/Medina geological
formation is described in petroleum industry terms as a "tight" sandstone with
porosity ranging from 6% to 12% and with very low natural permeability. Based on
the managing general partner's experience, it anticipates that all of the
natural gas wells drilled to the Clinton/Medina geological formation will be
completed and fraced in two different zones of the Clinton/Medina geological
feature. See the geologic evaluation and the model decline curve prepared by
United Energy Development Consultants, Inc. in "Appendix A - Information
Regarding Currently Proposed Prospects for Atlas America Public #16-2007(A)
L.P." for a discussion of the development of the Clinton/Medina Geological
Formation in western Pennsylvania and eastern Ohio.

The wells in the Clinton/Medina geological formation in western Pennsylvania and
eastern Ohio will be:

     o    primarily situated in Crawford, Mercer, Lawrence, Warren, and Venango
          Counties, Pennsylvania, and Stark, Mahoning, Trumbull and Portage
          Counties, Ohio;

     o    situated on approximately 50 acres, subject to adjustment to take into
          account lease boundaries;

     o    drilled at least 1,650 feet from each other in Pennsylvania, which is
          greater than the 660 feet minimum distance allowed by state law or
          local practice to protect against drainage from adjacent wells, and
          drilled at least 1,000 feet from each other in Ohio;

     o    drilled to approximately 5,000 to 6,300 feet in depth;

     o    classified as natural gas wells that may produce a small amount of
          oil, although the wells in eastern Ohio may be classified as oil
          wells; and

     o    primarily connected to the gathering system owned by Atlas Pipeline
          Partners and have their natural gas production primarily marketed to
          Hess Corporation as discussed below in "- Sale of Natural Gas and Oil
          Production."

Also, see "- Secondary Areas of Operations" below, for a discussion of the
Clinton/Medina geological formation in western New York and southern Ohio.

MISSISSIPPIAN CARBONATE AND DEVONIAN SHALE RESERVOIRS IN ANDERSON, CAMPBELL,
MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE. The Mississippian carbonate
reservoirs are discontinuous lens shaped accumulations found in the southern
Appalachian states of West Virginia, Virginia, Kentucky and Tennessee. These
reservoirs have porosities ranging from 6%

                                       68
to 20% with attendant permeabilities. The Devonian shale is found throughout the
Appalachian Basin. When the shale is highly fractured it becomes a reservoir.
See the geologic evaluation prepared by United Energy Development Consultants,
Inc. in "Appendix A - Information Regarding Currently Proposed Prospects for
Atlas America Public #16-2007(A) L.P." for a discussion of the development of
the Mississippian carbonate and Devonian Shale reservoirs in Anderson, Campbell,
Morgan, Roane and Scott Counties, Tennessee.

The wells in the Mississippian carbonate and Devonian Shale reservoirs will be:

     o    situated on 40 acres;

     o    drilled 1,320 feet from each other unless topography dictates
          otherwise, however, in all cases no less than 700 feet;

     o    drilled to approximately 1,500 to 5,500 feet in depth;

     o    classified as natural gas wells that may produce a small amount of
          oil; and

     o    primarily connected to the gathering system owned by Knox Energy LLC,
          which is referred to as the Coalfield Pipeline, and have their natural
          gas production primarily marketed to Duke Energy as discussed below in
          "- Sale of Natural Gas and Oil Production."

The prospects in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee
were acquired from Knox Energy LLC as described below in "- Interests of
Parties" and Knox Energy may participate in drilling wells in this area with the
partnerships.

SECONDARY AREAS OF OPERATIONS

The managing general partner also has reserved the right to use a portion of the
subscription proceeds of each partnership to drill development wells in other
areas of the Appalachian Basin or elsewhere in the United States. The secondary
areas anticipated by the managing general partner, which are situated in the
Appalachian Basin, are discussed below.

UPPER DEVONIAN SANDSTONE RESERVOIRS, ARMSTRONG COUNTY, PENNSYLVANIA. The Upper
Devonian Sandstone reservoirs are discontinuous lens-shaped accumulations found
throughout most of the Appalachian Basin. These reservoirs have porosities
ranging from greater than 5% to 20% with attendant permeabilities. The prospects
in Armstrong and Indiana Counties, Pennsylvania will be acquired from U.S.
Energy Exploration Corporation as described below and U.S. Energy will
participate in drilling the wells in this area with the partnerships.

The wells in the Upper Devonian Sandstone reservoirs will be:

     o    situated on approximately 15 acres, subject to adjustment to take into
          account lease boundaries;

     o    drilled at least 1,000 feet from each other, although under
          Pennsylvania law in certain circumstances a variance can be obtained,
          and some of the wells the managing general partner has drilled to date
          in this general area have been drilled less than 1,000 feet apart, but
          even in those cases the wells were approximately 980 feet or more from
          each other;

     o    drilled to approximately 1,800 to 4,400 feet in depth;

     o    classified as natural gas wells which may produce a small amount of
          oil; and

     o    connected to a gathering system owned by U.S. Energy and have their
          natural gas production marketed by U.S. Energy as discussed below in
          "- Sale of Natural Gas and Oil Production."

                                       69
The managing general partner anticipates the leases in Armstrong and Indiana
Counties, Pennsylvania will have a net revenue interest to a partnership of
84.375%. U.S. Energy, the originator of the leases, however, will retain a 25%
working interest in the wells and participate with the partnership in the costs
of drilling, completing, and operating the wells to the extent of its retained
working interest.

UPPER DEVONIAN SANDSTONE RESERVOIRS IN MCKEAN COUNTY, PENNSYLVANIA. See "- Upper
Devonian Sandstone Reservoirs, Armstrong County, Pennsylvania," above, for a
description of these reservoirs. Wells located in McKean County and drilled to
the Upper Devonian Sandstone reservoirs will be:

     o    situated on approximately 5 acres, subject to adjustments to take into
          account lease boundaries;

     o    drilled to approximately 2,000 to 2,500 feet in depth;

     o    classified as combination wells producing both natural gas and oil;

     o    drilled on leases with a net revenue interest of approximately 84.375%
          to 87.5%; and

     o    connected to the gathering systems owned by Atlas Pipeline Partners
          and M&M Royalty, LTD. and have their natural gas production primarily
          marketed to M&M Royalty, LTD. as discussed below in "- Sale of Natural
          Gas and Oil Production."

CLINTON/MEDINA GEOLOGICAL FORMATION IN WESTERN NEW YORK. Wells located in
western New York and drilled to the Clinton/Medina geological formation will be:

     o    primarily situated in Chautauqua County;

     o    situated on approximately 40 acres, subject to adjustment to take into
          account lease boundaries;

     o    drilled to approximately 3,800 to 4,000 feet in depth;

     o    drilled on leases with a net revenue interest of approximately 84.375%
          to 87.5%;

     o    classified as natural gas wells which may produce a small amount of
          oil; and

     o    connected to the gathering system owned by Atlas Pipeline Partners and
          have their natural gas production primarily marketed to Hess
          Corporation, commercial end users in the area, and/or Great Lakes
          Energy Partners, L.L.C. as discussed below in "- Sale of Natural Gas
          and Oil Production."

CLINTON/MEDINA GEOLOGICAL FORMATION IN SOUTHERN OHIO. Wells located in southern
Ohio and drilled to the Clinton/Medina geological formation will be:

     o    primarily situated in Noble, Washington, Guernsey, and Muskingum
          Counties;

     o    situated on approximately 40 acres, subject to adjustment to take into
          account lease boundaries;

     o    drilled at least 1,000 feet from each other;

     o    drilled to approximately 4,900 to 6,500 feet in depth;

     o    drilled on leases with a net revenue interest of approximately 82.5%
          to 87.5%;

     o    classified as either natural gas wells or oil wells; and

                                       70
o    primarily connected to the gathering system owned by Atlas Pipeline
          Partners (if classified as natural gas wells) and have their natural
          gas production marketed to Hess Corporation, although a portion of the
          natural gas production may be gathered and marketed by Triad Energy
          Corporation of West Virginia, Inc. as discussed below in "- Sale of
          Natural Gas and Oil Production."

Additionally, the managing general partner anticipates that the leases in
southern Ohio will have been originally acquired from a coal company and are
subject to a provision that the well must be abandoned if it hinders the
development of the coal. Thus, the managing general partner will not drill a
well on any lease subject to this provision unless it covers lands that were
previously mined. Although this does not totally eliminate the risk because the
leases may cover other coal deposits that might be mined during the life of a
well, the managing general partner believes that drilling wells on these
previously mined leases would be in the best interests of the partnerships.

ACQUISITION OF LEASES

The managing general partner will have the right, in its sole discretion, to
select the prospects which each partnership will drill. The managing general
partner intends that Atlas America Public #16-2007(A) L.P. will drill the
prospects described in "Appendix A - Information Regarding Currently Proposed
Prospects for Atlas America Public #16-2007(A) L.P." The managing general
partner also anticipates that it will designate a portion of the prospects in
Atlas America Public #16-2007(B) L.P., if units in that partnership are offered,
by means of a supplement or an amendment to the registration statement of which
this supplement is a part.

The leases covering each prospect on which one well will be drilled will be
acquired by a partnership from the managing general partner or its affiliates
and credited to the managing general partner as a part of its required capital
contribution to the partnership. Neither the managing general partner nor its
affiliates will receive any royalty or overriding royalty interest on any well.

The managing general partner anticipates that it will select the prospects for
each partnership, including any additional and/or substituted prospects, from
the following:

     o    leases in its and its affiliates' existing leasehold inventory;

     o    leases that are subsequently acquired by it or its affiliates; or

     o    leases owned by independent third-parties that may participate with
          the partnership in drilling wells.

The majority of the prospects acquired by a partnership will be in areas where
the managing general partner or its affiliates have previously conducted
drilling operations. The managing general partner believes that its and its
affiliates' leasehold inventory and leases acquired from third-parties will be
sufficient to provide all the development prospects to be drilled by the
partnerships if the targeted maximum subscription proceeds of $200 million are
received. In this regard, the managing general partner and its affiliates are
continually engaged in acquiring additional leasehold acreage in Pennsylvania,
Ohio, and other areas of the United States. As of August 15, 2006, the managing
general partner's and its affiliates' undeveloped leasehold acreage was as
follows:

                                       71
UNDEVELOPED LEASE ACREAGE
                                 -------------------------
                                      GROSS     NET (1)
                                     -------   --------
Kentucky .....................         9,060     4,530
Montana ......................         2,650     2,650
New York .....................        38,534    38,534
Ohio .........................        37,851    34,414
Pennsylvania .................       189,910   189,910
West Virginia ................        10,806     5,403
Wyoming ......................            80        80
                                     -------   -------
   Total .....................       288,891   275,521
                                     =======   =======

(1)  The net acreage as to which leases expire in fiscal 2007 are as follows:
     Ohio: 2007 - 1,538 acres and Pennsylvania: 2007 - 12,938 acres.

Most, if not all, of the prospects to be selected for the partnerships are
expected by the managing general partner to be single well proved undeveloped
prospects that are classified as developmental. Thus, only one well will be
drilled on each of those prospects and the number of prospects that the managing
general partner will assign to each partnership will be the same as the number
of wells that the partnership has the funds to drill. This also means that the
partnership, in all likelihood, will not farmout any acreage associated with
those prospects. However, the need for a farmout might arise, for example, if
during drilling or subsequently the managing general partner determines there
might be a productive horizon situated above (i.e. uphole) the target horizon,
but the partnership does not have the funds to complete the well in the horizon
or the completion of the horizon would be inconsistent with the partnership's
objectives. In this event, the managing general partner might decide to farmout
the activity for the partnership. Generally, a farmout is an agreement in which
the owner of the lease or existing well agrees to assign its interest in certain
acreage under the lease or the existing well to an assignee subject to the
assignee drilling one or more wells or completing or recompleting the existing
well in one or more horizons. The owner would retain some interest in the
assigned acreage or well. See "Conflicts of Interest - Conflicts Involving the
Acquisition of Leases" for the procedure for a farmout, and "Federal Income Tax
Consequences - Farmouts."

DEEP DRILLING RIGHTS RETAINED BY MANAGING GENERAL PARTNER. The lease assignments
to each partnership generally will be limited to a depth from the surface to the
deepest depth penetrated at the cessation of drilling operations. The managing
general partner will retain the deeper drilling rights, including ownership of
any coal bed methane production that might be obtained from the deeper
formations. Conversely, as between a partnership and the managing general
partner, the partnership will own any coal bed methane production that might be
obtained from the shallower formations that are not included in the deeper
drilling rights retained by the managing general partner.

The amount of the credit the managing general partner receives for the leases it
contributes to a partnership will not include any value allocable to the deeper
drilling rights retained by it. If the managing general partner undertakes any
activities with respect to the deeper formations in the future, then the
partnerships would not share in the profits from these activities, nor would the
partnerships pay any of the associated costs.

INTERESTS OF PARTIES

Generally, production and revenues from a well drilled by a partnership will be
net of the applicable landowner's royalty interest, which is typically 1/8th
(12.5%) of gross production, and any interest in favor of third-parties such as
an overriding royalty interest. Landowner's royalty interest generally means an
interest that is created in favor of the landowner when an oil and gas lease is
obtained; and overriding royalty interest generally means an interest that is
created in favor of someone other than the landowner. In either case, the owner
of the interest receives a specific percentage of the natural gas and oil
production free and clear of all costs of development, operation, or maintenance
of the well. This is compared with a working interest, which generally means an
interest in the lease under which the owner of the interest must pay

                                       72
some portion of the cost of development, operation, or maintenance of the well.
Also, the leases will be subject to terms that are customary in the industry
such as free gas to the landowner-lessor for home heating requirements, etc.

The managing general partner anticipates that each partnership generally will
have a net revenue interest in its leases in its primary drilling areas as set
forth in the chart below. Net revenue interest generally means the percentage of
revenues the owner of an interest in a well is entitled to receive under the
lease. The following chart expresses the percentage of production revenues that
the managing general partner, the landowner, other third-parties, and you and
the other investors in a partnership will share in from the wells in two of the
three primary drilling areas. The third primary drilling area in Anderson,
Campbell, Morgan, Roane and Scott Counties, Tennessee is discussed following the
chart. The chart assumes that the partnership owns 100% of the working interest
in the well. If a partnership acquires a lesser percentage working interest in a
well, which may be the case in Anderson, Campbell, Morgan, Roane and Scott
Counties, Tennessee, then the partnership's net revenue interest in that well
will decrease proportionately.

The actual number, identity and percentage of working interests or other
interests in prospects to be acquired by the partnerships will depend on, among
other things:

     o    the amount of subscription proceeds received by a partnership;

     o    the latest geological and production data;

     o    potential title or spacing problems;

     o    availability and price of drilling services, tubular goods and
          services;

     o    approvals by federal and state departments or agencies;

     o    agreements with other working interest owners in the prospects;

     o    farmins and farmouts; and

     o    continuing review of other prospects that may be available.

PRIMARY AREAS.

CLINTON/MEDINA GEOLOGICAL FORMATION IN WESTERN PENNSYLVANIA AND
MISSISSIPPIAN/UPPER DEVONIAN SANDSTONE RESERVOIRS IN FAYETTE COUNTY,
PENNSYLVANIA.
PARTNERSHIP                      THIRD PARTY                87.5% PARTNERSHIP
ENTITY                                     INTEREST                     ROYALTY INTEREST           NET REVENUE INTEREST (2)
------                           ----------------------------   --------------------------------   ------------------------
Managing General Partner......   32% partnership interest (1)                                                28.0%
Investors.....................   68% partnership interest (1)                                                59.5%
Third Party...................                                  12.5% Landowner Royalty Interest             12.5%
                                                                                                            -----
                                                                                                            100.0%
                                                                                                            =====
----------
(1)  These percentages are for illustration purposes only, and assume that the
     partnership has a 100% working interest and the managing general partner
     contributes its minimum required capital contribution of 25% to each
     partnership and the capital contributions from you and the other investors
     are 75%. The actual percentages are likely to be different because they
     will be based on the actual capital contributions of the managing general
     partner and you and the other investors. However, the managing general
     partner's total revenue share may not exceed 40% of partnership revenues
     regardless of the amount of its capital contributions.

(2)  The managing general partner anticipates that the majority of the wells in
     the Clinton/Medina Geological Formation in western Pennsylvania will have a
     net revenue interest of 84.375% which, using the assumptions set forth in
     footnote

                                       73
(1),  would  provide you and the other  investors in the  partnership  as a
     group 57.375% of that partnership's revenues from those wells.

MISSISSIPPIAN CARBONATE AND DEVONIAN SHALE RESERVOIRS IN ANDERSON, CAMPBELL,
MORGAN, ROANE AND SCOTT COUNTIES, TENNESSEE. Generally, the leases in north
central Tennessee will have a net revenue interest to a partnership ranging from
84.375% to 81.375%, assuming that a partnership has a 100% working interest.
However, the amount of the partnership's net revenue interest in some of the
prospects could be as low as 81.375% depending primarily on whether the
landowner royalty interest is 12.5% or 15.5%. The amount of the landowner
royalty depends, in turn, on whether the natural gas produced from those
prospects, if any, is sold at a price above or below $3.00 per mcf, and on
whether Knox Energy LLC and its affiliates, the originators of the leases,
participate as a working interest owner with a partnership in the leases
covering those prospects. Knox Energy and its affiliates may retain up to a 50%
working interest in the wells and participate with the partnership in the costs
of drilling, completing, and operating the wells to the extent of its retained
working interest. Also, if Knox Energy does not retain a working interest in a
well, then its overriding royalty interest will be 3.125%. However, if Knox
Energy retains a 50% working interest in a well, then its overriding royalty
interest of 3.125% will be reduced to 1.5625%. To the extent that Knox Energy
participates in a well as a working interest owner for less than a 50% working
interest, its overriding royalty interest will be prorated between 3.125% and
1.5625% depending on the percentage of its working interest. The investors' net
revenue interest in the above example would range from 57.375% to 55.335%, if
presented on a 100% working interest basis and the investors were receiving 68%
of the partnership revenues.

Pursuant to the acquisition terms of the agreement between the managing general
partner and its affiliates and Knox Energy and its affiliates, no well drilled
by the managing general partner and its affiliates in this area, which includes
the partnerships, may produce coalbed methane gas, and the managing general
partner or its affiliates must drill 300 commitment wells during the initial
three year term of the agreement with Knox Energy, which ends June 30, 2007, or
they will be in breach of the agreement.

SECONDARY AREAS

Although the managing general partner anticipates that each partnership will
have a net revenue interest ranging from 81% to 87.5% in its leases in the
secondary areas described above, assuming it owns 100% of the working interest,
there is no minimum net revenue interest that a partnership is required to own
before drilling a well in other areas of the United States. The leases in these
other areas may be subject to interests in favor of third-parties that are not
currently known such as overriding royalty interests, net profits interests,
carried interests, production payments, reversionary interests pursuant to
farmouts or non-consent elections under joint operating agreements, or other
retained or carried interests.

TITLE TO PROPERTIES

Title to all leases acquired by a partnership ultimately will be held in the
name of the partnership. However, to facilitate a partnership's acquisition of
the leases title to the leases may initially be held in the name of the managing
general partner, the operator, their affiliates, or any nominee designated by
the managing general partner. Title to each partnership's leases will be
transferred to the partnership and filed for record from time to time after the
wells are drilled and completed.

The managing general partner will take the steps it deems necessary to assure
that each partnership has acceptable title for its purposes. However, it is not
the practice in the natural gas and oil industry to warrant title or obtain
title insurance on leases and the managing general partner will provide neither
for the leases it assigns to a partnership. The managing general partner will
obtain a favorable formal title opinion for the leases before each well is
drilled, but will not obtain a division order title opinion after the well is
completed. The managing general partner may use its own judgment in waiving
title requirements and will not be liable for any failure of title of the leases
transferred to a partnership. Also, the partnerships may experience losses from
title defects excluded from, or not disclosed by, the formal title opinion that
is provided to the managing general partner before a well is drilled or that
would have been disclosed by a division order title opinion after the well is
drilled, if the partnership obtained division order title opinions, which it
will not do. Although past performance is no guarantee of future results, the
previous drilling partnerships sponsored by the managing general partner and its
affiliates have participated in drilling more than 3,220 wells in the
Appalachian Basin since 1985, and none of the wells have been lost because of
title failure. (See "Prior Activities.")

                                       74
DRILLING AND COMPLETION ACTIVITIES; OPERATION OF PRODUCING WELLS

On receipt of the minimum subscription proceeds of a partnership, the managing
general partner on behalf of the partnership may break escrow, transfer the
escrowed funds to a partnership account, enter into the drilling and operating
agreement, which is attached to the partnership agreement as Exhibit II, with
itself or an affiliate of the managing general partner as operator, and begin
drilling the partnership's wells.

Under the drilling and operating agreement, the responsibility for drilling and
either completing or plugging partnership wells will be on the managing general
partner or an affiliate of the managing general partner as the operator and the
general drilling contractor. Under the drilling and operating agreement, each
partnership is required to prepay the investors' share of the drilling and
completion costs of its wells to the managing general partner as the general
drilling contractor and operator. If one or more of a partnership's wells will
be drilled in the calendar year after the year in which the advance payment is
made, the required advance payment allows the partnership to secure tax benefits
of prepaid intangible drilling costs based on a substantial business purpose for
the advance payment under the drilling and operating agreement. The managing
general partner as operator and general drilling contractor will begin drilling
all of the wells no later than March 30, 2008 for the partnerships. (See
"Federal Income Tax Consequences - Drilling Contracts.")

During drilling operations the managing general partner's duties as operator and
general drilling contractor will include:

     o    making  the  necessary   arrangements   for  drilling  and  completing
          partnership   wells   and   related   facilities   for  which  it  has
          responsibility under the drilling and operating agreement;

     o    managing  and  conducting  all field  operations  in  connection  with
          drilling, testing, and equipping the wells; and

     o    making the technical decisions required in drilling and completing the
          wells.

All partnership wells will be drilled to a sufficient depth to test thoroughly
the objective geological formation unless the managing general partner
determines in its sole discretion that the well shall be completed in a
formation uphole from the objective geological formation.

Under the drilling and operating agreement the managing general partner, as
operator and general drilling contractor, will complete each well if there is a
reasonable probability of obtaining commercial quantities of natural gas or oil.
However, based on its past experience, the managing general partner anticipates
that most of the development wells drilled by the partnerships in the primary
and secondary areas will have to be completed before the managing general
partner can determine the well's productivity. If the managing general partner,
as operator and general drilling contractor, determines that a well should not
be completed, then the well will be plugged and abandoned.

During producing operations the managing general partner's duties, as operator,
will include:

     o    managing  and  conducting  all field  operations  in  connection  with
          operating and producing the wells;

     o    making the technical decisions required in operating the wells; and

     o    maintaining the wells, equipment, and facilities in good working order
          during their useful life.

The managing general partner, as operator, will be reimbursed for its direct
expenses and will receive well supervision fees at competitive rates for
operating and maintaining the wells during producing operations as discussed in
"Compensation." As discussed in "Summary of Drilling and Operating Agreement,"
the drilling and operating agreement contains a number of other material
provisions which you are urged to review.

Certain wells may be drilled by a partnership with third-parties owning a
portion of the working interest in the wells. Any other working interest owner
in a well will have a separate agreement with the managing general partner for
drilling and

                                       75
operating the well with differing terms and conditions from those contained in a
partnership's  drilling  and  operating  agreement.  (See  "Federal  Income  Tax
Consequences -- Drilling Contracts.")

SALE OF NATURAL GAS AND OIL PRODUCTION

POLICY OF TREATING ALL WELLS EQUALLY IN A GEOGRAPHIC AREA. All benefits and
liabilities from marketing and hedging arrangements or other relationships
affecting the property of the managing general partner or its affiliates and the
partnerships shall be fairly and equitably apportioned according to the
respective interests of each in the property. The managing general partner is
responsible for selling each partnership's natural gas and oil production, and
its policy is to treat all wells in a given geographic area equally. This
reduces certain potential conflicts of interest among the owners of the various
wells, including the partnerships sponsored by the managing general partner,
concerning to whom and at what price the natural gas and oil will be sold. For
example, the managing general partner calculates a weighted average selling
price for all of the natural gas sold in the geographic area and this is the
price which will be paid to each partnership in the geographic area for its
natural gas. For natural gas sold in western Pennsylvania during its previous
four fiscal years, the managing general partner received an average selling
price after deducting all expenses, including transportation expenses and after
the effects of hedging arrangements, of approximately:

     o    $3.34 per mcf, "mcf" means 1,000 cubic feet of natural gas, in 2002;

     o    $4.78 per mcf in 2003;

     o    $5.64 per mcf in 2004; and

     o    $6.72 per mcf in 2005.

If all of the natural gas produced in an area cannot be sold by the managing
general partner and its affiliates, including the partnerships, because of
limited gathering line or pipeline capacity, or limited demand for the natural
gas, which increases pipeline pressure, then the production that is sold will be
from those wells that have the greatest well pressure and are able to feed into
the pipeline, regardless of which partnerships own the wells. The proceeds from
these natural gas sales will be credited only to the partnerships whose wells
produced the natural gas sold.

GATHERING OF NATURAL GAS. Under the partnership agreement the managing general
partner will be responsible for gathering and transporting the natural gas
produced by the partnerships to interstate pipeline systems, local distribution
companies, and/or end-users in the area. For the majority of each partnership's
natural gas production, including natural gas in the primary areas, as discussed
below, the managing general partner anticipates that it will use the gathering
system owned by Atlas Pipeline Partners, L.P. (and Atlas Pipeline Operating
Partnership), which is a master limited partnership formed by a subsidiary of
Atlas America as managing general partner using Atlas America personnel who act
as its officers and employees. (See "Management - Organizational Diagrams and
Security Ownership of Beneficial Owners.") Atlas Pipeline Partners acquired the
natural gas gathering system and related facilities of Atlas America, Resource
Energy, and Viking Resources in February 2000. The gathering system consists of
more than 1,400 miles of intrastate pipelines located in western Pennsylvania,
eastern Ohio, and western New York.

If a partnership's natural gas is not transported through the Atlas Pipeline
Partners gathering system, it is because there is a third-party operator or the
gathering system has not been extended to the wells. In these cases, which
includes the McKean County area and the north central Tennessee area, as
described in "Compensation - Gathering Fees," the natural gas will be
transported through a third-party gathering system, and the partnership will pay
the managing general partner a competitive gathering fee, all or a portion of
which will be paid by it to the third-party. Also, in the north central
Tennessee area, the managing general partner and its affiliates may construct a
gathering system in the future for which they will receive gathering fees as
described in "Compensation - Gathering Fees."

As a part of the sale of the gathering system to Atlas Pipeline Partners in
February 2000, Atlas America and its affiliates, Resource Energy and Viking
Resources (the "Atlas entities"), made certain commitments that were intended to
maximize the use and expansion of the gathering system. Those commitments were
made pursuant to a master natural gas gathering

                                       76
agreement and an omnibus agreement which were entered into at the time of sale
in February 2000. Both the master natural gas gathering agreement and the
omnibus agreement set forth continuing obligations of the Atlas entities that
have no specified term, except that they will terminate with respect to future
wells drilled by the Atlas entities if the general partner of Atlas Pipeline
Partners, L.P., Atlas Pipeline Partners GP, LLC (which is owned by Atlas
Pipeline Holdings, L.P., a limited partnership that recently completed a public
offering as described in "Management - Organizational Diagrams and Security
Ownership of Beneficial Owners") is removed without cause and without its
consent. However, under the master natural gas gathering agreement the Atlas
entities, including the partnerships in this case, have committed the natural
gas production from the wells they drill before removal of Atlas Pipeline
Partners GP, LLC without cause and without its consent, for the life of the
wells. Thus, the termination of the master natural gas gathering agreement under
the circumstance described above will only terminate the obligation of the Atlas
entities, including the partnerships, to transport their natural gas through
Atlas Pipeline Partners' gathering system with respect to wells drilled on or
after the termination of the agreement. Some of these commitments still affect
the partnerships. For example, under the master natural gas gathering agreement
the Atlas entities are required to pay a gathering fee to Atlas Pipeline
Partners equal to the greater of $0.35 per mcf or 16% of the gross sales price
for each mcf transported through Atlas Pipeline Partners' gathering system. If a
partnership pays a lesser amount, which is anticipated by the managing general
partner as described in "Compensation - Gathering Fees," then the Atlas entities
must pay the difference to Atlas Pipeline Partners. Also, if Atlas Pipeline
Partners determines that the continued operation of any part of the gathering
system is not economically justified, then it may elect to discontinue the
operation of that portion of the gathering system. If Atlas Pipeline Partners
makes this determination, then it must give the parties to the agreement the
right to purchase that part of the gathering system for $10.

Under the omnibus agreement, Atlas America is required to commit to Atlas
Pipeline Partners' gathering system all wells it drills and operates, including
those of the partnerships, that are within 2,500 feet of the Atlas Pipeline
Partners gathering system. In addition, the Atlas entities, including the
partnerships, must construct at their own cost, up to 2,500 feet of flowline as
necessary to connect their wells to Atlas Pipeline Partners' gathering system.
Also, Atlas Pipeline Partners must, at its own cost, extend its gathering system
to connect to any flowlines constructed by the Atlas entities, including the
partnerships, that are within 1,000 feet of its gathering system. With respect
to wells to be drilled by Atlas America and its affiliates, including the
partnerships, that will be more than 3,500 feet from Atlas Pipeline Partners'
gathering system, Atlas Pipeline Partners has various options, in its
discretion, to connect those wells to its gathering system at its own cost.
Also, Atlas America and its affiliates may not divest their ownership of Atlas
Pipeline Partners GP, LLC without also divesting their ownership of the entities
serving as managing general partner in all of their affiliated investment
partnerships, including the partnerships, to the same acquirer, except that
Atlas America is permitted to transfer its ownership interest in Atlas Pipeline
Partners GP, LLC to a wholly- or majority-owned direct or indirect subsidiary as
long as Atlas America continues to control that subsidiary. See "Management -
Organizational Diagram and Security Ownership of Beneficial Owners," regarding
the public offering in Atlas Pipeline Holdings, L.P., which owns Atlas Pipeline
Partners GP, LLC. Further, Atlas Pipeline Partners GP, LLC has pledged its
equity interests in Atlas Pipeline Partners as security for the revolving credit
facility of Atlas America discussed in "Management's Discussion and Analysis of
Financial Condition, Results of Operations, Liquidity and Capital Resources."

NATURAL GAS CONTRACTS. As set forth in "- Primary Areas of Operations," each
partnership has three primary areas where it will drill its wells, and the
managing general partner anticipates that there will be a different natural gas
purchaser or purchasers in each area. The managing general partner anticipates
that more prospects will be drilled in the Fayette County area, which is one of
the primary drilling areas, than in the other areas, and the natural gas
produced from the Fayette County area will be sold to UGI Energy Services,
ConocoPhillips Company, Equitable Gas Company and Colonial Energy pursuant to
contracts which end March 31, 2008, except with respect to Colonial Energy,
which ends March 31, 2009. The natural gas produced from north central
Tennessee, which is one of the three primary areas, will be sold to Duke Energy
pursuant to a contract which ends October 31, 2008. The managing general partner
anticipates that the remainder of the natural gas produced by the partnership
from wells drilled in the other primary area (Clinton/Medina in Western
Pennsylvania) and the secondary areas, other than Armstrong and McKean Counties,
Pennsylvania will be sold to Hess Corporation ("Hess") as discussed below.

                                       77
The managing general partner and its affiliates previously entered into a
10-year agreement with First Energy Solutions Corporation, which is the
marketing affiliate of First Energy Corporation, a large regional electric
utility. This agreement was sold by First Energy Solutions Corporation to Hess
effective April 1, 2005. Subject to the exceptions set forth below, Hess has the
right to buy all of the natural gas produced and delivered by the managing
general partner and its affiliates, which includes each partnership and the
managing general partner's other partnerships, at certain delivery points with
the facilities of East Ohio Gas Company, National Fuel Gas Distribution,
Columbia of Ohio, and Peoples Natural Gas Company, which are local distribution
companies; and National Fuel Gas Supply, Columbia Gas Transmission Corporation
and Tennessee Gas Pipeline Company, which are interstate pipelines. This
contract, which ends April 1, 2009, is important to the managing general partner
and its affiliates because as of July 31, 2006 the managing general partner and
its affiliates, including its prior affiliated partnerships, were selling
approximately 40.9% of their natural gas production under the agreement with
Hess. However, as set forth above, each partnership will sell a much smaller
percentage of its natural gas to Hess because of certain exceptions to the
agreement, including natural gas sold through interconnects established after
the agreement, which includes the majority of the natural gas produced from
wells in the Fayette County, Pennsylvania area, and natural gas produced from
well(s) subject to an agreement under which a third-party was to arrange for the
gathering and sale of the natural gas such as natural gas produced from wells in
north central Tennessee, one of the primary drilling areas, or in Armstrong and
McKean Counties, Pennsylvania, which are both secondary drilling areas.

The pricing and delivery arrangements with all of the natural gas purchasers
described above are tied to the settlement of the New York Mercantile Exchange
Commission ("NYMEX") monthly futures contracts price, which is reported daily in
the Wall Street Journal and with an additional premium, which is referred to as
the basis, paid because of the location of the natural gas (the Appalachian
Basin) in relation to the natural gas market. The premium over quoted prices on
the NYMEX received by the managing general partner and its affiliates has ranged
between $0.51 to $1.07 per Mcf during the managing general partner's past three
fiscal years. These figures are based on the overall weighted average that the
managing general partner and its affiliates used in their annual reserve reports
for their past three fiscal years. Generally, the purchase agreements may be
suspended for force majeure, which generally means an Act of God.

Pricing for natural gas and oil has been volatile and uncertain for many years.
To limit the managing general partner's and its partnerships' exposure to
decreases in natural gas prices, the managing general partner and its
affiliates, Atlas America and/or Atlas Energy Resources, LLC use forward sales
transactions through its natural gas purchasers as discussed below and hedges
through contracts such as regulated NYMEX futures and options contracts and
non-regulated over-the-counter futures contracts with qualified counterparties.
The forward sales transactions require firm delivery of natural gas and,
therefore, are considered normal sales of natural gas, rather than hedges, for
accounting purposes. The futures contracts employed by the managing general
partner are commitments to purchase or sell natural gas at future dates and
generally cover one-month periods for up to 36 months in the future. To assure
that the financial instruments will be used solely for hedging price risks and
not for speculative purposes, the managing general partner has established a
committee to assure that all financial trading is done in compliance with the
managing general partner's hedging policies and procedures. The managing general
partner does not intend to contract for positions that it cannot offset with
actual production.

All of the natural gas purchasers described above and many third-party marketers
use NYMEX based financial instruments to hedge their pricing exposure, and they
make price hedging opportunities available to the managing general partner. The
forward sales transactions are similar to NYMEX based futures contracts, swaps
and options, but also require firm physical delivery of the natural gas. Because
of this, the managing general partner limits these arrangements to much smaller
quantities of natural gas than those projected to be available at any delivery
point. The price paid by the natural gas purchasers for certain volumes of
natural gas sold under these hedge agreements may be significantly different
from the underlying monthly spot market value. As of April 2, 2006, a portion of
the managing general partner's natural gas was subject to forward sales
transactions through March 31, 2007. After March 31, 2007, none of the managing
general partner's and its affiliates' natural gas is subject to forward sales
transactions and the managing general partner and its affiliates anticipate
using financial hedges as discussed below for all of its natural gas that is
hedged, although this may change from time to time.

                                       78
On October 27, 2005, the managing general partner and its affiliates implemented
financial hedges through its banking counter-party, Wachovia Bank, and as of
October 2, 2006, the managing general partner and its affiliates have hedged
approximately 51% of their natural gas production using fixed-for-floating
financial swaps for the period April 1, 2007 through December 31, 2009. The
managing general partner and its affiliates are also negotiating with other
banking counter-parties to implement its financial hedges.

The percentages of natural gas that is hedged through either financial hedges or
forward sales transactions or not hedged at all will change from time to time in
the discretion of Atlas America or Atlas Energy Resources, LLC. It is difficult
to project what portion of these hedges will be allocated to each partnership by
the managing general partner because of uncertainty about the quantity, timing,
and delivery locations of natural gas that may be produced by a partnership.
Although hedging provides the partnerships some protection against falling
prices, these activities also could reduce the potential benefits of price
increases and the partnerships could incur liability on the financial hedges.
For example, if a partnership's production is substantially less than expected,
the counterparties to the futures contracts fail to perform under the contracts
or there is a sudden, unexpected event materially impacting natural gas prices.
Subject to the managing general partner's and its affiliates' interest in their
natural gas contracts or pipelines and gathering systems, all benefits and
liabilities from marketing and hedging or other relationships affecting the
property of the managing general partner or its affiliates or the partnerships
must be fairly and equitably apportioned according to the interests of each in
the property.

MARKETING OF NATURAL GAS PRODUCTION FROM WELLS IN OTHER AREAS OF THE UNITED
STATES. The managing general partner expects that natural gas produced by the
partnership from wells drilled in areas of the Appalachian Basin other than
those described above will be primarily tied to the spot market price and
supplied to:

     o    gas marketers;

     o    local distribution companies;

     o    industrial or other end-users; and/or

     o    companies generating electricity.

CRUDE OIL. Crude oil produced from a partnership's wells will flow directly into
storage tanks where it will be picked up by the oil company, a common carrier,
or pipeline companies acting for the oil company which is purchasing the crude
oil. Unlike natural gas, crude oil does not present any transportation problem.
The managing general partner anticipates selling any oil produced by the wells
to regional oil refining companies at the prevailing spot market price for
Appalachian crude oil in spot sales. The managing general partner received an
average selling price for oil during its previous four fiscal years of
approximately $18.92 per barrel in 2002; $29.06 per barrel in 2003; $34.41 per
barrel in 2004; and $50.00 per barrel in 2005. During the term of the
partnerships it is anticipated that the price of oil will be uncertain and
volatile.

INSURANCE

Since 1972 the managing general partner and its affiliates, including its
partnerships, have been involved in drilling more than 5,300 wells, most of
which were developmental wells, in Ohio, Pennsylvania, and other areas of the
Appalachian Basin. They have made only one material insurance claim and as
discussed below, one which may evolve into a material claim. In February 2004,
one of the wells in another investment partnership incurred an uncontrolled flow
of natural gas and oil with a fire during drilling. These problems with the well
were subsequently controlled, but they resulted in the loss of a subcontractor's
drilling rig and third-party claims. As of April 19, 2005, the managing general
partner's insurance carrier had paid approximately $1.6 million to third-parties
for property damage claims and additional claims have been submitted which have
not yet been paid. The managing general partner's insurance company is exploring
all avenues for subrogation. In addition, in February 2006, there was a well
fire during the drilling of a well in Fayette County, Pennsylvania which
resulted in a claim against the managing general partner's insurance carrier in
an amount which has not been quantified. See "Actions to be Taken by Managing
General Partner to Reduce Risks of Additional Payments by Investor General
Partners - Insurance" for a discussion of the insurance coverage the managing
general partner intends to be available for a partnership's benefit.

                                       79
USE OF CONSULTANTS AND SUBCONTRACTORS

The partnership agreement authorizes the managing general partner to use the
services of independent outside consultants and subcontractors on behalf of the
partnerships. The services will normally be paid on a per diem or other cash fee
basis and will be charged to the partnership on whose behalf the costs were
incurred as either a direct cost or as a direct expense under the drilling and
operating agreement. These charges will be in addition to the costs of
subcontractor services provided by the managing general partner's affiliates,
which will be charged at competitive rates, and the oversight and administration
fee that will be paid to the managing general partner during drilling
operations, and the well supervision fees paid to the managing general partner
as operator as discussed in "Compensation."

                       COMPETITION, MARKETS AND REGULATION

NATURAL GAS REGULATION

Governmental agencies regulate the production and transportation of natural gas.
Generally, the regulatory agency in the state where a producing natural gas well
is located supervises production activities and the transportation of natural
gas sold into intrastate markets, and the Federal Energy Regulatory Commission
("FERC") regulates the interstate transportation of natural gas.

Natural gas prices have not been regulated since 1993, and the price of natural
gas is subject to the supply and demand for natural gas along with factors such
as the natural gas' BTU content and where the wells are located. Since 1985 FERC
has sought to promote greater competition in natural gas markets in the United
States. Traditionally, natural gas was sold by producers to interstate pipeline
companies that served as wholesalers and resold the natural gas to local
distribution companies for resale to end-users. FERC changed this market
structure by requiring interstate pipeline companies to transport natural gas
for third-parties. In 1992 FERC issued Order 636 and a series of related orders
that required pipeline companies to, among other things, separate their sales
services from their transportation services and provide an open access
transportation service that is comparable in quality for all natural gas
producers or suppliers. The premise behind FERC Order 636 was that the
interstate pipeline companies had an unfair advantage over other natural gas
producers or suppliers because they could bundle their sales and transportation
services together. FERC Order 636 is designed to ensure that no natural gas
seller has a competitive advantage over another natural gas seller because it
also provides transportation services.

In 2000 FERC issued Order 637 and subsequent orders to further enhance
competition by removing price ceilings on short-term capacity release
transactions. It also enacted other regulatory policies that are intended to
enhance competition in the natural gas market and increase the flexibility of
interstate natural gas transportation. FERC also has required pipeline companies
to develop electronic bulletin boards to provide standardized access to
information concerning capacity and prices.

CRUDE OIL REGULATION

Oil prices are not regulated, and the price is subject to the supply and demand
for oil, along with qualitative factors such as the gravity of the crude oil and
sulfur content differentials.

COMPETITION AND MARKETS

Many companies engage in natural gas and oil drilling operations in the
Appalachian Basin, where most or all of the wells in each partnership will be
located. According to the Energy Information Administration, the independent
statistical and analytical agency within the Department of Energy, in 2004 there
were 23 quadrillion BTU of natural gas consumed in the United States which
represented approximately 23% of the total energy used. The Appalachian Basin
accounted for approximately 5.7% of the total domestic natural gas production in
the United States in 2004 and represented approximately 12.5% of the total
number of wells drilled in the United States during 2004. Also, according to the
Natural Gas Annual 2004 Report, which is published by the Energy Information
Administration Office of Oil and Gas, as of December 31, 2004, the Appalachian
Basin's economically recoverable natural gas reserves represented approximately
8% of total domestic natural gas reserves.

                                       80
The natural gas and oil industry is highly competitive in all phases, including
acquiring suitable leases to drill and marketing natural gas and oil production
from the wells. Product availability and price are the principal means of
competing in selling natural gas and oil. Many of the partnerships' competitors
will have financial resources and staffs larger than those available to the
partnerships. This may enable them to identify and acquire desirable leases and
market their natural gas and oil production more effectively than the managing
general partner and the partnerships. While it is impossible to accurately
determine the partnerships' industry position, the managing general partner does
not consider that the partnerships' intended operations will be a significant
factor in the industry.

The natural gas and oil industry has from time to time experienced periods of
rapid cost increases. The increase in natural gas and oil prices over the last
several years also has increased the demand for drilling rigs and other related
equipment and the costs of drilling and completing natural gas and oil wells.
Additionally, the managing general partner and its affiliates have experienced
an increase in the cost of tubular steel used in drilling wells. Because each
partnership's wells will be drilled on a modified cost plus basis as described
in "Compensation - Drilling Contracts," these increased costs will increase the
partnerships' costs to drill and complete their wells. Also, the reduced
availability of drilling rigs and other related equipment may make it more
difficult to drill each partnership's wells in a timely manner or to comply with
the prepaid intangible drilling costs rules discussed in "Federal Income Tax
Consequences - Drilling Contracts." Further, over the term of each partnership
there may be fluctuating or increasing costs in doing business which directly
affect the managing general partner's ability to operate the partnership's wells
at acceptable price levels.

The natural gas and oil produced by your partnership's wells must be marketed in
order for you to receive revenues. During its fiscal years ending in 2005, 2004,
and 2003, the managing general partner did not experience any problems in
selling natural gas and oil, although the prices varied significantly during
those periods. As set forth above, natural gas and oil prices are not regulated,
but instead are subject to factors which are generally beyond the partnerships'
and the managing general partner's control such as the supply and demand for
natural gas and oil. For example, reduced natural gas demand and/or excess
natural gas supplies will result in lower prices. Other factors affecting the
price and/or marketing of natural gas and oil production, which are also beyond
the control of the managing general partner and the partnerships and cannot be
accurately predicted, are the following:

     o    the cost, proximity, availability, and capacity of pipelines and other
          transportation facilities;

     o    the price and availability of other energy sources such as coal,
          nuclear energy, solar and wind;

     o    the price and availability of alternative fuels, including when large
          consumers of natural gas are able to convert to alternative fuel use
          systems;

     o    local, state, and federal regulations regarding production,
          conservation, and transportation;

     o    overall domestic and global economic conditions;

     o    the impact of the U.S. dollar exchange rates on natural gas and oil
          prices;

     o    technological advances affecting energy consumption;

     o    domestic and foreign governmental relations, regulations and taxation;

     o    the impact of energy conservation efforts;

     o    the general level of supply and market demand for natural gas and oil
          on a regional, national and worldwide basis;

     o    weather conditions and fluctuating seasonal supply and demand for
          natural gas and oil because of various factors such as home heating
          requirements in the winter months, although seasonal anomalies such as
          mild

                                       81
winters or hot summers sometimes lessen this fluctuation, and certain
          natural gas users with natural gas storage facilities purchase a
          portion of the natural gas they anticipate they will need for the
          winter during the summer, which also can lessen seasonal demand
          fluctuations;

     o    economic and political instability, including war or terrorist acts in
          natural gas and oil producing countries, including those of the Middle
          East and South America;

     o    the amount of domestic production of natural gas and oil; and

     o    the amount and price of imports of natural gas and oil from foreign
          sources, including liquid natural gas from Canada and other countries
          (which the managing general partner believes becomes economic when
          natural gas prices are at or above $3.50 per mcf), and the actions of
          the members of the Organization of Petroleum Exporting Countries
          ("OPEC"), which include production quotas for petroleum products from
          time to time with the intent of increasing, maintaining, or decreasing
          price levels.

For example, the North American Free Trade Agreement ("NAFTA") eliminated trade
and investment barriers in the United States, Canada, and Mexico. From time to
time since then there have been increased imports of Canadian natural gas into
the United States. Without a corresponding increase in demand in the United
States, the imported natural gas would have an adverse effect on both the price
and volume of natural gas sales from the partnerships' wells.

The managing general partner is unable to predict what effect the various
factors set forth above will have on the future price of the natural gas and oil
sold from the partnerships' wells. According to the Annual Energy Outlook 2006
with Projections to 2030 published by the Energy Information Administration
(EIA), total natural gas consumption is projected to increase from 22.34
trillion cubic feet in 2003 to 26.86 trillion cubic feet by 2030. Over that same
period, total natural gas supplies are projected to grow by 4.08 trillion cubic
feet, with domestic natural gas production expected to account for 45% of the
total growth in gas supply, and net imports projected to account for the
remainder. Notwithstanding, wellhead natural gas prices are projected to decline
in the early years of the forecast as a result of the following responses to the
current high prices:

     o    an increase in drilling levels;

     o    the coming online of new natural gas production; and

     o    the increase in liquid natural gas ("LNG") imports.

After 2011, however, natural gas prices are projected to increase in response to
the higher exploration and development costs associated with smaller and deeper
natural gas deposits in the remaining domestic natural gas resource base. Also,
the managing general partner believes there have been several developments which
may increase the demand for natural gas, but may or may not be offset by an
increase in the supply of natural gas, which the managing general partner is
unable to predict. For example, the Clean Air Act Amendments of 1990 contain
incentives for the future development of "clean alternative fuel," which
includes natural gas and liquefied petroleum gas for "clean-fuel vehicles."
Also, the accelerating deregulation of electricity transmission has caused a
convergence between the natural gas and electric industries. In 2004, according
to information from the Energy Information Administration, the breakout of
energy sources for the generation of electricity in the United States was as
follows:

     o    natural gas fired power plants were used to produce approximately 18%;

     o    coal-fired power plants were used to produce approximately 50%;

     o    nuclear power plants were used to produce approximately 20%; and

     o    large scale hydroelectric projects were used to produce approximately
          7%.

                                       82
In recent years, the electricity industry has increased its use of natural gas
because of increased competition and the enforcement of stringent environmental
regulations. For example, the Environmental Protection Agency has sought to
enforce environmental regulations which increase the cost of operating
coal-fired power plants. According to the Energy Information Administration, the
demand for natural gas by producers of electricity is expected to increase
through the decade. Also, the last nuclear power plant to come online in the
United States was in June 1996, although the existing nuclear power plants have
increased their capacity and the recent energy act includes tax credits for
constructing new nuclear power plants. Unless the price of natural gas increases
to a point where it becomes uneconomic as an energy source as compared to
alternate energy sources, the managing general partner believes that natural gas
is the preferred fuel for many producers of electricity since many electricity
producers have begun moving away from dirtier-burning fuels, such as coal and
oil because of environmental compliance requirements. In this regard, some of
the new natural gas fired power plants which are coming into service are not
designed to allow for switching to other fuels.

STATE REGULATIONS

Natural gas and oil operations are regulated in Pennsylvania by the Department
of Environmental Resources and in Tennessee by the Department of Environment and
Conservation. Pennsylvania, Tennessee and the other states where each
partnership's wells may be situated impose a comprehensive statutory and
regulatory scheme for natural gas and oil operations, including supervising the
production activities and the transportation of natural gas sold in intrastate
markets, which creates additional financial and operational burdens. Among other
things, these regulations involve:

     o    new well permit and well registration requirements, procedures, and
          fees;

     o    landowner notification requirements;

     o    certain bonding or other security measures;

     o    minimum well spacing requirements;

     o    restrictions on well locations and underground gas storage;

     o    certain well site restoration, groundwater protection, and safety
          measures;

     o    discharge permits for drilling operations;

     o    various reporting requirements; and

     o    well plugging standards and procedures.

These state regulatory agencies also have broad regulatory and enforcement
powers including those associated with pollution and environmental control laws,
which are discussed below.

ENVIRONMENTAL REGULATION

Each partnership's drilling and producing operations will be subject to various
federal, state, and local laws covering the discharge of materials into the
environment, or otherwise relating to the protection of the environment. The
Environmental Protection Agency and state and local agencies will require the
partnerships to obtain permits and take other measures with respect to:

     o    the discharge of pollutants into navigable waters;

     o    disposal of wastewater; and

     o    air pollutant emissions.

                                       83
If these requirements or permits are violated there can be substantial civil and
criminal penalties that will increase if there was willful negligence or
misconduct. In addition, the partnerships may be subject to fines, penalties and
unlimited liability for cleanup costs under various federal laws such as the
Federal Clean Water Act, the Clean Air Act, the Resource Conservation and
Recovery Act, the Oil Pollution Act of 1990, the Toxic Substance Control Act and
the Comprehensive Environmental Response, Compensation and Liability Act of 1980
for oil and/or hazardous substance contamination or other pollution caused by a
partnership's drilling activities or its wells and its production activities.

Each partnership and its investor general partners may incur environmental costs
and liabilities due to the nature of the partnership's business and substances
from the partnership's wells as described "Risk Factors." For example, an
accidental release from one of a partnership's wells could subject the
partnership to substantial liabilities arising from environmental cleanup and
restoration costs, claims made by neighboring landowners and other third-parties
for personal injury and property damage, and fines or penalties for related
violations of environmental laws or regulations. Moreover, the possibility
exists that stricter laws, regulations or enforcement policies may be enacted or
adopted in the future which could significantly increase a partnership's
compliance costs and the cost of any remediation that may become necessary.

Also, a partnership's liability can extend to pollution costs that occurred on
the leases before they were acquired by the partnership. Although the managing
general partner will not transfer any lease to a partnership if it has actual
knowledge that there is an existing potential environmental liability on the
lease, there will not be an independent environmental audit of the leases before
they are transferred to a partnership. Thus, there is a risk that the leases
will have potential environmental liability even before drilling begins.

A partnership's required compliance with these environmental laws and
regulations may cause delays or increase the cost of the partnership's drilling
and producing activities. Because these laws and regulations are frequently
changed, the managing general partner is unable to predict the ultimate costs of
complying with present and future environmental laws and regulations. Also, the
managing general partner is unable to obtain insurance to protect against many
environmental claims, including remediation costs.

PROPOSED REGULATION

From time to time there are a number of proposals considered in Congress and in
the legislatures and agencies of various states that if enacted would
significantly and adversely affect the natural gas and oil industry and the
partnerships. The proposals involve, among other things:

     o    limiting the disposal of waste water from wells or the emission of
          greenhouse gases, which could substantially increase a partnership's
          operating costs and make the partnership's wells uneconomical to
          produce;

     o    changes in the federal income tax benefits for drilling natural gas
          and oil wells as discussed in "Federal Income Tax Consequences"; and

     o    tax credits and other incentives for the creation or expansion of
          alternative energy sources to natural gas and oil.

Also, Congress could re-enact price controls or additional taxes on natural gas
and oil in the future. However, it is impossible to accurately predict what
proposals, if any, will be enacted and their subsequent effect on a
partnership's activities.

                       PARTICIPATION IN COSTS AND REVENUES

IN GENERAL

The partnership agreement provides for the sharing of partnership costs and
revenues among the managing general partner and you and the other investors. A
tabular summary of the following discussion appears below. Each partnership will
be a separate business entity from the other partnerships, and you will be a
partner only in the partnership in which you invest. You will have no interest
in the business, assets, or tax benefits of the other partnership unless you
also invest in the other

                                       84
partnership. Thus, your investment return will depend solely on the operations
and success or lack of success of the particular partnership in which you
invest.

COSTS

1.   ORGANIZATION AND OFFERING COSTS. Organization and offering costs will be
     charged 100% to the managing general partner. However, the managing general
     partner will not receive any credit towards its required capital
     contribution or its revenue share for any organization and offering costs
     charged to it in excess of 15% of a partnership's subscription proceeds.

     o    Organization and offering costs generally means all costs of
          organizing and selling the offering and includes the dealer-manager
          fee, sales commissions and the up to .5% reimbursement for bona fide
          due diligence expenses.

          The managing general partner will pay a portion of a partnership's
          organization and offering costs to itself, its affiliates and
          independent third-parties and it will contribute the remainder to the
          partnership in the form of services related to organizing this
          offering. The managing general partner will receive a credit for these
          payments and services towards its required capital contribution in
          each partnership. The managing general partner's credit for its
          contribution of services for organization costs will be determined
          based on generally accepted accounting principles. The definition of
          organization and offering costs is set forth in the partnership
          agreement.

2.   LEASE COSTS. Each partnership's leases will be contributed to it by the
     managing general partner. The managing general partner will be credited
     with a capital contribution for each lease valued at:

     o    its cost; or

     o    fair market value if the managing general partner has reason to
          believe that cost is materially more than fair market value.

          The cost of the leases includes a portion of the managing general
          partner's reasonable, necessary and actual expenses for geological,
          geophysical, engineering, drafting, accounting, legal and other like
          services allocated to the leases in conformity with generally accepted
          accounting principles and industry standards. Also, the managing
          general partner has averaged the cost of all of its leases to arrive
          at the average lease cost per prospect set forth in "Compensation,"
          which the managing general partner believes is less than fair market
          value.

3.   INTANGIBLE DRILLING COSTS. Ninety percent of the subscription proceeds of
     you and the other investors in a partnership will be used to pay 100% of
     the intangible drilling costs incurred by that partnership in drilling and
     completing its wells.

     o    Intangible drilling costs generally means those costs of drilling and
          completing a well that are currently deductible, as compared with
          lease costs, which must be recovered through the depletion allowance,
          and equipment costs, which must be recovered through depreciation
          deductions.

     Although subscription proceeds of a partnership may be used to pay the
     costs of drilling different wells depending on when the subscriptions are
     received, 90% of the subscription proceeds of you and the other investors
     will be used to pay intangible drilling costs regardless of when you
     subscribe. Also, even if the IRS successfully challenged the managing
     general partner's characterization of a portion of these costs as
     deductible intangible drilling costs, and instead recharacterized the costs
     as some other item that may not be currently deductible, such as equipment
     costs and/or lease acquisition costs, this recharacterization by the IRS
     would have no effect on the allocation and payment of the costs by you and
     the other investors as intangible drilling costs under the partnership
     agreement.

                                       85
The allocation of each partnership's costs of drilling and completing its
     wells between intangible drilling costs, as defined in the partnership
     agreement, and equipment costs, as defined as "tangible costs" in the
     partnership agreement, will be made by the managing general partner, in its
     sole discretion, when the wells are drilled.

4.   EQUIPMENT COSTS. Ten percent of the subscription proceeds of you and the
     other investors in a partnership will be used to pay a portion of the
     equipment costs incurred by that partnership. All equipment costs of that
     partnership's wells that exceed 10% of the subscription proceeds of you and
     the other investors in the partnership will be charged to the managing
     general partner.

     o    Equipment costs generally means the costs of drilling and completing a
          well that are not currently deductible and are not lease costs.

5.   OPERATING COSTS, DIRECT COSTS, ADMINISTRATIVE COSTS AND ALL OTHER COSTS.
     Operating costs, direct costs, administrative costs, and all other
     partnership costs of your partnership not specifically charged under the
     partnership agreement will be charged between the managing general partner
     and you and the other investors in the partnership in the same ratio as the
     related production revenues are being credited.

     o    These costs generally include all costs of partnership administration
          and producing and maintaining the partnership's wells.

     Each well in a partnership will have a different productive life and when a
     well becomes uneconomic to produce, it will be plugged and abandoned. The
     costs of plugging and abandoning a well (other than those incurred in
     connection with drilling a nonproductive well) are shared between the
     managing general partner and you and the other investors in the same
     percentage as the related production revenues are being shared. For
     example, if the investors are receiving 68% of the partnership revenues and
     the managing general partner is receiving 32% of the partnership revenues,
     then the cost of plugging and abandoning the wells will be shared in the
     same percentages. Typically, the managing general partner will apply the
     salvage value of the equipment towards this obligation. The salvage value
     of the equipment will be shared between you and the other investors and the
     managing general partner based on the total amount of the actual equipment
     costs paid by each. Since the managing general partner in each partnership
     will have paid a majority of the partnership's total equipment costs, as
     compared to the total amount of the partnership's equipment costs paid by
     you and the other investors, it will also receive a majority of the salvage
     value of the equipment. See "Compensation - Drilling Contracts," for a
     discussion of the managing general partner's estimated equipment costs for
     an average partnership well in the primary drilling areas.

     To cover any shortfall that you and the other investors might incur between
     your share of the salvage value of the equipment in a well and your share
     of the plugging and abandoning costs of the well, the managing general
     partner has the right, beginning one year after each partnership well
     begins producing, to retain up to $200 per month of the partnership
     revenues in partnership reserves to cover future plugging and abandonment
     costs of the well. This $200 also includes the managing general partner's
     share of revenues, which will be used exclusively for the managing general
     partner's share of the plugging and abandonment costs of the well. To the
     extent any portion of those reserves ultimately is not required for the
     plugging and abandonment costs of the well, then it will be returned to the
     general operating revenues of the partnership.

6.   THE MANAGING GENERAL PARTNER'S REQUIRED CAPITAL CONTRIBUTION. The managing
     general partner's aggregate capital contributions to each partnership must
     not be less than 25% of all capital contributions to that partnership. This
     includes such items as the managing general partner's:

     o    credit for the cost of the leases it contributes to the partnership,
          or the fair market value of the leases if the managing general partner
          has a reason to believe that cost is materially more than fair market
          value;

                                       86
o    credit for the partnership's organization and offering costs paid or
          incurred by the managing general partner, including the costs of
          services contributed by the managing general partner to the
          partnership as organization costs; and

     o    share of the partnership's equipment costs paid by the managing
          general partner to itself as operator under the drilling and operating
          agreement.

The managing general partner's capital contributions must be paid or made at the
time the costs are required to be paid by the partnership, but in any event not
later than the end of the year immediately following the year in which the
partnership had its final closing.

REVENUES

Each partnership's production revenues from all of its wells will be commingled.
Thus, regardless of when you subscribe to a partnership you will share in the
production revenues from all of the partnership wells in that partnership on the
same basis as the other investors in the partnership in proportion to your
number of units.

1.   PROCEEDS FROM THE SALE OF LEASES. If a partnership well is sold, a portion
     of the sales proceeds will be allocated to the partners in the same
     proportion as their share of the adjusted tax basis of the property. In
     addition, proceeds will be allocated to the managing general partner to the
     extent of the pre-contribution appreciation in value of the property, if
     any. Any excess will be credited as provided in 4, below.

2.   INTEREST PROCEEDS. Interest income earned on your subscription proceeds
     before your partnership's final closing will be credited to your account
     and paid to you not later than the partnership's first cash distributions
     from operations. After your partnership's final closing and until the
     subscription proceeds are invested in your partnership's operations, any
     interest income from temporary investments will be allocated pro rata to
     you and the other investors providing the subscription proceeds. All other
     interest income, including interest earned on the deposit of production
     revenues, will be credited as provided in 4, below.

3.   EQUIPMENT PROCEEDS. Proceeds from the sale or other disposition of
     equipment will be credited to the parties charged with the costs of the
     equipment in the ratio in which the costs were charged.

4.   PRODUCTION REVENUES. Subject to the managing general partner's
     subordination obligation as described below, the managing general partner
     and you and the other investors in a partnership will share in all of that
     partnership's other revenues, including production revenues, in the same
     percentage as their respective capital contribution bears to the
     partnership's total capital contributions, except that the managing general
     partner will receive an additional 7% of that partnership's revenues.

     However, the managing general partner's total revenue share may not exceed
     40% of that partnership's revenues regardless of the amount of its capital
     contributions. For example, if the managing general partner contributes the
     minimum of 25% of the partnership's total capital contributions and the
     investors contribute 75% of the partnership's total capital contributions,
     then the managing general partner will receive 32% of the partnership
     revenues and the investors will receive 68% of the partnership revenues. On
     the other hand, if the managing general partner contributes 35% of the
     partnership's total capital contributions and the investors contribute 65%
     of the partnership's total capital contributions, then the managing general
     partner will receive 40% of the partnership revenues, not 42%, because its
     revenue share cannot exceed 40% of partnership revenues, and the investors
     will receive 60% of partnership revenues.

SUBORDINATION OF PORTION OF MANAGING GENERAL PARTNER'S NET REVENUE SHARE

Each partnership is structured to provide you and the other investors with cash
distributions equal to a minimum of 10% of capital, based on a subscription
price of $10,000 per unit, regardless of the actual subscription price you paid
for your units, in each of the first five 12-month periods beginning with that
partnership's first cash distributions from operations. To help achieve this
investment feature, the managing general

                                       87
partner will subordinate up to 50% of its share, as managing general partner, of
partnership net production revenues, which will be up to between 16% and 20% of
the total partnership net production revenues, depending on the amount of its
capital contributions, during this subordination period.

     o    Partnership net production revenues means gross revenues after
          deduction of the related operating costs, direct costs, administrative
          costs, and all other costs not specifically allocated.

Each partnership's 60-month subordination period will begin with that
partnership's first cash distribution from operations to you and the other
investors. Subordination distributions will be determined by debiting or
crediting current period partnership revenues to the managing general partner as
may be necessary to provide the distributions to you and the other investors. At
any time during the subordination period the managing general partner is
entitled to an additional share of partnership revenues to recoup previous
subordination distributions to the extent your cash distributions from that
partnership exceed the 10% return of capital described above. The specific
formula for determining subordination distributions is set forth in Section
5.01(b)(4)(a) of the partnership agreement.

The managing general partner anticipates that you will benefit from the
subordination if the price of natural gas and oil received by the partnership
and/or the results of the partnership's drilling activities, such as the volume
of natural gas and oil produced from the partnership's wells, are unable to
provide the required return of capital. However, if the wells produce small
natural gas and oil volumes or natural gas and oil prices decrease, then even
with subordination your cash flow may be very small and you may not receive the
10% return of capital for each of the first five years beginning with the
partnership's first cash distribution from operations.

As of September 15, 2006, the managing general partner was not subordinating any
of its partnership net production revenues in the 16 limited partnerships that
currently have the subordination feature in effect. Since 1993 the managing
general partner has had the same or a similar subordination feature in 34 of its
partnerships and from time to time it has subordinated its partnership net
production revenues in 16 of those partnerships. The managing general partner is
entitled to recoup those subordination distributions during the respective
subordination period of those previous partnerships to the extent cash
distributions of those previous partnerships to their respective investors would
exceed the specified return to the investors.

EXAMPLE OF NET REVENUE SHARING DURING A SUBORDINATION PERIOD.
NET REVENUES TO
                                                                           MAXIMUM AMOUNT OF             MANAGING GENERAL
                                                                            MANAGING GENERAL         PARTNER AND INVESTORS IF
                                   PERCENTAGE OF       PERCENTAGE OF       PARTNER'S SHARE OF            MAXIMUM AMOUNT OF
                                    PARTNERSHIP       PARTNERSHIP NET       PARTNERSHIP NET         MANAGING GENERAL PARTNER'S
                                      CAPITAL         REVENUES WITHOUT    REVENUES AVAILABLE         SHARE OF PARTNERSHIP NET
ENTITY                           CONTRIBUTIONS (1)   SUBORDINATION (1)   FOR SUBORDINATION (2)   REVENUES IS SUBORDINATED (1)(2)
------                           -----------------   -----------------   ---------------------   -------------------------------
Managing General Partner......          25%                 32%                   16%                          16%
Investors ....................          75%                 68%                                                84%
----------
(1)  These percentages are for illustration purposes only and assume the
     managing general partner's minimum required capital contribution of 25% to
     each partnership and capital contributions of 75% from you and the other
     investors. The actual percentages are likely to be different because they
     will be based on the actual capital contributions of the managing general
     partner and you and the other investors. However, the managing general
     partner's total revenue share may not exceed 40% of partnership revenues
     regardless of the amount of its capital contribution.

(2)  Each partnership is structured to provide you and the other investors with
     cash distributions equal to a minimum of 10% of capital, based on a
     subscription price of $10,000 per unit, regardless of the actual
     subscription price you paid for your units, in each of the first five
     12-month periods beginning with the partnership's first cash distributions
     from operations. To help achieve this investment feature of a 10% return of
     capital for each of the first five 12-month periods, the managing general
     partner will subordinate up to 50% of its share of partnership net
     production revenues, which will be up to between 16% and 20% of the total
     partnership net production revenues, depending on the amount of its capital
     contributions, during this subordination period.

                                       88
EXAMPLE OF NET REVENUE SHARING AFTER THE END OF A SUBORDINATION PERIOD.
NET REVENUES TO MANAGING
                                                                       MAXIMUM AMOUNT OF      GENERAL PARTNER AND
                                                                       MANAGING GENERAL     INVESTORS WHEN NONE OF
                                PERCENTAGE OF       PERCENTAGE OF     PARTNER'S SHARE OF       MANAGING GENERAL
                                 PARTNERSHIP       PARTNERSHIP NET      PARTNERSHIP NET       PARTNER'S SHARE OF
                                   CAPITAL         REVENUES WITHOUT   REVENUES AVAILABLE   PARTNERSHIP NET REVENUES
ENTITY                        CONTRIBUTIONS (1)   SUBORDINATION (1)    FOR SUBORDINATION      IS SUBORDINATED (1)
---------------------------   -----------------   -----------------   ------------------   ------------------------
Managing General Partner...          25%                 32%                  0%                      32%
Investors..................          75%                 68%                                          68%
----------
(1)  These percentages are for illustration purposes only and assume the
     managing general partner's minimum required capital contribution of 25% to
     each partnership and capital contributions of 75% from you and the other
     investors. The actual percentages are likely to be different because they
     will be based on the actual capital contributions of the managing general
     partner and you and the other investors. However, the managing general
     partner's total revenue share may not exceed 40% of partnership revenues
     regardless of the amount of its capital contribution.

TABLE OF PARTICIPATION IN COSTS AND REVENUES

The following table sets forth certain partnership costs and revenues charged
and credited between the managing general partner and you and the other
investors in each partnership, after deducting from the partnership's gross
revenues, the landowner royalties and any other lease burdens.

                                                       MANAGING
                                                        GENERAL
                                                        PARTNER   INVESTORS
                                                       --------   ---------
PARTNERSHIP COSTS
Organization and offering costs ....................        100%          0%
Lease costs ........................................        100%          0%
Intangible drilling costs (1) ......................          0%        100%
Equipment costs ....................................         (2)         (2)
Operating costs, administrative costs, direct costs,
   and all other costs .............................         (3)         (3)

PARTNERSHIP REVENUES
Interest income ....................................         (4)         (4)
Equipment proceeds .................................         (2)         (2)
All other revenues including production revenues ...      (5)(6)      (5)(6)

PARTICIPATION IN DEDUCTIONS AND CREDITS
Intangible drilling costs ..........................          0%        100%
Depreciation .......................................         (2)         (2)
Percentage depletion allowance .....................   (5)(6)(7)   (5)(6)(7)
Marginal well production credits ...................   (5)(6)(7)   (5)(6)(7)

----------
(1)  Ninety percent of the subscription proceeds of you and the other investors
     in a partnership will be used to pay 100% of the intangible drilling costs
     incurred by that partnership in drilling and completing its wells.

(2)  Ten percent of the subscription proceeds of you and the other investors in
     a partnership will be used to pay a portion of the equipment costs incurred
     by that partnership in drilling and completing its wells. All equipment
     costs in excess of 10% of that partnership's subscription proceeds will be
     paid by the managing general partner. Thus, the managing general partner
     will pay the majority of each partnership's equipment costs. Equipment
     proceeds, if any, will be credited in the same percentage in which the
     equipment costs were charged. Thus, the managing general partner will
     receive the majority of any equipment proceeds.

                                       89
(3)  These costs, which also include plugging and abandonment costs of the wells
     after the wells have been drilled, produced, and depleted, will be charged
     to the parties in the same ratio as the related production revenues are
     being credited.

(4)  Interest earned on your subscription proceeds before a partnership's final
     closing will be credited to your account and paid to you not later than the
     partnership's first cash distributions from operations. After the
     partnership's final closing and until the partnership's subscription
     proceeds are invested in its operations, any interest income from temporary
     investments will be allocated pro rata to the investors providing the
     subscription proceeds. All other interest income in the partnership,
     including interest earned on the deposit of operating revenues, will be
     credited as production revenues are credited.

(5)  In each partnership the managing general partner and you and the other
     investors will share in all of the partnership's other revenues in the same
     percentage that their respective capital contributions bear to the
     partnership's total capital contributions, except that the managing general
     partner will receive an additional 7% of the partnership revenues. However,
     the managing general partner's total revenue share in a partnership may not
     exceed 40% of partnership revenues.

(6)  If a portion of the managing general partner's partnership net production
     revenues is subordinated, then the actual allocation of partnership
     revenues between the managing general partner and you and the other
     investors will vary from the allocation described in (5) above.

(7)  The percentage depletion allowances and any marginal well production
     credits will be credited between the managing general partner and you and
     the other investors in the same percentages as the production revenues are
     being credited.

ALLOCATION AND ADJUSTMENT AMONG INVESTORS

The investors' share as a group of each partnership's revenues, gains, income,
costs, marginal well production credits, expenses, losses, and other charges and
liabilities generally will be charged and credited among you and the other
investors in that partnership in accordance with the ratio that your respective
number of units bears to the number of units held by all investors as a group in
that partnership, based on a subscription price of $10,000 per unit regardless
of the actual subscription price you paid for your units. These allocations will
take into account any investor general partner's status as a defaulting investor
general partner. Certain investors, however, will pay a discounted subscription
price for their units as described in "Plan of Distribution." Thus, intangible
drilling costs and the investors' share of the equipment costs of drilling and
completing the partnership's wells will be charged among you and the other
investors in a partnership as set forth above, except that these allocations
(i.e., intangible drilling costs and equipment costs) will be based on the
respective subscription amount paid by you and the other investors for your
respective units as set forth on your respective subscription agreements, rather
than a subscription price of $10,000 per unit for all of the units.

DISTRIBUTIONS

The managing general partner will review each partnership's accounts at least
monthly to determine whether cash distributions are appropriate and the amount
to be distributed, if any, taking into account its subordination obligation
discussed above in "- Subordination of Portion of Managing General Partner's Net
Revenue Share." Your partnership will distribute funds to you and the other
investors that the managing general partner, in its sole discretion, does not
believe are necessary for the partnership to retain. Distributions may be
reduced or deferred to the extent partnership revenues are used for any of the
following:

     o    repayment of partnership borrowings;

     o    cost overruns;

     o    remedial work to improve a well's producing capability;

     o    compensation and fees to the managing general partner as described in
          "Risk Factors - Risks Related to an Investment In a Partnership -
          Compensation and Fees to the Managing General Partner Regardless of
          Success of a Partnership's Activities Will Reduce Cash Distributions";

                                       90
o    direct costs and general and administrative expenses of the
          partnership;

     o    reserves, including a reserve for the estimated costs of eventually
          plugging and abandoning the wells; or

     o    indemnification of the managing general partner and its affiliates by
          the partnership for losses or liabilities incurred in connection with
          the partnership's activities.

Also, funds will not be advanced or borrowed by a partnership for the purpose of
making distributions to you and the other investors if the amount advanced or
borrowed would exceed the partnership's accrued and received revenues for the
previous four quarters, less paid and accrued operating costs with respect to
the revenues. Any cash distributions from a partnership to the managing general
partner will be made only in conjunction with distributions to you and the other
investors in that partnership and only out of funds properly allocated to the
managing general partner's account.

LIQUIDATION

Each partnership will continue for 50 years unless it is terminated earlier by a
final terminating event as described below, or an event which causes the
dissolution of a limited partnership under the Delaware Revised Uniform Limited
Partnership Act. However, if a partnership terminates on an event which causes a
dissolution of the partnership under state law and it is not a final terminating
event, then a successor limited partnership will automatically be formed. Thus,
only on a final terminating event will a partnership be liquidated. A final
terminating event is any of the following:

     o    the election to terminate the partnership by the managing general
          partner or the affirmative vote of investors whose units equal a
          majority of the total units;

     o    the termination of the partnership under Section 708(b)(1)(A) of the
          Internal Revenue Code because no part of its business is being carried
          on; or

     o    the partnership ceases to be a going concern.

On the partnership's liquidation you will receive your interest in the
partnership to which you subscribed. Generally, your interest in the partnership
means an undivided interest in the partnership's assets, after payments to the
partnership's creditors, in the ratio that your positive capital account bears
to the positive capital accounts of all of the partners in the partnership
(including the managing general partner) until all of the capital accounts have
been reduced to zero. Thereafter, your interest in the remaining partnership
assets will equal your interest in the related partnership revenues.

Any in-kind property distributions to you from the partnership in which you
invest must be made to a liquidating trust or similar entity, unless you
affirmatively consent to receive an in-kind property distribution after being
told the risks associated with the direct ownership of the property or unless
there are alternative arrangements in place which assure that you will not be
responsible for the operation or disposition of the partnership's properties. If
the managing general partner has not received your written consent to a proposed
in-kind property distribution within 30 days after it is mailed, then it will be
presumed that you have not consented. The managing general partner may then sell
the asset at the best price reasonably obtainable from an independent
third-party, or to itself or its affiliates at fair market value as determined
by an independent expert selected by the managing general partner. Also, if the
partnership is liquidated the managing general partner will be repaid any debts
owed to it by the partnership before there are any payments to you and the other
investors in that partnership.

                              CONFLICTS OF INTEREST

IN GENERAL

Conflicts of interest are inherent in natural gas and oil partnerships involving
non-industry investors because the transactions are entered into without arms'
length negotiation. Your interests and those of the managing general partner and
its affiliates may be inconsistent in some respects or in certain instances, and
the managing general partner's actions may not be the most advantageous to you.
The following discussion describes certain possible conflicts of interest that
may arise for the

                                       91
managing general partner and its affiliates in the course of each partnership.
For some of the conflicts of interest, but not all, there are certain
limitations on the managing general partner that are designed to reduce, but
will not eliminate, the conflicts. Other than these limitations the managing
general partner has no procedures to resolve a conflict of interest and under
the terms of the partnership agreement the managing general partner may resolve
the conflict of interest in its sole discretion and best interest.

Further, the managing general partner depends on its indirect parent company,
Atlas America and its affiliates, for management and administrative functions
and financing for capital expenditures. Neither the partnership agreement nor
any other agreement requires Atlas America to pursue a future business strategy
that favors the partnerships. Atlas America's directors and officers have a
fiduciary duty to make decisions in the best interests of the stockholders of
Atlas America. Because the managing general partner is allowed to take into
account the interests of parties other than the partnerships, such as Atlas
America and Atlas Energy Resources, LLC, in resolving partnership conflicts of
interest, this has the effect of limiting its fiduciary duty to the
partnerships.

The following discussion is materially complete; however, other transactions or
dealings may arise in the future that could result in conflicts of interest for
the managing general partner and its affiliates.

CONFLICTS REGARDING TRANSACTIONS WITH THE MANAGING GENERAL PARTNER AND ITS
AFFILIATES

Although the managing general partner believes that the compensation and
reimbursement that it and its affiliates will receive in connection with each
partnership are reasonable, the compensation has been determined solely by the
managing general partner and did not result from negotiations with any
unaffiliated third-party dealing at arms' length. The managing general partner
and its affiliates will receive compensation and reimbursement from each
partnership for their services in drilling, completing, and operating that
partnership's wells under the drilling and operating agreement and will receive
the other fees described in "Compensation" regardless of the success of that
partnership's wells. The managing general partner and its affiliates providing
the services or equipment can be expected to profit from the transactions, and
it is usually in the managing general partner's best interest to enter into
contracts with itself and its affiliates, rather than unaffiliated third-parties
even if the contract terms, skill, and experience, offered by the unaffiliated
third-parties are comparable.

When the managing general partner or any affiliate provides services or
equipment to a partnership the partnership agreement provides that their fees
must be competitive with the fees charged by unaffiliated third-parties in the
same geographic area engaged in similar businesses. Also, before the managing
general partner or any affiliate may receive competitive fees for providing
services or equipment to a partnership they must be engaged, independently of
the partnership and as an ordinary and ongoing business, in rendering the
services or selling or leasing the equipment and supplies to a substantial
extent to other persons in the natural gas and oil industry in addition to the
partnerships in which the managing general partner or an affiliate has an
interest. If the managing general partner or the affiliate is not engaged in
such a business, then the compensation must be the lesser of its cost or the
competitive rate that could be obtained in the area.

Any services not otherwise described in this prospectus or the partnership
agreement for which the managing general partner or an affiliate is to be
compensated by a partnership must be:

     o    set forth in a written contract that describes the services to be
          rendered and the compensation to be paid; and

     o    cancelable without penalty on 60 days written notice by investors
          whose units equal a majority of the total units.

The compensation paid by the partnership to the managing general partner or its
affiliates for additional services to the partnership under these contracts, if
any, will be reported to you in your partnership's annual and semiannual
reports, and a copy of the contract will be provided to you on request.

There is also a conflict of interest concerning the purchase price if the
managing general partner or an affiliate purchases a property from a
partnership, which they may do in certain limited circumstances as described in
"- Conflicts Involving the

                                       92
Acquisition of Leases - (6) Limitations on Sale of Undeveloped and Developed
Leases to the Managing General Partner," below.

CONFLICT REGARDING THE DRILLING AND OPERATING AGREEMENT

The managing general partner anticipates that all of the wells to be drilled by
each partnership will be drilled and operated under the drilling and operating
agreement. This creates a continuing conflict of interest because the managing
general partner must monitor and enforce, on behalf of each partnership, its own
compliance, as operator with the drilling and operating agreement and as
managing general partner with the partnership agreement, and the compliance of
its affiliate, Atlas Pipeline Partners, with the gas gathering agreement.

CONFLICTS REGARDING SHARING OF COSTS AND REVENUES

The managing general partner will receive a percentage of partnership revenues
that is greater than the percentage of partnership costs that it pays. This
sharing arrangement may create a conflict of interest between the managing
general partner and you and the other investors in a partnership concerning the
determination of which wells will be drilled by the partnership based on the
risk and profit potential associated with the wells.

In addition, the allocation of all of the intangible drilling costs to you and
the other investors and the majority of the equipment costs to the managing
general partner creates a conflict of interest between the managing general
partner and you and the other investors concerning whether to complete a well.
For example, the completion of a marginally productive well might prove
beneficial to you and the other investors, but not to the managing general
partner. When a completion decision is made, you and the other investors will
have already paid the majority of your costs so you will want to pay your share
of the additional costs to complete the well (i.e., 10% of the additional
equipment costs to complete the well) if there is a reasonable opportunity to
recoup your share of the completion costs plus any portion of the costs of the
well paid by you before the completion attempt.

On the other hand, the managing general partner will have paid only a portion of
its costs before this time, and it will want to pay its additional equipment
costs to complete the well only if it is reasonably certain of recouping its
share of the completion costs and making a profit. However, based on its past
experience the managing general partner anticipates that most of the wells in
the primary areas will have to be completed before it can determine the well's
productivity, which would eliminate this potential conflict of interest. In any
event, the managing general partner will not cause any well to be plugged and
abandoned without a completion attempt unless it makes the decision in
accordance with generally accepted oil and gas field practices in the geographic
area of the well location.

CONFLICTS REGARDING TAX MATTERS PARTNER

The managing general partner will serve as each partnership's tax matters
partner and represent the partnership before the IRS. The managing general
partner will have broad authority to act on behalf of you and the other
investors in the partnership in any administrative or judicial proceeding
involving the IRS, and this authority may involve conflicts of interest. For
example, potential conflicts include:

     o    whether or not to expend partnership funds to contest a proposed
          adjustment by the IRS, if any, that would decrease:

          o    the amount of a partnership's deduction for intangible drilling
               costs, which is allocated 100% to you and the other investors in
               the partnership; or

          o    the amount of the managing general partner's depreciation
               deductions, or the credit to its capital account for contributing
               the leases to a partnership which would also decrease the
               managing general partner's liquidation interest in the
               partnership; or

     o    the amount charged to a partnership by the managing general partner as
          reimbursement for expenses incurred by the managing general partner in
          its role as the tax matters partner.

                                       93
CONFLICTS REGARDING OTHER ACTIVITIES OF THE MANAGING GENERAL PARTNER, THE
OPERATOR AND THEIR AFFILIATES

The managing general partner will be required to devote to each partnership the
time and attention that it considers necessary for the proper management of the
partnership's activities. However, the managing general partner has sponsored
and continues to manage other natural gas and oil drilling partnerships, which
may be concurrent, and it will engage in unrelated business activities, either
for its own account or on behalf of other partnerships, joint ventures,
corporations, or other entities in which it has an interest. This creates a
continuing conflict of interest in allocating management time, services, and
other activities among the partnerships in this program and the managing general
partner's other activities.

The managing general partner will determine the allocation of its management
time, services, and other functions on an as-needed basis consistent with its
fiduciary duties among the partnerships in this program and its other
activities. However, the managing general partner depends on its indirect parent
company, Atlas America and its affiliates, for management and administrative
functions and financing for capital expenditures as described in "Management -
Transactions with Management and Affiliates." Thus, the competition for the time
and services of the managing general partner and its affiliates could result in
insufficient attention to the management and operation of the partnerships.

Subject to its fiduciary duties, the managing general partner will not be
restricted from participating in other businesses or activities, even if these
other businesses or activities compete with a partnership's activities and
operate in the same areas as a partnership. However, the managing general
partner and its affiliates may pursue business opportunities that are consistent
with a partnership's investment objectives for their own account only after they
have determined that the opportunity either:

     o    cannot be pursued by the partnership because of insufficient funds; or

     o    it is not appropriate for the partnership under the existing
          circumstances.

CONFLICTS INVOLVING THE ACQUISITION OF LEASES

The managing general partner will select, in its sole discretion, the wells to
be drilled by each partnership. Conflicts of interest may arise concerning which
wells will be drilled by each partnership in this program and which wells will
be drilled by the managing general partner's and its affiliates' other
affiliated partnerships or third-party programs in which they serve as
driller/operator. It may be in the managing general partner's or its affiliates'
advantage to have a partnership in this program bear the costs and risks of
drilling a particular well rather than another affiliate. These potential
conflicts of interest will be increased if the managing general partner
organizes and allocates wells to more than one partnership at a time. To lessen
this conflict of interest the managing general partner generally takes a similar
interest in the other partnerships when it serves as managing general partner
and/or driller/operator of the other partnerships. Also, as discussed in
"Proposed Activities," the managing general partner has a drilling commitment
with Knox Energy for the drilling of 300 wells, which creates a conflict of
interest in deciding whether the managing general partner will select wells for
each partnership to drill in the areas that will help the managing general
partner satisfy this drilling commitment.

When the managing general partner must provide prospects to two or more
partnerships at the same time it will attempt to treat each partnership fairly
on a basis consistent with:

     o    the funds available to the partnerships; and

     o    the time limitations on the investment of funds for the partnerships.

The partnership agreement gives the managing general partner the authority to
cause each partnership in this program to acquire undivided interests in natural
gas and oil properties, and to participate with other parties, including other
drilling programs previously or subsequently conducted by the managing general
partner or its affiliates, in the conduct of its drilling operations on those
properties. If conflicts between the interest of a partnership in this program
and other drilling partnerships do arise, then the managing general partner may
be unable to resolve those conflicts to the maximum advantage of a partnership
in this program because the managing general partner must deal fairly with the
investors in all of its drilling partnerships.

                                       94
In addition, subject to the restrictions set forth below, the managing general
partner decides which prospects and what interest in the prospects to transfer
to a partnership. This will result in a subsequent partnership sponsored by the
managing general partner benefiting from knowledge gained through a prior
partnership's drilling experience in an area and acquiring a prospect adjacent
to the prior partnership's prospect. In this regard, as drilling progresses,
reserves from newly completed wells are reclassified from the proved undeveloped
to the proved developed category and additional adjacent locations are added to
proved undeveloped reserves.

No procedures, other than the guidelines set forth below and in "- Procedures to
Reduce Conflicts of Interest," have been established by the managing general
partner to resolve any conflicts that may arise. The partnership agreement
provides that the managing general partner and its affiliates will abide by the
guidelines set forth below. However, with respect to (2), (3), (4), (5), (7) and
(9) there is an exception in the partnership agreement for another program in
which the interest of the managing general partner is substantially similar to
or less than its interest in the partnerships.

(1)  TRANSFERS AT COST. All leases will be acquired by each partnership from the
     managing general partner and credited towards its required capital
     contribution to the partnership at the cost of the lease, unless the
     managing general partner has a reason to believe that cost is materially
     more than the fair market value of the property. If the managing general
     partner believes that cost is materially more than fair market value, then
     the managing general partner's credit for the contribution must be at a
     price not in excess of the fair market value. (See "Participation in Costs
     and Revenues - Costs - Lease Costs.")

          o    A determination of fair market value must be supported by an
               appraisal from an independent expert and maintained in the
               partnership's records for at least six years.

(2)  EQUAL PROPORTIONATE INTEREST. When the managing general partner sells or
     transfers an oil and gas interest to a partnership, it must, at the same
     time, sell or transfer to the partnership an equal proportionate interest
     in all of its other property in the same prospect.

          o    The term "prospect" generally means an area which is believed to
               contain commercially productive quantities of natural gas or oil.

     However, a prospect will be limited to the drilling or spacing unit on
     which one well will be drilled if the following two conditions are met:

          o    the well is being drilled to a geological feature which contains
               proved reserves as defined below; and

          o    the drilling or spacing unit protects against drainage.

     The managing general partner believes that for a prospect located in the
     primary drilling areas as described in "Proposed Activities - Primary Areas
     of Operations," a prospect will consist of the drilling and spacing unit
     because it will meet the test in the preceding sentence.

          o    Proved reserves, generally, are the estimated quantities of
               natural gas and oil which have been demonstrated to be
               recoverable in future years with reasonable certainty under
               existing economic and operating conditions. Proved reserves
               include proved undeveloped reserves which generally are reserves
               expected to be recovered from existing wells where a relatively
               major expenditure is required for recompletion or from new wells
               on undrilled acreage. Reserves on undrilled acreage will be
               limited to those drilling units offsetting productive units that
               are reasonably certain of production when drilled. Proved
               Reserves for other undrilled units can be claimed only where it
               can be demonstrated with certainty that there is continuity of
               production from the existing productive formation.

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In the primary areas the managing general partner anticipates that the
     drilling of these wells by each partnership may provide the managing
     general partner with offset sites by allowing it to determine, at the
     partnership's expense, the value of adjacent acreage in which the
     partnership would not have any interest. The managing general partner owns
     acreage throughout the primary areas where each partnership's wells will be
     situated. To lessen this conflict of interest, for five years the managing
     general partner may not drill any well:

          o    to the Clinton/Medina geologic formation, if the well would be
               within 1,650 feet of an existing partnership well in Pennsylvania
               or within 1,000 feet of an existing partnership well in Ohio; or

          o    to the Mississippian/Upper Devonian Sandstone reservoirs in
               Fayette, Greene and Westmoreland Counties, Pennsylvania, if the
               well would be within at least 1,000 feet from a producing well,
               although a partnership may drill a new well or re-enter an
               existing well that is closer than 1,000 feet to a plugged and
               abandoned well.

     If a partnership abandons its interest in a well, then the restrictions
     described above will continue for one year following the abandonment. There
     are no similar prohibitions for a partnership's other primary drilling
     area, although the managing general partner believes that none of the
     prospects transferred to a partnership will result in drainage from the
     surrounding wells.

(3)  SUBSEQUENTLY ENLARGING PROSPECT. In areas where the prospect is not limited
     to the drilling or spacing unit and the area constituting a partnership's
     prospect is subsequently enlarged based on geological information, which is
     later acquired, then there is the following special provision:

          o    if the prospect is enlarged to cover any area where the managing
               general partner owns a separate property interest and the
               partnership activities were material in establishing the
               existence of proved undeveloped reserves which are attributable
               to the separate property interest, then the separate property
               interest or a portion thereof must be sold to the partnership in
               accordance with (1), (2) and (4).

(4)  TRANSFER OF LESS THAN THE MANAGING GENERAL PARTNER'S AND ITS AFFILIATES'
     ENTIRE INTEREST. If the managing general partner sells or transfers to a
     partnership less than all of its ownership in any prospect, then it must
     comply with the following conditions:

          o    the retained interest must be a proportionate working interest;

          o    the managing general partner's obligations and the partnership's
               obligations must be substantially the same after the sale of the
               interest by the managing general partner or its affiliates; and

          o    the managing general partner's revenue interest must not exceed
               the amount proportionate to its retained working interest.

     For example, if the managing general partner transfers 50% of its working
     interest in a prospect to a partnership and retains a 50% working interest,
     then the partnership will not pay any of the costs associated with the
     managing general partner's retained working interest as a part of the
     transfer. This limitation does not prevent the managing general partner and
     its affiliates from subsequently dealing with their retained working
     interest as they may choose with unaffiliated parties or affiliated
     partnerships. For example, the managing general partner may sell its
     retained working interest to a third-party for a profit.

(5)  LIMITATIONS ON ACTIVITIES OF THE MANAGING GENERAL PARTNER AND ITS
     AFFILIATES ON LEASES ACQUIRED BY A PARTNERSHIP. For a five year period
     after the final closing of a partnership, if the managing general partner
     proposes to acquire an interest from an unaffiliated person in a prospect
     in which the partnership owns an interest or in a

                                       96
prospect in which the partnership's interest has been terminated without
     compensation within one year before the proposed acquisition, then the
     following conditions apply:

          o    if the managing general partner does not currently own property
               in the prospect separately from the partnership, then the
               managing general partner may not buy an interest in the prospect;
               and

          o    if the managing general partner currently owns a proportionate
               interest in the prospect separately from the partnership, then
               the interest to be acquired must be divided in the same
               proportion between the managing general partner and the
               partnership as the other property in the prospect. However, if
               the partnership does not have the cash or financing to buy the
               additional interest, then the managing general partner is also
               prohibited from buying the additional interest.

(6)  LIMITATIONS ON SALE OF UNDEVELOPED AND DEVELOPED LEASES TO THE MANAGING
     GENERAL PARTNER. The managing general partner and its affiliates, other
     than an affiliated partnership as set forth in (7) below, may not purchase
     undeveloped leases or receive a farmout from a partnership other than at
     the higher of cost or fair market value. Farmouts to the managing general
     partner and its affiliates also must comply with the conditions set forth
     in (9) below.

     The managing general partner and its affiliates, other than an affiliated
     income program, may not purchase any producing natural gas or oil property
     from a partnership unless:

          o    the sale is in connection with the liquidation of the
               partnership; or

          o    the managing general partner's well supervision fees under the
               drilling and operating agreement for the well have exceeded the
               net revenues of the well, determined without regard to the
               managing general partner's well supervision fees for the well,
               for a period of at least three consecutive months.

     In both cases, the sale must be at fair market value supported by an
     appraisal of an independent expert selected by the managing general
     partner. The appraisal of the property must be maintained in the
     partnership's records for at least six years.

(7)  TRANSFER OF LEASES BETWEEN AFFILIATED LIMITED PARTNERSHIPS. The transfer of
     an undeveloped lease from a partnership to an affiliated drilling limited
     partnership must be made at fair market value if the undeveloped lease has
     been held by the partnership for more than two years. Otherwise, the
     transfer may be made at cost if the managing general partner deems it to be
     in the best interest of the partnership.

     An affiliated income program may purchase a producing natural gas and oil
     property from a partnership at any time at:

          o    fair market value as supported by an appraisal from an
               independent expert if the property has been held by the
               partnership for more than six months or there have been
               significant expenditures made in connection with the property; or

          o    cost as adjusted for intervening operations if the managing
               general partner deems it to be in the best interest of the
               partnership.

     However, these prohibitions do not apply to joint ventures or farmouts
     among affiliated partnerships, provided that:

          o    the respective obligations and revenue sharing of all parties to
               the transaction are substantially the same; and

                                       97
o    the compensation arrangement or any other interest or right of
               either the managing general partner or its affiliates is the same
               in each affiliated partnership or if different, the aggregate
               compensation of the managing general partner or the affiliate is
               reduced to reflect the lower compensation arrangement.

(8)  LEASES WILL BE ACQUIRED ONLY FOR STATED PURPOSE OF THE PARTNERSHIP. Each
     partnership must acquire only leases that are reasonably expected to meet
     the stated purposes of the partnership. Also, no leases may be acquired for
     the purpose of a subsequent sale, farmout or other disposition unless the
     acquisition is made after a well has been drilled to a depth sufficient to
     indicate that the acquisition would be in the partnership's best interest.

(9)  FARMOUT. The managing general partner may not assign the working interest
     in a prospect to a partnership for the purpose of a subsequent farmout,
     sale or other disposition, nor may the managing general partner enter into
     a farmout to avoid paying its share of the costs related to drilling a well
     on an undeveloped lease. However, the managing general partner's decision
     with respect to making a farmout and the terms of a farmout from a
     partnership involve conflicts of interest since the managing general
     partner may benefit from cost savings and reduction of its risk.

     The partnership may farmout an undeveloped lease or well activity to the
     managing general partner, its affiliates or an unaffiliated third-party
     only if the managing general partner, exercising the standard of a prudent
     operator, determines that:

          o    the partnership lacks the funds to complete the oil and gas
               operations on the lease or well and cannot obtain suitable
               financing;

          o    drilling on the lease or the intended well activity would
               concentrate excessive funds in one location, creating undue risks
               to the partnership;

          o    the leases or well activity have been downgraded by events
               occurring after assignment to the partnership so that development
               of the leases or well activity would not be desirable; or

          o    the best interests of the partnership would be served.

     If the partnership farmouts a lease or well activity, the managing general
     partner must retain on behalf of the partnership the economic interests and
     concessions as a reasonably prudent oil and gas operator would or could
     retain under the circumstances prevailing at the time, consistent with
     industry practices. However, if the farmout is made to the managing general
     partner or its affiliates there is a conflict of interest since the
     managing general partner will represent both the partnership and itself or
     an affiliate. Although the conflict of interest may be resolved to the
     managing general partner's benefit, the managing general partner must still
     retain on behalf of the partnership the economic interests and concessions
     as a reasonably prudent oil and gas operator would or could retain under
     the circumstances prevailing at the time, consistent with industry
     practices.

CONFLICTS REGARDING ORDER OF PIPELINE CONSTRUCTION AND GATHERING FEES

There are conflicts between you and the managing general partner and its
affiliates, because the managing general partner must monitor and enforce on
behalf of the partnerships the compliance of its affiliate, Atlas Pipeline
Partners, with the gas gathering agreement. Also, the managing general partner
may choose well locations for the partnerships that are situated near Atlas
Pipeline Partners' gathering system which would benefit the managing general
partner's indirect parent company, Atlas America, by providing more gathering
fees to Atlas Pipeline Partners, even if there are other well locations
available in the same area or other areas which offer the partnerships a greater
potential return. (See "Management - Organizational Diagrams and Security
Ownership of Beneficial Owners.") However, the managing general partner believes
this conflict of interest is substantially reduced because the managing general
partner expects to make the largest single capital contribution in each
partnership as explained in "Capitalization and Source of Funds and Use of
Proceeds."

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In addition, Atlas America or an affiliate will operate the Atlas Pipeline
Partners gathering system. Thus, the expansion of the Atlas Pipeline Partners
gathering system will be within the control of the managing general partner's
affiliate, which the managing general partner believes will attempt to expand
the Atlas Pipeline Partners gathering system to those areas with the greatest
number of wells with the greatest potential reserves. However, Atlas Pipeline
Holdings, L.P., a wholly-owned subsidiary of Atlas America, recently completed
an initial public offering of a minority interest in its units and, as a public
company, may be more susceptible to a change of control. (See "Risk Factors -
Risks Related to the Partnerships' Oil and Gas Operations - Adverse Events in
Marketing a Partnership's Natural Gas Could Reduce Partnership Distributions.")

Further, certain of the managing general partner's affiliates, including Atlas
America, are obligated through their agreement with Atlas Pipeline Partners to
pay the difference between the amount a partnership pays for gathering fees to
the managing general partner as set forth in "Compensation - Gathering Fees,"
and the greater of $.35 per mcf or 16% of the gross sales price for the natural
gas. This creates a conflict of interest between the managing general partner
and a partnership because the managing general partner has an economic incentive
to increase the amount of gathering fees paid by the partnership so as to reduce
the amount paid by Atlas America to Atlas Pipeline Partners, but any increase
cannot exceed a competitive rate. Further, if Atlas Pipeline Partners GP, LLC
were removed as general partner of Atlas Pipeline Partners without cause and
without its consent, this could create further pressure to increase the amount
of gathering fees required to be paid by a partnership for natural gas
transported through Atlas Pipeline Partners' gathering system. This could happen
because Atlas Pipeline Partners GP, LLC would no longer receive revenues from
Atlas Pipeline Partners, but Atlas America and its affiliates would still be
obligated to pay the difference between the amount of gathering fees set forth
in the master natural gas gathering agreement, as described above, and the
amount of gathering fees paid by a partnership, other than with respect to new
wells drilled by the partnership after the removal of Atlas Pipeline Partners
GP, LLC as general partner of Atlas Pipeline Partners, if any. Thus, the
managing general partner and its affiliates would have a further economic
incentive to increase the gathering fees. Any increase in the gathering fees
that a partnership pays would reduce your cash distributions from the
partnership. However, the gathering fees paid to the managing general partner
may not exceed competitive rates.

CONFLICTS BETWEEN INVESTORS AND THE MANAGING GENERAL PARTNER AS AN INVESTOR

The managing general partner, its officers, directors, and its affiliates may
subscribe for units in each partnership and the subscription price of their
units will be reduced by 10% as described in "Plan of Distribution." Even though
they pay a reduced price for their units, these investors generally will:

     o    share in the partnership's costs, revenues, and distributions on the
          same basis as the other investors as described in "Participation in
          Costs and Revenues"; and

     o    have the same voting rights, except as discussed below.

Any subscription for units by the managing general partner, its officers,
directors, or affiliates in the partnership in which you invest will dilute the
voting rights of you and the other investors and there may be a conflict with
respect to certain matters. The managing general partner and its officers,
directors and affiliates, however, are prohibited from voting with respect to
certain matters as described in "Summary of Partnership Agreement - Voting
Rights."

LACK OF INDEPENDENT UNDERWRITER AND DUE DILIGENCE INVESTIGATION

The terms of this offering, the partnership agreement, and the drilling and
operating agreement were determined by the managing general partner without
arms' length negotiations. You and the other investors have not been separately
represented by legal counsel, who might have negotiated more favorable terms for
you and the other investors in this offering and the agreements.

Also, there was not an extensive in-depth "due diligence" investigation of the
existing and proposed business activities of the partnerships and the managing
general partner that would be provided by independent underwriters. Although
Anthem Securities, which is affiliated with the managing general partner, serves
as dealer-manager of this offering and will receive reimbursement of bona fide
due diligence expenses for certain due diligence investigations conducted by the
selling agents, all of which will be reallowed by Anthem Securities to the
selling agents, its due diligence examination concerning this

                                       99
offering cannot be considered to be independent or as comprehensive as a due
diligence examination that would have been conducted by an independent
underwriter.

CONFLICTS CONCERNING LEGAL COUNSEL

The managing general partner anticipates that its legal counsel will also serve
as legal counsel to each partnership and that this dual representation will
continue in the future. However, if a future dispute arises between the managing
general partner and you and the other investors in a partnership, then the
managing general partner will cause you and the other investors to retain
separate counsel. Also, if counsel advises the managing general partner that
counsel reasonably believes its representation of a partnership will be
adversely affected by its responsibilities to the managing general partner, then
the managing general partner will cause you and the other investors in a
partnership to retain separate counsel.

CONFLICTS REGARDING PRESENTMENT FEATURE

You and the other investors in a partnership have the right to present your
units in the partnership to the managing general partner for purchase beginning
with the fifth calendar year after the end of the calendar year in which your
partnership closes. This creates the following conflicts of interest between you
and the managing general partner.

     o    The managing general partner may suspend the presentment feature if it
          does not have the necessary cash flow or it cannot borrow funds for
          this purpose on terms which it deems reasonable. Both of these
          determinations are subjective and will be made in the managing general
          partner's sole discretion.

     o    The managing general partner will also determine the purchase price
          based on a reserve report that it prepares and is reviewed by an
          independent expert that it chooses. The formula for arriving at the
          purchase price has many subjective determinations that are within the
          discretion of the managing general partner.

CONFLICTS REGARDING MANAGING GENERAL PARTNER WITHDRAWING OR ASSIGNING AN
INTEREST

A conflict of interest is created with you and the other investors by the
managing general partner's right to do any of the following:

     o    mortgage its managing general partner interest in each partnership;

     o    withdraw an interest in each partnership's wells equal to or less than
          its revenue interest to be used as collateral for a loan to the
          managing general partner; or

     o    assign, subject to the managing general partner's subordination
          obligation, its managing general partner interest in each partnership
          to its affiliates which also may mortgage the interests as collateral
          for their loans, if any.

If the managing general partner assigned a portion or all, of its managing
general partner interest in a partnership to an affiliate, the amount of
partnership net production revenues available to the managing general partner or
an affiliated assignee for their respective subordination obligations to you and
the other investors could be reduced or eliminated if there was a default under
a loan to the managing general partner or the affiliated assignee. Also, under
certain circumstances, if the managing general partner or an affiliated assignee
if a portion or all, of the managing general partner's managing general partner
interest in a partnership was assigned by the managing general partner to an
affiliate as discussed above, made a subordination distribution to you and the
other investors after a default to its lenders, then the lenders may be able to
recoup that subordination distribution from you and the other investors.

PROCEDURES TO REDUCE CONFLICTS OF INTEREST

In addition to the procedures set forth in "- Conflicts Involving the
Acquisition of Leases," the managing general partner and its affiliates will
comply with the following procedures in the partnership agreement to reduce some
of the conflicts of interest with you and the other investors. The managing
general partner does not have any other conflict of interest resolution
procedures. Thus, conflicts of interest between the managing general partner and
you and the other investors may

                                       100
not necessarily be resolved in your best interests. However, the managing
general partner believes that its significant capital contribution to each
partnership will reduce the conflicts of interest.

(1)  FAIR AND REASONABLE. The managing general partner may not sell, transfer,
     or convey any property to, or purchase any property from, a partnership
     except pursuant to transactions that are fair and reasonable; nor take any
     action with respect to the assets or property of a partnership which does
     not primarily benefit the partnership.

(2)  NO COMPENSATING BALANCES. The managing general partner may not use a
     partnership's funds as a compensating balance for its own benefit. Thus, a
     partnership's funds may not be used to satisfy any deposit requirements
     imposed by a bank or other financial institution on the managing general
     partner for its own corporate purposes.

(3)  FUTURE PRODUCTION. The managing general partner may not commit the future
     production of a partnership well exclusively for the managing general
     partner's own benefit.

(4)  DISCLOSURE. Any agreement or arrangement that binds a partnership must be
     fully disclosed in this prospectus.

(5)  NO LOANS FROM A PARTNERSHIP. A partnership may not loan money to the
     managing general partner.

(6)  NO REBATES. The managing general partner may not participate in any
     business arrangements which would circumvent these guidelines including
     receiving rebates or give-ups.

(7)  SALE OF ASSETS. The sale of all or substantially all of the assets of a
     partnership may only be made with the consent of investors whose units
     equal a majority of the total units.

(8)  PARTICIPATION IN OTHER PARTNERSHIPS. If a partnership participates in other
     partnerships or joint ventures, then the terms of the arrangements must not
     circumvent any of the requirements contained in the partnership agreement,
     including the following:

     o    there may be no duplication or increase in organization and offering
          expenses, the managing general partner's compensation, partnership
          expenses, or other fees and costs;

     o    there may be no substantive change in the fiduciary and contractual
          relationship between the managing general partner and you and the
          other investors; and

     o    there may be no diminishment in your voting rights.

(9)  INVESTMENTS. A partnership's funds may not be invested in the securities of
     another person except in the following instances:

     o    investments in working interests made in the ordinary course of the
          partnership's business;

     o    temporary investments in income producing short-term highly liquid
          investments, in which there is appropriate safety of principal, such
          as U.S. Treasury Bills;

     o    multi-tier arrangements meeting the requirements of (8) above;

     o    investments involving less than 5% of the total subscription proceeds
          of the partnership that are a necessary and incidental part of a
          property acquisition transaction; and

     o    investments in entities established solely to limit the partnership's
          liabilities associated with the ownership or operation of property or
          equipment, provided that duplicative fees and expenses are prohibited.

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(10) SAFEKEEPING OF FUNDS. The managing general partner may not employ, or
     permit another to employ, the funds or assets of a partnership in any
     manner except for the exclusive benefit of the partnership. The managing
     general partner has a fiduciary responsibility for the safekeeping and use
     of all funds and assets of each partnership whether or not in the managing
     general partner's possession or control.

(11) ADVANCE PAYMENTS. Advance payments by each partnership to the managing
     general partner and its affiliates are prohibited except when advance
     payments are required to secure the tax benefits of prepaid intangible
     drilling costs and for a business purpose.

POLICY REGARDING ROLL-UPS

It is possible at some indeterminate time in the future that each partnership
may become involved in a roll-up. In general, a roll-up means a transaction
involving the acquisition, merger, conversion, or consolidation of a partnership
with or into another partnership, corporation or other entity, and the issuance
of securities by the roll-up entity to you and the other investors. A roll-up
will also include any change in the rights, preferences, and privileges of you
and the other investors in the partnership. These changes could include the
following:

     o    increasing the compensation of the managing general partner;

     o    amending your voting rights;

     o    listing the units on a national securities exchange or on NASDAQ;

     o    changing the partnership's fundamental investment objectives; or

     o    materially altering the partnership's duration.

If a roll-up should occur in the future, the partnership agreement provides
various policies which include the following:

     o    an independent expert must appraise all partnership assets as
          discussed in Section 4.03(d)(16)(a) of the partnership agreement, and
          you must receive a summary of the appraisal in connection with a
          proposed roll-up;

     o    if you vote "no" on the roll-up proposal, then you will be offered a
          choice of:

          o    accepting the securities of the roll-up entity; or

          o    one of the following:

               o    remaining a partner in the partnership and preserving your
                    units in the partnership on the same terms and conditions as
                    existed previously; or

               o    receiving cash in an amount equal to your pro-rata share of
                    the appraised value of the partnership's net assets; and

     o    the partnership will not participate in a proposed roll-up:

          o    unless approved by investors whose units equal 66% of the total
               units;

          o    which would result in the diminishment of your voting rights
               under the roll-up entity's chartering agreement;

          o    which includes provisions which would operate to materially
               impede or frustrate the accumulation of shares by you of the
               securities of the roll-up entity;

                                       102
o    in which your right of access to the records of the roll-up
               entity would be less than those provided by the partnership
               agreement; or

          o    in which any of the transaction costs would be borne by the
               partnership if the proposed roll-up is not approved by investors
               whose units equal 66% of the total units.

            FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER

IN GENERAL

The managing general partner will manage your partnership and its assets. In
conducting your partnership's affairs the managing general partner is
accountable to you as a fiduciary, which under Delaware law generally means that
the managing general partner must exercise due care and deal fairly with you and
the other investors. Neither the partnership agreement nor any other agreement
between the managing general partner and each partnership may contractually
limit any fiduciary duty owed to you and the other investors by the managing
general partner under applicable law except as set forth in Sections 4.01, 4.02,
4.03, 4.04, 4.05, and 4.06 of the partnership agreement. See "Conflicts of
Interest - In General" regarding the managing general partner's dependence on
its indirect parent company, Atlas America and its affiliates, for management
and administrative functions and financing for capital expenditures and
"Management - Organizational Diagrams and Security Ownership of Beneficial
Owners - Pro Forma Organizational Diagram (Subject to Change)" regarding Atlas
Energy Resources, LLC. In this regard, the partnership agreement does permit the
managing general partner and its affiliates to:

     o    have business interests or activities that may conflict with the
          partnerships if they determine that the business opportunity either:

          o    cannot be pursued by the partnership because of insufficient
               funds; or

          o    it is not appropriate for the partnership under the existing
               circumstances;

     o    devote only so much of their time as is necessary to manage the
          affairs of each partnership, as determined by the managing general
          partner in its sole discretion;

     o    conduct business with the partnerships in a capacity other than as
          managing general partner or sponsor as described in Sections 4.01,
          4.02, 4.03, 4.04, 4.05 and 4.06 of the partnership agreement;

     o    manage multiple programs simultaneously; and

     o    be indemnified and held harmless as described below in "- Limitations
          on Managing General Partner Liability as Fiduciary."

The fiduciary duty owed by the managing general partner to the partnership is
analogous to the fiduciary duty owed by directors to a corporation and its
stockholders, which is commonly referred to as the "business judgment rule."
This rule provides that directors are not liable for mistakes made in the good
faith exercise of honest business judgment or for losses incurred in the good
faith performance of their duties when performed with such care as an ordinarily
prudent person would use.

If the managing general partner breaches its fiduciary responsibilities, then
you are entitled to an accounting and the recovery of any economic loss caused
by the breach. The Delaware Revised Uniform Limited Partnership Act provides
that a limited partner may institute legal action (a "derivative" action) on a
partnership's behalf to recover damages from a third-party when the managing
general partner refuses to institute the action or where an effort to cause the
managing general partner to do so is not likely to succeed. In addition, the
statutory or case law may permit a limited partner to institute legal action on
behalf of himself and all other similarly situated limited partners (a "class
action") to recover damages from the managing general partner for violations of
its fiduciary duties to the limited partners. This is a rapidly expanding and
changing area of the law, and if you have questions concerning the managing
general partner's duties you are urged to consult your own counsel.

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LIMITATIONS ON MANAGING GENERAL PARTNER LIABILITY AS FIDUCIARY

Under the terms of the partnership agreement the managing general partner, the
operator, and their affiliates have limited their liability to each partnership
and to you and the other investors for any loss suffered by your partnership or
you and the other investors in the partnership which arises out of any action or
inaction on their part if:

     o    they determined in good faith that the course of conduct was in the
          best interest of the partnership;

     o    they were acting on behalf of, or performing services for, the
          partnership; and

     o    their course of conduct did not constitute negligence or misconduct.

In addition, the partnership agreement provides for indemnification of the
managing general partner, the operator, and their affiliates by each partnership
against any losses, judgments, liabilities, expenses, and amounts paid in
settlement of any claims sustained by them in connection with that partnership
provided that they meet the standards set forth above. However, there is a more
restrictive standard for indemnification for losses arising from or out of an
alleged violation of federal or state securities laws. Also, to the extent that
any indemnification provision in the partnership agreement purports to include
indemnification for liabilities arising under the Securities Act of 1933, as
amended, you should be aware that in the SEC's opinion this indemnification
provision would be contrary to public policy and therefore unenforceable.

Payments to the managing general partner or its affiliates arising from the
indemnification or agreement to hold harmless provisions of the partnership
agreement are recoverable only out of the partnership's tangible net assets,
which include its revenues and any insurance proceeds from the types of
insurance for which the managing general partner, the operator and their
affiliates may be indemnified under the partnership agreement. Still, the use of
partnership funds or assets to indemnify the managing general partner, the
operator, or an affiliate would reduce amounts available for partnership
operations or for distribution to you and the other investors.

A partnership may not pay the cost of the portion of any insurance that insures
the managing general partner, the operator, or an affiliate against any
liability for which they cannot be indemnified. However, a partnership's funds
can be advanced to them for legal expenses and other costs incurred in any legal
action for which indemnification is being sought if the partnership has adequate
funds available and certain conditions in the partnership agreement are met.

The effect of the foregoing provisions and the business judgment rule may be to
limit your recourse against the managing general partner.

                         FEDERAL INCOME TAX CONSEQUENCES

INTRODUCTION

Because no advance ruling on any federal tax issue of an investment in a
partnership will be requested from the IRS, the IRS could disagree with the tax
position taken by the partnerships. However, the managing general partner has
obtained a tax opinion letter from Kunzman & Bollinger, Inc., special counsel
for this offering, with respect to the material and any significant federal
income tax issues involving an investment in a partnership by a "typical
investor" as that term is defined in "- Managing General Partner's
Representations," below. You are urged to read the entire tax opinion letter,
which has been filed as Exhibit 8 to the registration statement of which this
prospectus is a part. (See "Additional Information," for information on how to
obtain a copy of special counsel's tax opinion letter.)

Although special counsel's tax opinions express what it believes a court would
probably conclude if presented with the applicable federal tax issues, special
counsel's tax opinions are only predictions, and are not guarantees, of the
outcome of the particular tax issues being addressed. The IRS could challenge
special counsel's tax opinions, and the challenge could be sustained in the
courts if litigated and cause adverse tax consequences to you and your
partnership's other investors. Special counsel's tax opinions are based in part
on representations and statements made by the managing general partner in the
tax opinion letter and in this prospectus, including forward looking statements
relating to the partnership and its proposed activities. (See "Forward Looking
Statements and Associated Risks.")

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DISCLOSURES IN TAX OPINION LETTER

The following disclosures are made in special counsel's tax opinion letter.

     o    THE TAX OPINION LETTER WAS WRITTEN TO SUPPORT THE PROMOTION OR
          MARKETING OF UNITS IN THE PARTNERSHIPS TO POTENTIAL INVESTORS, AND
          SPECIAL COUNSEL TO THE PARTNERSHIPS HAS HELPED THE MANAGING GENERAL
          PARTNER ORGANIZE AND DOCUMENT THE OFFERING OF UNITS IN THE
          PARTNERSHIPS.

     o    THE TAX OPINION LETTER IS NOT CONFIDENTIAL. THERE ARE NO LIMITATIONS
          ON THE DISCLOSURE BY ANY POTENTIAL INVESTOR IN A PARTNERSHIP TO ANY
          OTHER PERSON OF THE TAX TREATMENT OR TAX STRUCTURE OF THE
          PARTNERSHIPS.

     o    INVESTORS IN A PARTNERSHIP HAVE NO CONTRACTUAL PROTECTION AGAINST THE
          POSSIBILITY THAT A PORTION OR ALL OF THEIR INTENDED TAX BENEFITS FROM
          AN INVESTMENT IN THE PARTNERSHIP ULTIMATELY ARE NOT SUSTAINED IF
          CHALLENGED BY THE IRS. (SEE "RISK FACTORS - TAX RISKS - YOUR TAX
          BENEFITS FROM AN INVESTMENT IN A PARTNERSHIP ARE NOT CONTRACTUALLY
          PROTECTED.")

     o    EACH POTENTIAL INVESTOR IN A PARTNERSHIP IS URGED TO SEEK ADVICE BASED
          ON HIS PARTICULAR CIRCUMSTANCES FROM AN INDEPENDENT TAX ADVISOR WITH
          RESPECT TO THE FEDERAL TAX CONSEQUENCES TO HIM OF AN INVESTMENT IN A
          PARTNERSHIP.

SPECIAL COUNSEL'S ASSUMPTIONS

Set forth below is a synopsis of the principal assumptions made by special
counsel in giving its federal income tax opinions.

     o    You will not borrow money to buy units in a partnership from any other
          investor in the partnership.

     o    You will be personally liable to repay any money you borrow to buy
          units in a partnership.

     o    You will not protect yourself through nonrecourse financing,
          guarantees, stop loss agreements or other similar arrangements from
          losing the money you invest in a partnership.

MANAGING GENERAL PARTNER'S REPRESENTATIONS

In giving its opinions, special counsel relied in part on representations from
the managing general partner set forth in the tax opinion letter, including the
principal representations summarized below.

     o    A "typical investor" in each partnership will be a natural person who
          purchases units in this offering and is a U.S. citizen.

     o    The investor general partner units in each partnership will be
          converted by the managing general partner to limited partner units
          after all of the wells in that partnership have been drilled and
          completed. (See "Actions to be Taken by Managing General Partner to
          Reduce Risks of Additional Payments by Investor General Partners."

     o    Each partnership will elect to currently deduct all of the intangible
          drilling costs of all of its wells.

     o    The managing general partner anticipates that all of each
          partnership's subscription proceeds will be expended in 2007, and you
          will include your share of your partnership's deduction for intangible
          drilling costs on your individual federal income tax return for 2007,
          subject to your right to elect to capitalize and amortize over a
          60-month period a portion or all of your share of your partnership's
          deduction for intangible drilling costs.

                                       105
o    Each partnership may have its final closing as late in the year as
          December 31, 2007. Thus, depending primarily on when its subscription
          proceeds are received, each partnership may prepay in 2007 most, if
          not all, of its intangible drilling costs for wells the drilling of
          which will not begin until 2008.

     o    Each partnership will have a calendar year taxable year.

     o    The managing general partner anticipates that most, if not all, of
          each partnership's natural gas and oil production from its productive
          wells will be marginal production that will qualify for the
          potentially higher rates of percentage depletion and potentially
          available marginal well production credits depending primarily on the
          applicable reference prices for natural gas and oil, which may vary
          from year to year.

     o    The principal purpose of each partnership is to locate, produce and
          market natural gas and oil on a profitable basis to its investors,
          apart from tax benefits, as discussed in this prospectus.

     o    Each partnership's total abandonment losses under Section 165 of the
          Code, which could include, for example, abandonment losses incurred by
          a partnership for wells drilled which are nonproductive (i.e. a "dry
          hole"), and abandonment losses incurred by a partnership for
          productive wells which have been operated until their commercial
          natural gas and oil reserves have been depleted, will be less than $2
          million, in the aggregate, in any taxable year of each partnership and
          less than $4 million, in the aggregate, during each partnership's
          first six taxable years.

Additional details, assumptions of special counsel, representations of the
managing general partner, and other matters affecting special counsel's opinions
are contained in special counsel's tax opinion letter. You are urged to read the
entire tax opinion letter, which is attached as Exhibit 8 to the Registration
Statement of which this prospectus is a part, to assist your understanding of
the federal tax benefits and risks of an investment in a partnership.

SPECIAL COUNSEL'S OPINIONS

Taxpayers bear the burden of proof to support claimed deductions and tax
credits, and special counsel's tax opinions are not binding on the IRS or the
courts. Special counsel's tax opinions with respect to an investment in a
partnership by a typical investor, who is sometimes referred to in special
counsel's opinions as a "Participant," "Investor General Partner" or "Limited
Partner," are set forth below.

     (1)  PARTNERSHIP CLASSIFICATION. Each Partnership will be classified as a
          partnership for federal income tax purposes, and not as a corporation.

     (2)  LIMITATIONS ON PASSIVE ACTIVITY LOSSES AND CREDITS. The passive
          activity limitations on losses and credits under Section 469 of the
          Code will apply to:

          o    the initial Limited Partners in a Partnership; and

          o    will not apply to the Investor General Partners in a Partnership
               until after their Investor General Partner Units are converted to
               Limited Partner Units.

     (3)  NOT A PUBLICLY TRADED PARTNERSHIP. Neither Partnership will be treated
          as a publicly traded partnership under the Code.

     (4)  BUSINESS EXPENSES. Business expenses, including payments for personal
          services actually rendered in the taxable year in which accrued by a
          Partnership, which are reasonable, ordinary and necessary and do not
          include amounts for items such as Lease acquisition costs, Tangible
          Costs, Organization and Offering Costs and other items that are
          required to be capitalized under the Code, are currently deductible by
          each Partnership.

                                       106
o    POTENTIAL LIMITATIONS ON DEDUCTIONS. A Participant's ability in any
          taxable year to use his share of these deductions of the Partnership
          in which he invests on his individual federal income tax returns may
          be reduced, eliminated or deferred by the following limitations:

          o    the Participant's personal tax situation, such as the amount of
               his regular taxable income, alternative minimum taxable income,
               losses, itemized deductions, personal exemptions, etc., which are
               not related to his investment in a Partnership;

          o    the amount of the Participant's adjusted basis in his Units at
               the end of the Partnership's taxable year;

          o    the amount of the Participant's "at risk" amount in the
               Partnership in which he invests at the end of the Partnership's
               taxable year; and

          o    the passive activity limitations on losses, and credits, if any,
               of the Partnership in which they invest in the case of Limited
               Partners (including Investor General Partners after their Units
               are converted to Limited Partner Units) who are natural persons
               or are entities that also are subject to the passive activity
               limitations on losses and credits under Section 469 of the Code.

(5)  INTANGIBLE DRILLING COSTS. Although each Partnership will elect to deduct
     currently all of its Intangible Drilling Costs, each Participant in a
     Partnership may still elect to capitalize and deduct all or part of his
     share of his Partnership's Intangible Drilling Costs (which do not include
     drilling and completion costs of a re-entry well that are not related to
     deepening the well, if any) ratably over a 60-month period. Subject to the
     foregoing, Intangible Drilling Costs paid by a Partnership under the terms
     of bona fide drilling contracts for the Partnership's wells will be
     deductible by Participants in that Partnership who elect to currently
     deduct their share of their Partnership's Intangible Drilling Costs in the
     taxable year in which the payments are made and the drilling services are
     rendered.

     A Participant's ability in any taxable year to use his share of these
     Partnership deductions on his personal federal income tax returns may be
     reduced, eliminated or deferred by the "Potential Limitations on
     Deductions" set forth in opinion (4) above.

(6)  PREPAID INTANGIBLE DRILLING COSTS. Subject to each Participant's election
     to capitalize and amortize a portion or all of his share of his
     Partnership's Intangible Drilling Costs as set forth in opinion (5) above,
     any prepayments of Intangible Drilling Costs by a Partnership in 2007 for
     wells the drilling of which will begin after December 31, 2007, but on or
     before March 30, 2008, will be deductible by the Participants in 2007.

     A Participant's ability in any taxable year to use his share of these
     Partnership deductions on his personal federal income tax returns may be
     reduced, eliminated or deferred by the "Potential Limitations on
     Deductions" set forth in opinion (4) above.

(7)  DEPLETION ALLOWANCE. The greater of the cost depletion allowance or the
     percentage depletion allowance will be available to qualified Participants
     as a current deduction against their share of their Partnership's gross
     income from the sale of natural gas and oil production in each taxable
     year, subject to the following restrictions:

     o    a Participant's cost depletion allowance cannot exceed his adjusted
          tax basis in the natural gas or oil property to which it relates; and

     o    a Participant's percentage depletion allowance:

                                       107
o    may not exceed 100% of his taxable income from each natural gas
               and oil property before the deduction for depletion; and

          o    is limited to 65% of his taxable income for the year computed
               without regard to percentage depletion, net operating loss
               carry-backs and capital loss carry-backs and, in the case of a
               Participant that is a trust, any distributions to its
               beneficiaries.

(8)  MACRS. Each Partnership's reasonable Tangible Costs for equipment placed in
     its productive wells that cannot be deducted immediately will be eligible
     for cost recovery deductions under the Modified Accelerated Cost Recovery
     System ("MACRS") over a seven year "cost recovery period" on a well-by-well
     basis, beginning in the taxable year each well is drilled, completed and
     made capable of production, i.e. placed in service.

     A Participant's ability in any taxable year to use his share of these
     Partnership deductions on his personal federal income tax returns may be
     reduced, eliminated or deferred by the "Potential Limitations on
     Deductions" set forth in opinion (4), above.

(9)  TAX BASIS OF UNITS. Each Participant's initial adjusted tax basis in his
     Units will be the amount of money that he paid for his Units.

(10) AT RISK LIMITATION ON LOSSES. Each Participant's initial "at risk" amount
     in the Partnership in which he invests will be the amount of money that he
     paid for his Units.

(11) ALLOCATIONS. The allocations of income, gain, loss, deduction, and credit,
     or items thereof, and distributions set forth in the Partnership Agreement
     for each Partnership, including the allocations of basis and amount
     realized with respect to a Partnership's natural gas and oil properties,
     will govern each Participant's allocable share of those items to the extent
     the allocations do not cause or increase a deficit balance in his Capital
     Account in the Partnership in which he invests.

(12) SUBSCRIPTION. No gain or loss will be recognized by the Participants on
     payment of their subscriptions to the Partnership in which they invest.

(13) PROFIT MOTIVE, IRS ANTI-ABUSE RULE AND POTENTIALLY RELEVANT JUDICIAL
     DOCTRINES. The Partnerships will possess the requisite profit motive under
     Section 183 of the Code. Also, the IRS anti-abuse rule in Treas. Reg.
     Section 1.701-2 and potentially relevant judicial doctrines will not have a
     material adverse effect on the tax consequences of an investment in a
     Partnership by a Participant as described in our opinions.

(14) REPORTABLE TRANSACTIONS. Neither Partnership is, nor should be in the
     future, a reportable transactions under Section 6707A(c) of the Code.

(15) OVERALL CONCLUSION. Special counsel's overall conclusion is that the
     federal tax treatment of a typical Participant's investment in a
     Partnership as set forth in its opinions above is the proper federal tax
     treatment and will be upheld on the merits if challenged by the IRS and
     litigated. Special counsel's evaluation of the federal income tax laws and
     the expected activities of the Partnerships as represented to it by the
     Managing General Partner in the tax opinion letter and as described in the
     Prospectus causes it to believe that the deduction by a typical Participant
     of all, or substantially all, of his allocable share of his Partnership's
     Intangible Drilling Costs in 2007 (even if the drilling of most or all of
     his Partnership's wells begins after December 31, 2007, but on or before
     March 30, 2008), as set forth in opinions (5) and (6) above, is the
     principal tax benefit offered by each Partnership to its potential
     Participants and also is the proper federal tax treatment, subject to each
     Participant's election to capitalize and amortize a portion or all of his
     share of his Partnership's deduction for Intangible Drilling Costs as
     discussed in "- Alternative Minimum Tax" in "Discussion of Federal Income
     Tax Consequences," below.

                                       108
A Participant's ability in any taxable year to use his share of these
          Partnership deductions on his personal federal income tax returns may
          be reduced, eliminated or deferred by the "Potential Limitations on
          Deductions" set forth in opinion (4), above.

          The discussion in the Prospectus under the caption "FEDERAL INCOME TAX
          CONSEQUENCES," insofar as it contains statements of federal income tax
          law, is correct in all material respects.

                  DISCUSSION OF FEDERAL INCOME TAX CONSEQUENCES

INTRODUCTION

Special counsel's tax opinions are limited to those set forth above. The
following is a discussion of all material federal income tax issues or
consequences, and any significant federal tax issues, related to the purchase,
ownership and disposition of a partnership's units that will apply to typical
investors in each partnership. Except as otherwise noted below, however,
different tax consequences from those discussed below may apply to foreign
persons, corporations, partnerships, trusts and other prospective investors that
are not treated as typical investors for federal income tax purposes. Also, the
proper treatment of a partnership's tax attributes by a typical investor on his
individual federal income tax returns may vary from that of another typical
investor. This is because the practical utility of the tax aspects of any
investment depends largely on each investor's particular income tax position in
the year in which items of income, gain, loss, deduction, or credit, if any, are
properly taken into account in computing his federal income tax liability. In
addition, the IRS may challenge the deductions, and credits, if any, claimed by
a partnership or you and the other investors in a partnership, or the taxable
year in which the deductions, and credits, if any, are claimed, and it is
possible that the challenge would be upheld if litigated. Accordingly, you are
urged to seek advice based on your particular circumstances from an independent
tax advisor in evaluating the potential tax consequences to you of an investment
in a partnership.

PARTNERSHIP CLASSIFICATION

For federal income tax purposes a partnership is not a taxable entity. Thus, the
partners, rather than the partnership, receive and report any deductions and tax
credits, if any, as well as the income, from a partnership's operations. Each
partnership has been formed as a limited partnership under the Delaware Revised
Uniform Limited Partnership Act, which describes each partnership as a
"partnership." Thus, each partnership automatically will be classified as a
partnership for federal tax purposes since the managing general partner has
represented that neither partnership will elect to be taxed as a corporation.
Treas. Reg. Section 301.7701-2.

The managing general partner anticipates that all of the subscription proceeds
of each partnership will be expended in 2007, and the related income, if any,
and deductions, including the deduction for intangible drilling costs, will be
reflected on their respective investors' federal income tax returns for 2007,
subject to each investor's right to elect to capitalize and amortize over a
60-month period a portion or all of the investor's share of his partnership's
deduction for intangible drilling costs. See "Capitalization and Source of Funds
and Use of Proceeds" and "Participation in Costs and Revenues" and "- Intangible
Drilling Costs," "- Drilling Contracts," "- Depletion Allowance" and "-
Depreciation and Cost Recovery Deduction" and "- Alternative Minimum Tax,"
below.).

LIMITATIONS ON PASSIVE ACTIVITY LOSSES AND CREDITS

Under the passive activity rules of Section 469 of the Code, all income of a
taxpayer who is subject to the rules is categorized as:

     o    income from passive activities, such as limited partners' interests in
          a business;

     o    active income, such as salary, bonuses, etc.; or

     o    portfolio income, such as gain, interest, dividends and royalties
          unless earned in the ordinary course of a trade or business, and gain
          not derived in the ordinary course of a trade or business on the sale
          of property that generates portfolio income or is held for investment.

                                       109
Losses generated by passive activities can offset only passive income and cannot
be applied against active income or portfolio income. Similar rules apply with
respect to tax credits. (See "- Marginal Well Production Credits," below.)
Suspended passive losses and passive credits that an investor cannot use in his
current tax year may be carried forward indefinitely, but not back, and used to
offset future years' passive activity income, or offset passive activity regular
federal income tax liability (in the case of passive activity credits).

The passive activity rules apply to:

     o    individuals, estates, and trusts;

     o    closely held C corporations which under Sections 469(j)(1),
          465(a)(1)(B) and 542(a)(2) of the Code are regular corporations with
          five or fewer individuals who own directly or indirectly more than 50%
          in value of the outstanding stock at any time during the last half of
          the taxable year (for this purpose, U.S. trusts forming part of a
          stock bonus, pension or profit-sharing plan of an employer for the
          exclusive benefit of its employees or their beneficiaries that
          constitutes a "qualified trust" under Section 401(a) of the Code,
          trusts forming part of a plan providing for the payment of
          supplemental employee unemployment compensation benefits that meet the
          requirements of Section 501(c)(17) of the Code, domestic or foreign
          "private foundations" described in Section 501(c)(3) of the Code, and
          a portion of a trust permanently set aside or to be used exclusively
          for the charitable purposes described in Section 642(c) of the Code or
          a corresponding provision of a prior income tax law, are considered to
          be individuals); and

     o    personal service corporations, which under Sections 469(j)(2), 269A(b)
          and 318(a)(2)(C) of the Code are corporations the principal activity
          of which is the performance of personal services and those services
          are substantially performed by employee-owners. For this purpose, the
          term "employee-owners" includes any employee who owns, on any day
          during the taxable year, any of the outstanding stock of the personal
          service corporation, and an employee is considered to own:

          o    the employee's proportionate share of any stock of the personal
               service corporation owned, directly or indirectly, by or for a
               partnership or estate in which the employee is a partner or
               beneficiary;

          o    the employee's proportionate share of any stock of the personal
               service corporation owned, directly or indirectly, by or for a
               trust (other than an employee's trust that is a qualified
               pension, profit-sharing, or stock bonus plan and is exempt from
               the tax) if the employee is a beneficiary;

          o    all of the stock of the personal service corporation owned,
               directly or indirectly, by or for any portion of a trust of that
               the employee is considered the owner under the Code; and

          o    if any stock in a corporation is owned, directly or indirectly,
               for or by the employee, the employee's portionate share of the
               stock of the personal service corporation owned, directly or
               indirectly, by or for that corporation.

          Provided, however, that a corporation will not be treated as a
          personal service corporation for purposes of Section 469 of the Code
          unless more than 10% of the stock (by value) in the corporation is
          held by employee-owners (as described above). I.R.C. Section
          469(j)(2)(B).

However, if a closely held C corporation, other than a personal service
corporation in which employee-owners own more than 10% (by value) of the stock,
has net active income (i.e., taxable income determined without regard to any
income or loss from a passive activity and without regard to any item of
portfolio income, expense (including interest expense), or gain or loss) for a
taxable year, its passive loss for that taxable year can be applied against its
net active income for that taxable year. Similar rules apply to its passive
credits, if any. I.R.C. Section 469(e)(2).

                                       110
Passive activities include any trade or business in which the taxpayer does not
materially participate on a regular, continuous, and substantial basis. Under
the partnership agreement, limited partners will not have material participation
in the partnership in which they invest. Thus, if you are subject to the passive
activity rules as described above and you invest in a partnership as a limited
partner, your investment in the partnership will be subject to the passive
activity limitations on losses and credits. (See "Risk Factors - Tax Risks -
Limited Partners Need Passive Income to Use Their Deduction for Intangible
Drilling Costs.")

Investor general partners also will not materially participate in the
partnership in which they invest. However, because each partnership will own
only "working interests," as defined by the Code, in its wells, and investor
general partners will not have limited liability under the Delaware Revised
Uniform Limited Partnership Act until they are converted to limited partners,
their deductions and any credits from their partnership will not be treated as
passive deductions or credits under the Code before the conversion, unless they
invest in a partnership through an entity which limits their liability. For
example, if an individual invests in a partnership indirectly as an investor
general partner by using an entity that limits his personal liability under
state law to purchase his units, such as a limited partnership in which he is
not a general partner, a limited liability company or an S corporation, he will
be subject to the passive activity limitations on deductions and credits the
same as if he had invested in the partnership as a limited partner. (See "-
Conversion from Investor General Partner to Limited Partner" and "- Marginal
Well Production Credits," below.)

As compared with limitations on liability under state law as discussed above,
contractual limitations on the liability of investor general partners under the
partnership agreement, such as insurance, limited indemnification by the
managing general partner, etc. will not cause investor general partners to be
subject to the passive activity limitations on losses and credits. Investor
general partners, however, may be subject to an additional limitation on their
deduction of investment interest expense as a result of their non-passive
deduction of intangible drilling costs. (See "- Limitations on Deduction of
Investment Interest," below.)

A Limited Partner's "at risk" amount is reduced by losses allowed under Section
465 of the Code even if the losses are suspended by the passive activity
limitations. (See "- 'At Risk' Limitation on Losses," below.) Similarly, a
Limited Partner's basis is reduced by deductions even if the deductions are
suspended under the passive activity limitations. (See "- Tax Basis of Units,"
below.)

Suspended passive losses and passive credits that cannot be used by a taxpayer
in his current tax year may be carried forward indefinitely, but not back, and
can be used to offset passive income in future years or, in the case of passive
credits, can be used to offset regular federal income tax liability attributable
to passive income in future years. I.R.C. Section 469(b). A suspended passive
loss, but not a suspended passive credit, is allowed in full when a taxpayer's
entire interest in a passive activity is sold to an unrelated third-party in a
fully taxable transaction, and in part on the taxable disposition of
substantially all of a taxpayer's interest in a passive activity if the
suspended passive loss as well as current gross income and deductions of the
passive activity can be allocated to the part disposed of with reasonable
certainty. I.R.C. Section 469(g)(1). In an installment sale of a taxpayer's
entire interest in a passive activity, passive losses become available in the
same ratio that gain recognized each year bears to the total gain on the sale.
I.R.C. Section 469(g)(3). (See "Transferability of Units - Restrictions on
Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership
Agreement.")

Any suspended passive losses remaining at a taxpayer's death are allowed as
deductions on the decedent's final return, subject to a reduction to the extent
the amount of the suspended passive losses is greater than the excess of the
basis of the property in the hands of the transferee over the property's
adjusted basis immediately before the decedent's death. I.R.C. Section
469(g)(2). If a taxpayer makes a gift of his entire interest in a passive
activity, the basis in the property of the person receiving the gift is
increased by any suspended passive losses and no deductions are allowed. If the
interest is later sold at a loss, the basis in the property of the person
receiving the gift is limited to the fair market value of the property on the
date the gift was made. I.R.C. Section 469(j)(6).

                                       111
PUBLICLY TRADED PARTNERSHIP RULES

Net losses and most net credits of a partner from a publicly traded partnership
are suspended and carried forward to be netted against income or regular federal
income tax liability, respectively, from that publicly traded partnership only.
In addition, net losses from other passive activities may not be used to offset
net passive income from a publicly traded partnership. I.R.C. Sections 469(k)(2)
and 7704. A publicly traded partnership is a partnership in which interests in
the partnership are traded on an established securities market or are readily
tradable on either a secondary market or the substantial equivalent of a
secondary market. However, in special counsel's opinion neither of the
partnerships will be treated as a publicly traded partnership under the Code.
This opinion is based primarily on the substantial restrictions in the
partnership agreement on the ability of you and the other investors to transfer
your units in your partnership. (See "Transferability of Units - Restrictions on
Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership
Agreement.") Also, the managing general partner has represented that the
partnerships' respective units will be not traded on an established securities
market.

CONVERSION FROM INVESTOR GENERAL PARTNER TO LIMITED PARTNER

If you invest in a partnership as an investor general partner, then your share
of the partnership's deduction for intangible drilling costs in 2007 will not be
subject to the passive activity limitations on losses and credits. This is
because the investor general partner units in each partnership will not be
converted to limited partner units under Section 6.01(b)(1) of the partnership
agreement until after all of the wells in that partnership have been drilled and
completed. (See "Actions to be Taken by Managing General Partner to Reduce Risks
of Additional Payments by Investor General Partners," and "- Drilling
Contracts," below.) After the investor general partner units have been converted
to limited partner units, each former investor general partner will have limited
liability as a limited partner under the Delaware Revised Uniform Limited
Partnership Act after the date of the conversion.

Concurrently, the former investor general partner will become subject to the
passive activity limitations on losses and credits as a limited partner.
However, the former investor general partner previously will have received a
non-passive loss as an investor general partner in 2007 as a result of his share
of his partnership's deduction for intangible drilling costs. Therefore, the
Code requires that his net income from the partnership's wells after his
conversion to a limited partner must continue to be characterized as non-passive
income that cannot be offset with passive losses. For a discussion of the effect
of this rule on an investor general partner's tax credits, if any, from his
partnership, see "- Marginal Well Production Credits," below. The conversion of
the investor general partner units into limited partner units should not have
any other adverse tax consequences on an investor general partner unless his
share, if any, of any partnership liabilities is reduced as a result of the
conversion. This is because a reduction in a partner's share of liabilities is
treated as a constructive distribution of cash to the partner, which reduces the
partner's basis in his partnership units and is taxable to the partner to the
extent it exceeds his basis in his units. (See "- Tax Basis of Units," below.)

TAXABLE YEAR AND METHOD OF ACCOUNTING

Each partnership will adopt a calendar year taxable year and will use the
accrual method of accounting for federal income tax purposes.

TAXABLE YEAR. Each partnership will have a calendar year taxable year. I.R.C.
Sections 706(a) and (b). The taxable year of the partnership in which you invest
is important to you because your share of the partnership's deductions, tax
credits, if any, income and other items of tax significance must be taken into
account on your personal federal income tax return for your taxable year within
or with which the partnership's taxable year ends.

METHOD OF ACCOUNTING. Each partnership will use the accrual method of accounting
for federal income tax purposes. I.R.C. Section 448(a). Under the accrual method
of accounting, income is taken into account for the year in which all events
have occurred that fix the right to receive it and the amount is determinable
with reasonable accuracy, rather than the time of receipt. Consequently, you and
the other investors in the partnership in which you invest may have income tax
liability resulting from the partnership's accrual of income in one tax year
even though it does not receive the income in cash until the next tax year.
Expenses are deducted for the year in which all events have occurred that
determine the fact of the liability, the amount is determinable with reasonable
accuracy and the economic performance test is satisfied. Under Section 461(h) of
the Code, if the

                                       112
liability of the taxpayer arises out of the providing of services or property to
the taxpayer by another person, economic performance occurs as the services or
property, respectively, are provided. If the liability of the taxpayer arises
out of the use of the property by the taxpayer, economic performance occurs as
the property is used.

A special rule in the Code, however, provides that there is economic performance
in the current taxable year with respect to amounts paid in that taxable year
for intangible drilling costs of drilling and completing a natural gas or oil
well so long as the drilling of the well begins before the close of the 90th day
after the close of the taxable year in which the payments were made. I.R.C.
Section 461(i). (See "- Drilling Contracts," below, for a discussion of the
federal income tax treatment of any prepaid intangible drilling costs by the
partnerships.)

BUSINESS EXPENSES

Ordinary and necessary business expenses, including reasonable compensation for
personal services actually rendered, are deductible in the year incurred. In
this regard, the managing general partner has represented that the amounts
payable by each partnership to it and its affiliates under the partnership
agreement and the drilling and operating agreement are reasonable and
competitive amounts that ordinarily would be paid for similar services in
similar transactions between persons having no affiliation and dealing with each
other "at arms" length in the proposed areas of the partnerships' operations.
(See Treas. Reg. Section 1.162-7(b)(3) and "Compensation" and "- Drilling
Contracts," below.) The fees paid to the managing general partner and its
affiliates by the partnerships will not be currently deductible, however, to the
extent it is determined by the IRS or the courts that they are:

     o    in excess of reasonable compensation;

     o    properly characterized as organization or syndication fees or other
          capital costs, such as lease acquisition costs or equipment costs
          (i.e., "Tangible Costs"); or

     o    not "ordinary and necessary" business expenses.

In the event of an IRS audit of a partnership, payments to the managing general
partner and its affiliates by the partnership would be scrutinized by the IRS to
a greater extent than payments to an unrelated party.

Your ability in any taxable year to use your share of these partnership
deductions on your personal federal income tax returns may be reduced,
eliminated or deferred by the "Potential Limitations on Deductions" set forth in
special counsel's opinion (4) in "Special Counsel's Opinions," above.

Although the partnerships will engage in the production of natural gas and oil
from wells drilled in the United States, the partnerships will not qualify for
the "U.S. production activities deduction." This is because the deduction cannot
exceed 50% of the IRS Form W-2 wages paid by a taxpayer for a tax year, and the
partnerships will not pay any Form W-2 wages since they will not have any
employees. Instead, the partnerships will rely on the managing general partner
and its affiliates to manage them and their respective businesses. (See
"Management.")

INTANGIBLE DRILLING COSTS

You may elect to deduct your share of your partnership's intangible drilling
costs, which include items that do not have salvage value, such as labor, fuel,
repairs, supplies and hauling necessary to the drilling of a well and preparing
it for the production of natural gas or oil, in the taxable year in which your
partnership's wells are drilled and completed. I.R.C. Section 263(c), Treas.
Reg. Section 1.612-4(a). For a discussion of the deduction of intangible
drilling costs that are prepaid by your partnership in 2007 for wells the
drilling of which will not begin until 2008, if any, see "- Drilling Contracts,"
below.

Your share of your partnership's gain (if a partnership well is sold at a gain),
or your gain (if your units are sold at a gain), will be treated as ordinary
income, rather than capital gain, to the extent of the previous deductions for
intangible drilling costs you have claimed, but not for the deductions for
operating expenses related to a re-entry well, if any. (See "- Sale of the
Properties" and "- Disposition of Units," below.) Also, productive-well
intangible drilling costs may subject you to an

                                       113
alternative minimum tax in excess of regular tax unless you elect to deduct all
or part of these costs ratably over a 60 month period. (See "- Alternative
Minimum Tax," below.)

Under the partnership agreement, 90% of the subscription proceeds received by
each partnership from its respective investors will be used to pay 100% of the
partnership's intangible drilling costs of drilling and completing its wells.
(See "Application of Proceeds" and "Participation in Costs and Revenues.") The
IRS could challenge the characterization of a portion of these costs as
currently deductible intangible drilling costs and recharacterize the costs as
some other item that may not be currently deductible, such as lease acquisition
expenses, equipment costs or syndication fees. However, this would have no
effect on the allocation and payment of the intangible drilling costs by you and
the other investors under the partnership agreement.

Also, if a partnership re-enters an existing well as described in "Proposed
Activities - Primary Areas of Operations - Mississippian/Upper Devonian
Sandstone Reservoirs, Fayette County, Pennsylvania," the costs of deepening the
well and completing it to deeper reservoirs, if any, other than equipment costs
and lease acquisition costs, will be treated under the Code as intangible
drilling costs. The remaining intangible drilling costs of drilling and
completing a re-entry well that are not related to deepening the well, if any,
however, will be treated under the Code as operating expenses that should be
expensed in the taxable year they are incurred for federal income tax purposes.
Any intangible drilling costs of a re-entry well that are treated as operating
expenses for federal income tax purposes, however, will not be characterized as
operating costs, instead of intangible drilling costs, for purposes of
allocating the payment of the costs between the managing general partner, on the
one hand, and you and the other investors, on the other hand. In addition, under
the Code costs related to a re-entry well that are characterized as operating
costs under the Code cannot be amortized as intangible drilling costs over a
60-month period as described in "- Alternative Minimum Tax," below, even though
they may be characterized as intangible drilling costs for purposes of the
partnership agreement as discussed above. (See "Participation in Costs and
Revenues.")

In the case of corporations, other than S corporations, which are "integrated
oil companies," the amount allowable as a deduction for intangible drilling
costs in any taxable year is reduced by 30%. I.R.C. Section 291(b)(1).
Integrated oil companies are:

     o    those taxpayers who directly or through a related person engage in the
          retail sale of natural gas and oil and whose gross receipts for the
          taxable year from those activities exceed $5 million; or

     o    those taxpayers and related persons who have average daily refinery
          runs in excess of 75,000 barrels for the taxable year. I.R.C.
          Section 291(b)(4).

Amounts of an integrated oil company's intangible drilling costs that are
disallowed as a current deduction under Section 291 of the Code are allowable,
however, as a deduction ratably over the 60-month period beginning with the
month in which the costs are paid or incurred. Neither partnership will be an
integrated oil company.

Your ability in any taxable year to use your share of these partnership
deductions on your personal federal income tax returns may be reduced,
eliminated or deferred by the "Potential Limitations on Deductions" set forth in
special counsel's opinion (4) in "Special Counsel's Opinions," above.

You are urged to seek advice based on your particular circumstances from an
independent tax advisor concerning the tax benefits to you of your share of the
deduction for intangible drilling costs of the partnership in which you invest.

DRILLING CONTRACTS

Each partnership will enter into the drilling and operating agreement with the
managing general partner to drill and complete the partnership's wells for an
amount equal to the sum of the following items: (i) the cost of permits,
supplies, materials, equipment, and all other items used in the drilling and
completion of a well provided by third-parties, or if the foregoing items are
provided by affiliates of the managing general partner, then those items will be
charged at competitive rates; (ii) fees for third-party services; (iii) fees for
services provided by the managing general partner's affiliates, which will be
charged at competitive rates; (iv) an administration and oversight fee of
$15,000 per well, which will be charged to you and the other investors as part
of each well's intangible drilling costs and the portion of equipment costs paid
by you and the other

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investors; and (v) a mark-up in an amount equal to 15% of the sum of (i), (ii),
(iii) and (iv), above, for the managing general partner's services as general
drilling contractor. The managing general partner anticipates that, on average
over all of the wells that are drilled and completed by each partnership,
assuming a 100% working interest in each well, its mark-up of 15% will be
approximately $42,254 per well with respect to the intangible drilling costs and
the portion of equipment costs paid by you and the other investors in your
partnership as described in "Compensation - Drilling Contracts." However, the
actual cost of drilling and completing the wells may be more or less than the
amounts estimated by the managing general partner, due primarily to the
uncertain nature of drilling operations. Therefore, the managing general
partner's 15% mark-up discussed above also could be more or less than the dollar
amount estimated by the managing general partner as set forth above. The
managing general partner believes that the compensation payable to it and its
affiliates under the drilling and operating agreement is competitive in the
proposed areas of operation. Nevertheless, the amount of fees and profit
realized by the managing general partner under the drilling and operating
agreement could be challenged by the IRS as being unreasonable and disallowed as
a deductible intangible drilling cost.

Depending primarily on when their respective subscription proceeds are received,
the managing general partner anticipates that each partnership may prepay in
2007 most, if not all, of its intangible drilling costs for wells the drilling
of which will begin in 2008. In Keller v. Commissioner, 79 T.C. 7 (1982), aff'd
725 F.2d 1173 (8th Cir. 1984), the Tax Court applied a two-part test for the
current deductibility of prepaid intangible drilling and development costs. The
test is:

     o    the expenditure must be a payment rather than a refundable deposit;
          and

     o    the deduction must not result in a material distortion of income
          taking into substantial consideration the business purpose aspects of
          the transaction.

The drilling partnership in Keller entered into footage and daywork drilling
contracts that permitted it to terminate the contracts at any time, without a
default by the driller, and receive a return of the prepaid amounts less amounts
earned by the driller. The Tax Court found that the right to receive, by
unilateral action, a refund of the prepayments on the footage and daywork
drilling contracts rendered the prepayments deposits instead of payments.
Therefore, the prepayments were held to be nondeductible in the year they were
paid to the extent they had not been earned by the driller. The Tax Court
further found that the drilling partnership failed to show a convincing business
purpose for the prepayments under the footage and daywork drilling contracts.

The drilling partnership in Keller also entered into turnkey drilling contracts
that permitted it to stop work under the contract at any time and apply the
unearned balance of the prepaid amounts to another well to be drilled on a
turnkey basis. The Tax Court found that these prepayments constituted "payments"
and not nondeductible deposits, despite the right of substitution. Further, the
Tax Court noted that the turnkey drilling contracts obligated "the driller to
drill to the contract depth for a stated price regardless of the time, materials
or expenses required to drill the well," thereby locking in prices and shifting
the risks of drilling from the drilling partnership to the driller. Since the
drilling partnership, a cash basis taxpayer, received the benefit of the turnkey
obligation in the year of prepayment, the Tax Court found that the amounts
prepaid on turnkey drilling contracts clearly reflected income and were
deductible in the year of prepayment.

In Leonard T. Ruth, TC Memo 1983-586, a drilling program entered into nine
separate turnkey contracts with a general contractor, the parent corporation of
the drilling program's corporate general partner, to drill nine program wells.
Each contract identified the prospect to be drilled, stated the turnkey price,
and required the full price to be paid in 1974. The program paid the full
turnkey price to the general contractor on December 31, 1974; the receipt of
which was found by the court to be significant in the general contractor's
financial planning. The program had no right to receive a refund of any of the
payments. The actual drilling of the nine wells was subcontracted by the general
contractor to independent contractors who were paid by the general contractor in
accordance with their individual contracts. The drilling of all of the wells
began in 1975 and all of the wells were completed in 1975. The amount paid by
the general contractor to the independent driller for its work on the nine wells
was approximately $365,000 less than the amount prepaid by the program to the
general contractor. The program claimed a deduction for intangible drilling and
development costs in 1974. The IRS challenged the timing of the deduction,
contending that there was no business purpose for the payments in 1974, that the
turnkey arrangements were merely "contracts of convenience" designed to create a
tax deduction in 1974, and that the turnkey

                                       115
contracts constituted assets having a life beyond the taxable year and that to
allow a deduction for their entire costs in 1974 distorted income. The Tax
Court, relying on Keller, held that the program could deduct the full amount of
the payments in 1974. The court found that the program entered into turnkey
contracts, paid a premium to secure the turnkey obligations, and thereby locked
in the drilling price and shifted the risks of drilling to the general
contractor. Further, the court found that by signing and paying the turnkey
obligation, the program got its bargained-for benefit in 1974, therefore the
deduction of the payments in 1974 clearly reflected income.

Each partnership will attempt to comply with the guidelines set forth in Keller
with respect to any prepaid intangible drilling costs. In this regard, the
drilling and operating agreement will require each partnership to prepay in 2007
all of the partnership's share of the estimated intangible drilling costs, and
all of the investors' share of your partnership's share of the estimated
equipment costs, for drilling and completing specified wells for that
partnership, the drilling of which may begin in 2008. These prepayments of
intangible drilling costs should not result in a loss of a current deduction for
the intangible drilling costs in 2007 if:

     o    the guidelines set forth in Keller are complied with;

     o    there is a legitimate business purpose for the required prepayment;

     o    the drilling of the prepaid wells begins on or before March 30, 2008;

     o    the contract is not merely a sham to control the timing of the
          deduction; and

     o    there is an enforceable contract of economic substance.

In this regard, the drilling and operating agreement will require each
partnership to prepay the managing general partner's estimate of the intangible
drilling costs and the investor's share of the equipment costs to drill and
complete the wells specified in the drilling and operating agreement in order to
enable the operator to:

     o    begin site preparation for the wells;

     o    obtain suitable subcontractors at the then current prices; and

     o    insure the availability of equipment and materials.

Under the drilling and operating agreement excess prepaid intangible drilling
costs, if any, will not be refundable to a partnership, but instead will be
applied only to intangible drilling cost overruns, if any, on the other
specified wells being drilled or completed by the partnership or to intangible
drilling costs to be incurred by the partnership in drilling and completing
substitute wells. Under Keller, a provision for substitute wells should not
result in the prepayments being characterized as refundable deposits.

The likelihood that prepayments of intangible drilling costs will be challenged
by the IRS on the grounds that there is no business purpose for the prepayments
is increased if prepayments are not required with respect to 100% of the working
interest in the well. In this regard, the managing general partner anticipates
that less than 100% of the working interest will be acquired by each partnership
in one or more of its wells, and prepayments of intangible drilling costs will
not be required of the other owners of working interests in those wells. In the
view of special counsel, however, a legitimate business purpose for the required
prepayments of intangible drilling costs by the partnerships may exist under the
guidelines set forth in Keller, even though prepayments are not required by the
drilling contractor with respect to a portion of the working interest in the
wells.

In addition, a current deduction for prepaid intangible drilling costs is
available only if the drilling of the wells begins before the close of the 90th
day after the close of the taxable year in which the prepayment was made. See
the discussion of Section 461(i) of the Code in "- Method of Accounting," above.
Therefore, under the drilling and operating agreement, the managing

                                      116
general partner, serving as operator and general drilling contractor, must begin
drilling the wells that are prepaid by the partnership in 2007, if any, no later
than March 30, 2008, which is before the close of the 90th day after the close
of the 2007 calendar taxable year of each partnership in which a partnership's
intangible drilling costs are prepaid. However, the drilling of any partnership
well may be delayed due to circumstances beyond the control of the managing
general partner and the drilling subcontractors. These circumstances include,
for example:

     o    the unavailability of drilling rigs;

     o    decisions of third-party operators to delay drilling the wells;

     o    poor weather conditions;

     o    inability to obtain drilling permits or access right to the drilling
          site; or

     o    title problems;

and the managing general partner will have no liability under the partnership
agreement or the drilling and operating agreement to either partnership or their
respective investors if these types of events (i.e., "force majeure") delay
beginning the drilling of any partnership prepaid well beyond the 90 day limit
imposed by Section 461(i) of the Code (i.e., March 30, 2008).

If the drilling of a prepaid partnership well does not begin within the 90 day
time constraint imposed by Section 461(i) of the Code (i.e., March 30, 2008),
deductions claimed by you and the other investors in that partnership for
prepaid intangible drilling costs for the well in 2007, would not be lost, but
those deductions would be deferred to 2008 when the well is actually drilled.

Your ability in any taxable year to use your share of these partnership
deductions on your personal federal income tax returns may be reduced,
eliminated or deferred by the "Potential Limitations on Deductions" set forth in
special counsel's opinion (4) in "Special Counsel's Opinions," above.

DEPLETION ALLOWANCE

Proceeds from the sale of each partnership's natural gas and oil production will
constitute ordinary income. A portion of that income will not be taxable under
the depletion allowance, which permits the deduction from gross income for
federal income tax purposes of either the percentage depletion allowance or the
cost depletion allowance, whichever is greater. I.R.C. Sections 611, 613 and
613A. Your share of your partnership's gain (if a partnership well is sold at a
gain), or your gain (if you sell your units at a gain), will be treated as
ordinary income rather than capital gain to the extent of your previous
deductions for depletion that reduced your adjusted basis in the property or
your units. (See "- Sale of the Properties" and "- Disposition of Units,"
below.)

Cost depletion for any year is determined by dividing the adjusted tax basis for
the property by the total units of natural gas or oil expected to be recoverable
from the property and then multiplying the resultant quotient by the number of
units actually sold during the year. Cost depletion cannot exceed the adjusted
tax basis of the property to which it relates.

Percentage depletion is available to taxpayers other than "integrated oil
companies," as that term is defined in "- Intangible Drilling Costs," above,
which does not include the partnerships. Your percentage depletion allowance is
based on your share of your partnership's gross production income from its
natural gas and oil properties. Under Section 613A(c) of the Code, percentage
depletion is available with respect to 6 million cubic feet of average daily
production of domestic natural gas or 1,000 barrels of average daily production
of domestic crude oil. However, taxpayers who have both natural gas and oil
production may allocate the production limitation between the production.

The rate of percentage depletion is 15%. However, percentage depletion for
marginal production increases 1%, up to a maximum increase of 10%, for each
whole dollar that the domestic wellhead price of crude oil for the immediately
preceding year is less than $20 per barrel without adjustment for inflation.
I.R.C. Section 613A(c)(6). The term "marginal production" includes natural gas
and oil produced from a domestic stripper well property, which is defined in
Section 613A(c)(6)(E) of the Code

                                      117
as any property that produces a daily average of 15 or less equivalent barrels
of oil, which is equivalent to 90 mcf of natural gas, per producing well on the
property in the calendar year. In this regard, the managing general partner has
represented that most, if not all, of the natural gas and oil production from
each partnership's productive wells will be marginal production under this
definition in the Code. Therefore, most, if not all, of each partnership's gross
income from the sale of its natural gas and oil production will qualify for
these potentially higher rates of percentage depletion. The rate of percentage
depletion for marginal production in 2007 is 15%. This rate may fluctuate from
year to year depending on the price of oil, but will not be less than the
statutory rate of 15% nor more than 25%.

Also, percentage depletion:

     o    may not exceed 100% of the taxable income from each natural gas and
          oil property before the deduction for depletion, (this limitation was
          suspended in 2005 with respect to marginal properties, which the
          managing general partner has represented will include most, if not
          all, of each partnership's wells, but as of the date of this
          prospectus this limitation had not been suspended for 2007 and it may
          never be suspended for 2007 or subsequent taxable years); and

     o    is limited to 65% of the taxpayer's taxable income for the year
          computed without regard to percentage depletion, net operating loss
          carry-backs and capital loss carry-backs and, in the case of an
          investor that is a trust, any distributions to its beneficiaries. Any
          disallowed percentage depletion deductions under this limitation may
          be carried forward to the next taxable year.

The availability in any taxable year of the percentage depletion allowance must
be computed separately by you and not by your partnership or for investors in
your partnership as a whole. You are urged to seek advice based on your
particular circumstances from an independent tax advisor with respect to the
availability of the percentage depletion allowance to you.

DEPRECIATION AND COST RECOVERY DEDUCTIONS

Ten percent of each partnership's subscription proceeds from you and the other
investors will be used to pay equipment costs (i.e. "Tangible Costs"), and the
managing general partner will pay all of the partnership's remaining equipment
costs of drilling and completing its wells. The related depreciation deductions,
i.e., cost recovery deductions under the modified accelerated cost recovery
system ("MACRS"), will be allocated under the partnership agreement between the
managing general partner, on the one hand, and you and the other investors in
each partnership, on the other hand, in proportion to the actual amount of the
partnership's equipment costs paid by each.

A partnership's reasonable Tangible Costs for equipment placed in its wells that
cannot be deducted immediately will be recovered through depreciation deductions
over a seven year cost recovery period, using the 200% declining balance method
with a switch to straight-line to maximize the deduction, beginning in the
taxable year in which each well is drilled, completed and made capable of
production, (i.e., "placed in service") by the partnership. I.R.C. Section
168(c). In this regard, the managing general partner anticipates that each
partnership will have all of its wells drilled, completed and placed in service
for the production of natural gas or oil approximately eight to 12 months after
that partnership's final closing. In the case of a short partnership tax year,
the MACRS deduction will be prorated on a 12-month basis. No distinction is made
between new and used property and salvage value is disregarded. Under Section
168(d)(1) of the Code, all property assigned to the 7-year class is treated as
placed in service, or disposed of, in the middle of the year, unless more than
40% of the total cost of all equipment in a partnership's wells placed in
service during the year is placed in service during the last three months of the
year. If that happens, then under Section 168(d)(3) of the Code the depreciation
for the full year will be multiplied by a fraction based on the quarter the
equipment is placed in service: 87.5% for the first quarter, 62.5% for the
second, 37.5% for the third, and 12.5% for the fourth. All of these cost
recovery deductions claimed by a partnership and you and the other investors in
that partnership are subject to recapture as ordinary income rather than capital
gain on the sale or other taxable disposition of the property by the partnership
or your units by you. (See "- Sale of the Properties" and "- Disposition of
Units," below.) Depreciation for alternative minimum tax purposes is computed
using the 150% declining balance method switching to straight-line, for most
personal property. This will result in adjustments in computing the alternative
minimum taxable income of you and the other investors in a partnership in
taxable years in which the partnership claims depreciation deductions. (See "-
Alternative Minimum Tax," below.)

                                      118
Your ability in any taxable year to use your share of these partnership
deductions on your personal federal income tax returns may be reduced,
eliminated or deferred by the "Potential Limitations on Deductions" set forth in
special counsel's opinion (4) in "Special Counsel's Opinions," above.

MARGINAL WELL PRODUCTION CREDITS

There is a marginal well production credit of 50(cent) per mcf of qualified
natural gas production and $3 per barrel of qualified oil production for
purposes of the regular federal income tax. A tax credit, unlike a tax
deduction, reduces tax liability on a dollar-for-dollar basis. This credit is
part of the general business credit under Section 38 of the Code, but under
current law this credit cannot be used against the alternative minimum tax. (See
"- Alternative Minimum Tax," below.) Natural gas and oil production that
qualifies as marginal production under the percentage depletion rules of Section
613A(c)(6) of the Code as discussed above in "- Depletion Allowance," which the
managing general partner has represented will include most, if not all, of the
natural gas and oil production from each partnership's productive wells, is also
qualified marginal production for purposes of this credit. Also, the credit will
be reduced proportionately if the reference prices for the previous calendar
year are between $1.67 and $2.00 per mcf for natural gas and $15 and $18 per
barrel for oil. In this regard, the managing general partner anticipates that
neither of the partnership's natural gas and oil production in 2007, if any,
will qualify for this credit, because as of the date of this prospectus the
prices for natural gas and oil in 2006 were substantially above the $2.00 per
mcf of natural gas and $18.00 per barrel of oil prices where the credit phases
out completely.

Based on the prices for natural gas and oil in recent years compared with the
prices at which the credit phases out completely, it may appear unlikely that
either partnership's natural gas and oil production will ever qualify for this
credit. (See "Proposed Activities - Sale of Natural Gas Production - Policy of
Treating All Wells Equally in a Geographic Area.") However, prices for natural
gas and oil are volatile and could decrease in the future. (See "Risk Factors -
Risks Related To The Partnerships' Oil and Gas Operations - Partnership
Distributions May be Reduced if There is a Decrease in the Price of Natural Gas
and Oil.") Thus, it is possible that the partnerships' production of natural gas
or oil in one or more taxable years after 2007 could qualify for the marginal
well production credit, depending primarily on the applicable reference prices
for natural gas and oil in the future. However, depending primarily on market
prices for natural gas and oil, which are volatile, each partnership's
production of natural gas and oil may not qualify for marginal well production
credits for many years, if ever.

To the extent that your share of your partnership's marginal well production
credits, if any, exceeds your regular federal income tax owed on your share of
the partnership's taxable income, the excess credits, if any, can be used by you
to offset any other regular federal income taxes owed by you, on a
dollar-for-dollar basis, subject to the passive activity limitations if you
invest in a partnership as a limited partner. (See "- Limitations on Passive
Activity Losses and Credits," above.) Also, if you invest in a partnership as an
investor general partner, your share of your partnership's marginal well
production credits, if any, will be an active credit that may offset your
regular federal income tax liability on any type of income. However, after you
are converted to a limited partner in the partnership in which you invest, your
share of the partnership's marginal well production credits, if any, will be
active credits only to the extent of your regular federal income tax liability
that is allocable to your share of any net income of the partnership from the
sale of its natural gas and oil production, since your share of that net income
must continue to be treated by you as non-passive income even after you have
been converted to a limited partner. (See "- Conversion from Investor General
Partner to Limited Partner," above.) Any credits allocable to you as a converted
investor general partner in excess of that amount, as well as all of the
marginal well production credits allocable to those investors who originally
invest in the partnership as limited partners, will be passive credits that
under current law can reduce only your regular income tax liability attributable
to net passive income from the partnership in which you invest or your other
passive activities, if any, other than publicly traded partnership passive
activities.

LEASE ACQUISITION COSTS AND ABANDONMENT

Lease acquisition costs, together with the related cost depletion deduction, and
any amortization deductions for geological and geophysical expenses incurred by
the managing general partner after August 8, 2005, with respect to a
partnership's prospects and any abandonment loss for lease acquisition costs,
are allocated under the partnership agreement 100% to the managing general
partner, which will contribute the leases to each partnership as a part of its
capital contribution.

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TAX BASIS OF UNITS

Your share of your partnership's losses is allowable only to the extent of the
adjusted basis of your units at the end of your partnership's taxable year.
I.R.C. Section 704(d). The adjusted basis of your units will be adjusted, but
not below zero, for any gain or loss to you from a sale or other taxable
disposition by your partnership of a natural gas or oil property, and will be
increased by your:

     o    cash subscription payment;

     o    share of partnership income; and

     o    share, if any, of partnership debt.

The adjusted basis of your units will be reduced by your:

     o    share of partnership losses;

     o    share of partnership expenditures that are not deductible in computing
          its taxable income and are not properly chargeable to capital account;

     o    depletion deductions, but not below zero;

     o    cash distributions from the partnership; and

     o    any reduction in your share of your partnership's debt, if any. I.R.C.
          Sections 705, 722 and 742.

The reduction in your share of partnership liabilities, if any, is considered a
cash distribution to you. Although you will not be personally liable on any
partnership loans, if you invest in a partnership as an investor general partner
you will be liable for other obligations of the partnership. (See "Risk Factors
- Risks Related to an Investment In a Partnership - If You Choose to Invest as a
General Partner, Then You Have Greater Risk Than a Limited Partner.") Should
cash distributions to you from your partnership exceed the tax basis of your
units immediately before the distributions, taxable gain would result to you to
the extent of the excess. (See "- Distributions From a Partnership," below.)

"AT RISK" LIMITATION ON LOSSES

You may use your share of your partnership's losses to offset income from other
sources, to the extent that your use of those losses is not limited by the
adjusted tax basis of your units or the passive activity limitations on losses
and credits, but only to the extent of the amount you have "at risk" in the
partnership under Section 465 of the Code at the end of a taxable year. (See "-
Limitations on Passive Activity Losses and Credits" and "- Tax Basis of Units,"
above.) "Loss," for purposes of the "at risk" rules, means the excess of your
share of the allocable deductions for a taxable year from the partnership in
which you invest over the amount of income actually received or accrued by you
during the year from that partnership. This "at risk" limitation on your share
of your partnership's losses, however, does not apply to you if you are a
corporation that is neither an S corporation nor a corporation in which at any
time during the last half of the taxable year five or fewer individuals owned
more than 50% (in value) of the outstanding stock under Section 542(a)(2) of the
Code. (See "- Limitations on Passive Activity Losses and Credits," above,
relating to the application of Section 469 of the Code to closely held C
corporations for additional information on the stock ownership requirements
under Section 542(a)(2) of the Code.

Your initial "at risk" amount in the partnership in which you invest will be
equal to the amount of money you paid for your units. However, any amounts
borrowed by you to buy your units will not be considered "at risk" if the
amounts are borrowed from another investor in your partnership or anyone related
to another investor in your partnership. In this regard, the managing general
partner has represented that it and its affiliates will not make or arrange
financing for you or any other potential investors to use to purchase units in
the partnerships. Also, the amount you have "at risk" in your partnership will
not include the amount of any loss that you are protected against through:

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o    nonrecourse loans;

     o    guarantees;

     o    stop loss agreements; or

     o    other similar arrangements.

The amount of any loss that exceeds your "at risk" amount in the partnership in
which you invest at the end of any taxable year must be carried forward by you
to the next taxable year, and will then be available to the extent you are "at
risk" in the partnership at the end of that taxable year. Further, your "at
risk" amount in subsequent taxable years of the partnership will be reduced by
any portion of a partnership loss that is allowable to you as a deduction.

Since income, gains, losses and distributions of the partnership in which you
invest will affect your "at risk" amount in the partnership, the extent to which
you are "at risk" in the partnership must be determined annually. Previously
allowed losses must be included in your gross income if your "at risk" amount is
reduced below zero. The amount included in your income, however, may be deducted
in the next taxable year to the extent of any increase in the amount that you
have "at risk" in your partnership.

DISTRIBUTIONS FROM A PARTNERSHIP

A cash distribution from your partnership to you in excess of the adjusted basis
of your units immediately before the distribution is treated as gain to you from
the sale or exchange of your units to the extent of the excess. I.R.C. Section
731(a)(1). Different rules apply, however, to payments by a partnership to a
deceased investor's successor in interest and to payments for an investor's
share of his partnership's unrealized receivables and inventory items as those
terms are defined in Section 751 of the Code. Under Section 731(a)(2) of the
Code, no loss can be recognized by you on these types of distributions, unless
the distribution is made to liquidate your units in your partnership and then
only to the extent of the excess, if any, of your adjusted basis in your units
over the sum of the amount of money distributed to you plus your share of the
basis (as determined under Section 732 of the Code) of any unrealized
receivables and inventory items of your partnership. (See "- Disposition of
Units," below, for a discussion of a partnership's unrealized receivables and
inventory items under Section 751 of the Code.)

No gain or loss will be recognized by the partnership in which you invest on
cash distributions to you and the other investors. I.R.C. Section 731(b). If
property is distributed by the partnership to the managing general partner and
you and the other investors in that partnership, basis adjustments to the
partnership's properties may be made by the partnership, and adjustments to the
basis in their respective interests in the partnership may be made by the
managing general partner and you and the other investors. I.R.C. Sections 732,
733, 734, and 754. (See Section 5.04(d) of the Partnership Agreement and "- Tax
Elections," below.) Other distributions of cash, disproportionate distributions
of property, if any, and liquidating distributions of the partnership may result
in taxable gain or loss to you and the other investors.

SALE OF THE PROPERTIES

The maximum tax rate on a noncorporate taxpayer's adjusted net capital gain on
the sale of most capital assets held more than a year is 15%, or 5% to the
extent the gain would have been taxed at a 10% or 15% rate if it had been
ordinary income, respectively, for most capital assets. In addition, for 2008
only, the 5% tax rate on adjusted net capital gain will be reduced to 0%. The
former maximum tax rates of 18% and 8%, respectively, on qualified five-year
gain have been eliminated. These capital gain rates also apply for purposes of
the alternative minimum tax. (See "- Alternative Minimum Tax," below.) However,
the former tax rates on adjusted net capital gain of 20% and 10%, respectively,
are scheduled to be reinstated on January 1, 2009.

Under Section 1(h)(3) of the Code, "adjusted net capital gain" means net capital
gain determined without taking qualified dividend income into account:

     o    reduced (but not below zero) by:

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o    any amount of qualified dividend income taken into account as
               investment income under Section 163(d)(4)(B)(iii) of the Code;

          o    net capital gain that is taxed a maximum rate of 28% (such as
               gain on the sale of most collectibles and gain on the sale of
               qualified small business stock qualified under Section 1202 of
               the Code); and

          o    net capital gain that is taxed at a maximum rate of 25% (gain
               attributable to real estate depreciation); and

     o    increased by the amount of qualified dividend income.

"Net capital gain" means the excess of net long-term gain (the excess of
long-term gains over long-term losses) over net short-term loss (the excess of
short-term gains over short-term losses). The annual capital loss limitation for
noncorporate taxpayers is the amount of capital gains plus the lesser of $3,000,
which is reduced to $1,500 for married persons filing separate returns, or the
excess of capital losses over capital gains. I.R.C. Section 1211(b)

Gains from the sale by a partnership of a natural gas and oil property held by
it for more than 12 months will be treated as long-term capital gain, while a
net loss will be an ordinary deduction, except to the extent of depreciation
recapture on equipment and recapture of intangible drilling costs and depletion
deductions as discussed below. In addition, gain on the sale of the
partnership's natural gas and oil properties may be recaptured as ordinary
income to the extent of non-recaptured Section 1231 losses (as defined below)
for the five most recent preceding taxable years on previous sales, if any, of
the partnership's natural gas and oil properties or other assets. I.R.C. Section
1231(c). If, for any taxable year, the Section 1231 gains exceed the Section
1231 losses, the gains and losses will be treated as long-term capital gains or
long-term capital losses, as the case may be. If the Section 1231 gains do not
exceed the Section 1231 losses, the gains and losses will not be treated as
gains and losses from sales or exchanges of capital assets. For this purpose,
the term "Section 1231 gain" means any recognized gain:

     o    on the sale or exchange of a property used in a trade or business; and

     o    from the involuntary conversion into other property or money of:

          o    property used in a trade or business; or

          o    any capital assets that are held for more than one year and are
               held in connection with a trade or business or a transaction
               entered into for profit.

The term "Section 1231 loss" means any recognized loss from a sale or exchange
or conversion described above.

The term "property used in a trade or business" means depreciable property and
real property that are used in a trade or business and are held for more than
one year, which are not inventory and are not held primarily for sale to
customers in the ordinary course of a trade or business.

Net Section 1231 gain will be treated as ordinary income to the extent the gain
does not exceed the non-recaptured net Section 1231 losses. The term
"non-recaptured net Section 1231 losses" means the excess of:

     o    the aggregate amount of the net Section 1231 losses for the five most
          recent taxable years; over

     o    the portion of those losses taken into account to determine whether
          the net Section 1231 gain for any taxable year should be treated as
          ordinary income to the extent the gain does not exceed the
          non-recaptured net Section 1231 losses, as discussed above, for those
          preceding taxable years.

Other gains and losses on sales of natural gas and oil properties held by the
partnership for less than 12 months, if any, will result in ordinary gains or
losses.

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In addition, as discussed above deductions for intangible drilling costs and
depletion allowances that are incurred in connection with a natural gas or oil
property may be recaptured as ordinary income when the property is sold or
otherwise disposed of in a taxable transaction by the partnership. The amount of
gain recaptured as ordinary income is the lesser of:

     o    the aggregate amount of expenditures that have been deducted as
          intangible drilling costs with respect to the property and which, but
          for being deducted, would have been included in the adjusted basis of
          the property, plus deductions for depletion that reduced the adjusted
          basis of the property; or

     o    the excess of:

          o    the amount realized, in the case of a sale, exchange or
               involuntary conversion; or

          o    the fair market value of the interest, in the case of any other
               taxable disposition;

          over the adjusted basis of the property. I.R.C. Section 1254(a).

(See "- Intangible Drilling Costs" and "- Depletion Allowance," above.)

Also, all gain on the sale or other taxable disposition of equipment by the
partnership will be treated as ordinary income to the extent of MACRS deductions
previously claimed by the partnership. I.R.C. Section 1254(a). (See "-
Depreciation and Cost Recovery Deductions," above.)

DISPOSITION OF UNITS

The sale or exchange, including a purchase by the managing general partner, of
all or some of your units, if held by you as a capital asset for more than 12
months, will result in your recognition of long-term capital gain or loss,
except for your share of your partnership's "Section 751 assets" (i.e. inventory
items and unrealized receivables). "Unrealized receivables" includes any right
to payment for goods delivered, or to be delivered, to the extent the proceeds
would be treated as amounts received from the sale or exchange of non-capital
assets, services rendered or to be rendered, to the extent not previously
includable in income under your partnership's accounting methods, and deductions
previously claimed by you for depreciation, depletion and intangible drilling
costs with respect to the partnership in which you invest. "Inventory items"
includes property properly includable in inventory and property held primarily
for sale to customers in the ordinary course of business and any other property
that would produce ordinary income if sold, including accounts receivable for
goods and services. These tax items are sometimes referred to in this discussion
as "Section 751 assets." All of these tax items may be recaptured as ordinary
income rather than capital gain regardless of how long you have owned your
units. (See "- Sale of the Properties," above.)

If your units are held for 12 months or less, your gain or loss will be
short-term gain or loss. Also, your pro rata share of your partnership's
liabilities, if any, as of the date of the sale or exchange, must be included in
the amount realized by you. Thus, the gain recognized by you may result in a tax
liability to you greater than the cash proceeds, if any, received by you from
the disposition of your units. In addition to gain from a passive activity, a
portion of any gain recognized by a limited partner on the sale or other taxable
disposition of his units will be characterized as portfolio income under the
passive activity loss rules to the extent the gain is attributable to portfolio
income, e.g. interest income on investments of working capital. Treas. Reg.
Section 1.469-2T(e)(3). (See "- Limitations on Passive Activity Losses and
Credits," above.)

A gift of your units may result in federal and/or state income tax and gift tax
liability to you. Also, interests in different partnerships do not qualify for
tax-free like-kind exchanges. I.R.C. Section 1031(a)(2)(D). Other types of
dispositions of your units may or may not result in recognition of taxable gain.
However, no gain should be recognized by an investor general partner on the
conversion of his investor general partner units to limited partner units so
long as there is no change in his share of his partnership's liabilities or
Section 751 assets as a result of the conversion. Revenue Ruling 84-52, 1984-1
C.B. 157. In addition, if you sell or exchange all or some of your units you are
required by the Code to notify your partnership within 30 days or by January 15
of the following year, if earlier. The partnership will then report to the IRS
any information required by the IRS to be reported regarding the transfer of the
units, including your share of your partnership's Section 751 assets that are
subject to recapture as ordinary income as discussed above.

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If you die, or sell or exchange all of your units, the taxable year of your
partnership will close with respect to you, but not the remaining investors, on
the date of death, sale or exchange, and there will be a proration of
partnership items for the partnership's taxable year. If you sell less than all
of your units, the partnership's taxable year will not terminate with respect to
you, but your proportionate share of the partnership's items of income, gain,
loss, deduction and credit will be determined by taking into account your
varying interests in the partnership during the taxable year.

If you sell or exchange all or some of your units in the partnership in which
you invest, you are required under Section 6050K of the Code to notify the
partnership within 30 days or by January 15 of the following year, if earlier.
After receiving the notice, the partnership must file a return with the IRS
setting forth the name and address of both you, as the transferor, and the
transferee, the fair market value of the portion of the partnership's unrealized
receivables and appreciated inventory (i.e., Section 751 assets) allocable to
the units sold or exchanged by you (which is subject to recapture as ordinary
income instead of capital gain as discussed above) and any other information as
may be required by the IRS. The partnership also must provide each person whose
name is set forth in the return a written statement showing the information set
forth on the return.

You are urged to seek advice based on your particular circumstances from an
independent tax advisor before any sale or other disposition of your units,
including any purchase of your units by the managing general partner.

ALTERNATIVE MINIMUM TAX

With limited exceptions, under Section 55 of the Code you must pay an
alternative minimum tax if it exceeds your regular federal income tax for the
year. Alternative minimum taxable income ("AMTI") is regular federal taxable
income, plus or minus various adjustments, plus tax preference items. The tax
rate for noncorporate taxpayers is 26% for the first $175,000, $87,500 for
married individuals filing separately, of a taxpayer's AMTI in excess of the
applicable exemption amount (as set forth below); and additional AMTI is taxed
at 28%. However, the regular tax rates on capital gains also will apply for
purposes of the alternative minimum tax. (See "- Sale of the Properties,"
above.) Exemption amounts for alternative minimum tax purposes are different
from the regular tax personal exemptions, which are not allowed, and the types
and amounts of itemized deductions allowed for minimum tax purposes are more
limited than those allowed for regular tax purposes as discussed below.

For tax years beginning in 2006, the exemption amounts for individuals under the
Tax Increase Prevention Act were the following amounts:

     o    married individuals filing jointly and surviving spouses, $62,550,
          less 25% of AMTI exceeding $150,000 (zero exemption when AMTI is
          $400,200);

     o    unmarried individuals, $42,500, less 25% of AMTI exceeding $112,500
          (zero exemption when AMTI is $282,500); and

     o    married individuals filing separately, $31,275, less 25% of AMTI
          exceeding $75,000 (zero exemption when AMTI is $200,100). Also, AMTI
          of married individuals filing separately was increased by the lesser
          of $31,275 or 25% of the excess of AMTI (without regard to the
          exemption reduction) over $200,100.

Unless Congress takes further action, for tax years beginning in 2007 the
exemption amounts for individuals for alternative minimum tax purposes will be
reduced substantially from those set forth above as follows: $45,000 for married
individuals filing jointly and surviving spouses, $33,750 for single persons
other than surviving spouses, and $22,500 for married individuals filing
separately.

Code sections suspending losses, such as the rules concerning your "at risk"
amount in the partnership, the amount of your passive activity losses from the
partnership, and your basis in your units, are recomputed for alternative
minimum tax purposes, and the amounts of the deductions that are suspended, or
capital gains that are recaptured as ordinary income, may differ for regular
income tax and alternative minimum tax purposes. Due to the inherently factual
nature of these determinations and each investor's different tax situation,
special counsel is unable to express an opinion as to whether any investor will
incur, or increase, his alternative minimum tax liability because of an
investment in the partnership.

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As of the date of this prospectus, the 2006 exemption amounts and certain
adjustments to the AMTI of a noncorporate taxpayer that were available for 2006
had not been extended to 2007. Thus, you are urged to seek advice from an
independent tax advisor to determine whether changes to the alternative minimum
tax laws have been made after the date of this prospectus.

Some of the principal adjustments to taxable income that are used to determine
an individual's AMTI include those summarized below:

     o    Depreciation deductions of the costs of the equipment placed in
          service in the wells ("Tangible Costs") may not exceed deductions
          computed using the 150% declining balance method. These adjustments
          are discussed in greater detail below. (See "- Depreciation and Cost
          Recovery Deductions," above.)

     o    Miscellaneous itemized deductions are not allowed.

     o    Medical expenses are deductible only to the extent they exceed 10% of
          adjusted gross income.

     o    State and local property taxes and income taxes, which are itemized
          and deducted for regular tax purposes, are not deductible. (In 2005
          you could elect, instead, to itemize state and local sales taxes for
          regular federal income tax purposes, but as of the date of this
          prospectus this election had not been extended to 2007, thus, you are
          urged to seek advice from an independent tax advisor to determine
          whether this election was subsequently extended to 2007).

     o    Interest deductions are restricted.

     o    The standard deduction and personal exemptions are not allowed.

     o    Only some types of operating losses are deductible.

     o    Passive activity losses are computed differently.

     o    Earlier recognition of income from incentive stock options may be
          required.

The principal tax preference items that must be added to taxable income for
alternative minimum tax purposes include:

     o    excess intangible drilling costs, as discussed below; and

     o    tax-exempt interest earned on certain private activity bonds, less any
          deductions that would have been allowable if the interest were
          included in gross income for regular income tax purposes.

For taxpayers other than "integrated oil companies" as that term is defined in
"- Intangible Drilling Costs," above, which does not include the partnerships,
the 1992 National Energy Bill repealed:

     o    the preference for excess intangible drilling costs; and

     o    the excess percentage depletion preference for natural gas and oil.

The repeal of the excess intangible drilling costs preference, however, under
current law may not result in more than a 40% reduction in the amount of the
taxpayer's AMTI computed as if the excess intangible drilling costs preference
had not been repealed. I.R.C. Section 57(a)(2)(E). Under the prior rules, the
amount of intangible drilling costs that is not deductible for alternative
minimum tax purposes is the excess of the "excess intangible drilling costs"
over 65% of net income from natural gas and oil properties. Net natural gas and
oil income is determined for this purpose without subtracting excess intangible
drilling costs. Excess intangible drilling costs is the regular intangible
drilling costs deduction minus the amount that would

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have been deducted under 120-month straight-line amortization, or, at the
taxpayer's election, under the cost depletion method. There is no preference
item for costs of nonproductive wells.

Also, you may elect under Section 59(e) of the Code to capitalize all or part of
your share of your partnership's intangible drilling costs (which does not
include your share of the partnership's intangible drilling costs of a re-entry
well that are treated under the Code as operating costs, if any) and deduct the
costs ratably over a 60-month period beginning with the month in which the costs
were paid or incurred by the partnership. This election also applies for regular
tax purposes and can be revoked only with the IRS' consent. Making this
election, therefore, will include the following principal consequences to you:

     o    your regular federal income tax deduction for intangible drilling
          costs in 2007 will be reduced because you must spread the deduction
          for the amount of intangible drilling costs which you elect to
          capitalize over the 60-month amortization period; and

     o    the capitalized intangible drilling costs will not be treated as a
          preference that is included in your alternative minimum taxable
          income.

Other than intangible drilling costs as discussed above, and passive activity
losses and credits in the case of limited partners, the principal tax item that
may have an impact on your alternative minimum taxable income as a result of
investing in a partnership is depreciation of the partnership's equipment
expenses. (See "- Limitations on Passive Activity Losses and Credits," above.)
As noted in "- Depreciation and Cost Recovery Deductions," above, each
partnership's cost recovery deductions for regular income tax purposes will be
computed differently than for alternative minimum tax purposes. Consequently, in
the early years of the cost recovery period of your partnership's equipment, but
not in the later years, your depreciation deductions from the partnership will
be smaller for alternative minimum tax purposes than your depreciation
deductions for regular income tax purposes on the same equipment. This could
cause you to incur, or may increase, your alternative minimum tax liability in
those taxable years. Conversely, this adjustment may decrease your alternative
minimum taxable income in the later years of the cost recovery period. Also,
under current law, your share of your partnership's marginal well production
credits, if any, may not be used to reduce your alternative minimum tax
liability, if any. In addition, the rules relating to the alternative minimum
tax for corporations are different from those for individuals that are discussed
above.

All prospective investors contemplating purchasing units in a partnership are
urged to seek advice based on their particular circumstances from an independent
tax advisor as to the likelihood of them incurring or increasing any alternative
minimum tax liability as a result of an investment in a partnership.

LIMITATIONS ON DEDUCTION OF INVESTMENT INTEREST

Investment interest expense is deductible by a noncorporate taxpayer only to the
extent of net investment income each year, with an indefinite carryforward of
disallowed investment interest expense deductions to subsequent taxable years.
I.R.C. Section 163(d). An investor general partner's share of any interest
expense incurred by the partnership in which he invests before his investor
general partner units are converted to limited partner units will be subject to
the investment interest limitation. I.R.C. Section 163(d)(5)(A)(ii). In
addition, an investor general partner's share of the partnership's loss in 2007
as a result of the deduction for intangible drilling costs will reduce his net
investment income and may reduce or eliminate the deductibility of his
investment interest expenses, if any, in 2007, with the disallowed portion to be
carried forward to subsequent taxable years. This limitation on the deduction of
investment interest expenses, however, will not apply to any income or expenses
taken into account by limited partners in computing their income or loss from
the partnership as a passive activity under Section 469 of the Code. I.R.C.
Section 163(d)(4)(D). (See "- Limitations on Passive Activity Losses and
Credits," above.)

ALLOCATIONS

The partnership agreement allocates to you your share of your partnership's
income, gains, losses, deductions, and credits, if any, including the deductions
for intangible drilling costs and depreciation. Allocations under the
partnership agreement of some tax items are made in ratios that are different
from allocations of other tax items (i.e., "special allocations"). Your capital
account in the partnership in which you invest will be adjusted to reflect your
share of these allocations, and your capital account, as adjusted, will be given
effect by the partnership in making distributions to you on liquidation of the

                                      126
partnership or your units. Also, the basis of the natural gas and oil properties
owned by your partnership for purposes of computing cost depletion and gain or
loss on disposition of a property will be allocated and reallocated when
necessary in the ratio in which the expenditure giving rise to the tax basis of
each property was charged as of the end of the year. (See Section 5.03(b) of the
Partnership Agreement.)

Your capital account in the partnership in which you invest will be:

     o    increased by the amount of money you contribute to the partnership and
          allocations of partnership income and gain to you; and

     o    decreased by the value of property or cash distributed to you by the
          partnership and allocations of partnership losses and deductions to
          you.

Allocations made in a manner that is disproportionate to the respective
interests of the partners in a partnership of any item of partnership income,
gain, loss, deduction or credit will not be given effect unless the allocation
has "substantial economic effect." I.R.C. Section 704(b). Economic effect means
that if there is an economic benefit or burden that corresponds to an
allocation, the partner to whom the allocation is made must receive the economic
benefit or bear the economic burden. The economic effect of an allocation is
substantial if there is a reasonable possibility that the allocation will affect
substantially the dollar amounts to be received by the partners from the
partnership, independent of tax consequences and taking into account the
partners' tax attributes that are unrelated to the partnership. The allocations
under the partnership agreement will have economic effect if throughout the term
of the partnership in which you invest:

     o    the partners' capital accounts are increased and decreased as
          described above;

     o    liquidation proceeds are distributed in accordance with the partners'
          capital accounts; and

     o    any partner with a deficit balance in his capital account following
          the liquidation of his interest in the partnership is required to
          restore the amount of the deficit to the partnership.

Even though you and the other investors are not required under the partnership
agreement to restore any deficit balance in your capital accounts in your
partnership by making additional capital contributions to the partnership, an
allocation that is not attributable to nonrecourse debt or tax credits will
still be considered to have economic effect under the Treasury Regulations to
the extent it does not cause or increase a deficit balance in your capital
account if:

     o    the partners' capital accounts are increased and decreased as
          described above;

     o    the partnership's liquidation proceeds are distributed in accordance
          with the partners' capital accounts; and

     o    the partnership agreement provides that if you unexpectedly incur a
          deficit balance in your capital account because of certain
          adjustments, allocations, or distributions of the partnership, then
          you will be allocated an additional amount of partnership income and
          gain that is sufficient to eliminate the deficit balance as quickly as
          possible.

Treas. Reg. Section 1.704-1(b)(2)(ii)(d). These provisions are included in the
partnership agreement (See Sections 5.02, 5.03(h), and 7.02(a) of the
partnership agreement.)

Special provisions of the Treasury Regulations apply to deductions that are
related to nonrecourse debt and tax credits, since allocations of those tax
items cannot have substantial economic effect under the Treasury Regulations. If
the managing general partner or an affiliate makes a nonrecourse loan to the
partnership in which you invest (a "partner nonrecourse liability"), then that
partnership's losses, deductions, or Section 705(a)(2)(B) expenditures
attributable to the loan must be allocated to the managing general partner.
Also, if there is a net decrease in partner nonrecourse liability minimum gain
with respect to the loan, the managing general partner must be allocated income
and gain equal to the net decrease. (See Sections 5.03(a)(1) and

                                      127
5.03(i) of the partnership agreement.) In addition, any marginal well production
credits of the partnership will be allocated among the managing general partner
and you and the other investors in the partnership in accordance with each
partner's respective interest in the partnership's production revenues from the
sale or its natural gas and oil production. (See Section 5.03(g) of the
partnership agreement, "Participation in Costs and Revenues," and "- Marginal
Well Production Credits," above.)

If you sell or transfer your unit in the partnership in which you invest, or on
the death of an investor, or the admission of an additional partner, the
partnership's income, gain, loss, credits and deductions will be allocated among
its partners according to their varying interests in the partnership during the
taxable year. In addition, the Code may require the partnership's property to be
revalued on the admission of additional partners, if any, if disproportionate
distributions are made to the partners, or if there are "built-in" losses on the
transfer of a partner's units or any distribution of the partnership's property
to its partners. (See "- Tax Elections," below.)

It also should be noted that your share of items of income, gain, loss,
deduction, and credit, if any, in the partnership in which you invest must be
taken into account by you whether or not you receive any cash distributions from
the partnership. For example, your share of partnership revenues applied by your
partnership to the repayment of loans, if any, or the reserve for plugging
wells, will be included in your gross income in a manner analogous to an actual
distribution of the revenues (and income) to you. Thus, you may have tax
liability on taxable income from your partnership for a particular year in
excess of any cash distributions from the partnership to you with respect to
that year. To the extent a partnership has cash available for distribution,
however, it is the managing general partner's policy that partnership cash
distributions to you and the other investors in that partnership will not be
less than the managing general partner's estimate of the investors' income tax
liability (as a group) with respect to that partnership's income.

If any allocation under the partnership agreement is not recognized for federal
income tax purposes, your share of the items subject to the allocation will be
determined in accordance with your interest in the partnership in which you
invest by considering all of the relevant facts and circumstances. To the extent
deductions or credits allocated by the partnership agreement exceed deductions
or credits which would be allowed under a reallocation of those tax items by the
IRS, you may incur a greater tax burden.

PARTNERSHIP BORROWINGS

Under the partnership agreement, only the managing general partner and its
affiliates may make loans to the partnerships. The use of partnership revenues
taxable to you to repay borrowings by your partnership could create income tax
liability for you in excess of your cash distributions from the partnership,
since repayments of principal are not deductible for federal income tax
purposes. In addition, interest on the loans will not be deductible unless the
loans are bona fide loans that will not be treated by the IRS as capital
contributions to the partnership by the managing general partner or its
affiliates in light of all of the surrounding facts and circumstances. Also, the
"at risk" amounts of you and the other investors in the partnership in which you
invest, which limit the amount of partnership losses you and the other investors
can claim as discussed in "- 'At Risk' Limitation on Losses," above, will not be
increased by the amount of any partnership borrowings from the managing general
partner or its affiliates, because you and the other investors will not bear any
risk of repaying the borrowings from your non-partnership assets, even if you
invest in the partnership as an investor general partner.

PARTNERSHIP ORGANIZATION AND OFFERING COSTS

Expenses connected with the offer and sale of units in a partnership, such as
the dealer-manager fee, sales commissions, and other selling expenses,
professional fees, and printing costs, which are charged under the partnership
agreement 100% to the managing general partner as organization and offering
costs, are not deductible. Although expenses incident to the creation of a
partnership may be amortized over a period of not less than 180 months, these
expenses also will be paid by the managing general partner as part of each
partnership's organization costs. Thus, any related deductions, which the
managing general partner does not anticipate will be material in amount as
compared to the total amount of subscription proceeds of each partnership, will
be allocated under the partnership agreement to the managing general partner.

TAX ELECTIONS

Each partnership may elect to adjust the basis of its property (other than cash)
on the transfer of a unit in the partnership by sale or exchange or on the death
of an investor, and on the distribution of property (other than money) by the
partnership to

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an investor (the Section 754 election). If the Section 754 election is made, the
transferees of the units are treated, for purposes of depreciation and gain, as
though they had acquired a direct interest in the partnership assets and the
partnership is treated for these purposes, on distributions to the investors, as
though it had newly acquired an interest in the partnership assets and therefore
acquired a new cost basis for the assets. Any election, once made, may not be
revoked without the consent of the IRS.

In this regard, due to the complexities and added expense of the tax accounting
required to implement a Section 754 election to adjust the basis of a
partnership's property when units are sold, taking into account the limitations
on the sale of the partnership's units as described in "Transferability of
Units," the managing general partner anticipates that the partnerships will not
make the Section 754 election, although they reserve the right to do so. Even if
the partnerships do not make the Section 754 election, however, the basis
adjustment described above is mandatory under the Code with respect to the
transferee partner only, if at the time a unit is transferred by sale or
exchange, or on the death of an investor, a partnership's adjusted basis in its
property exceeds the fair market value of the property by more than $250,000
immediately after the transfer of the unit. Similarly, a basis adjustment is
mandatory under the Code if a partnership distributes property in-kind to a
partner and the sum of the partner's loss on the distribution and the basis
increase to the distributed property is more than $250,000. I.R.C. Sections 734
and 743. In this regard, under Section 7.02 of the partnership agreement, a
partnership will not distribute its assets in-kind to its investors except to a
liquidating trust or similar entity for the benefit of its investors on the
dissolution and termination of the partnership, unless at the time of the
distribution its investors have been offered the election of receiving in-kind
property distributions, and you or any other investor in that partnership
accepts the offer after being advised of the risks associated with direct
ownership; or there are alternative arrangements in place which assure that you
and the other investors in that partnership will not, at any time, be
responsible for the operation or disposition of the partnership's properties.

If the basis of a partnership's assets must be adjusted as discussed above, the
primary effect on the partnership, other than the federal income tax
consequences discussed above, would be an increase in its administrative and
accounting expenses to make the required basis adjustments to its properties and
separately account for those adjustments after they are made. In this regard,
the partnerships will not make in-kind property distributions to their
respective investors except in the limited circumstances described above, and
the units will have no readily available market and will be subject to
substantial restrictions on their transfer. (See "Transferability of Units -
Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the
Partnership Agreement.") These factors will tend to reduce the likelihood that a
partnership will be required to make mandatory basis adjustments to its
properties.

In addition to the Section 754 election, each partnership may make various
elections under the Code for federal tax reporting purposes that could result in
the deductions of intangible drilling costs and depreciation, and the depletion
allowance, being treated differently for tax purposes than for accounting
purposes. Also, under Section 195 of the Code "start-up expenditures" may be
capitalized and amortized over a 180-month period. The term "start-up
expenditure" for this purpose includes any amount:

     o    paid or incurred in connection with:

          o    investigating the creation or acquisition of an active trade or
               business;

          o    creating an active trade or business; or

          o    any activity engaged in for profit and for the production of
               income before the day on which the active trade or business
               begins, in anticipation of that activity becoming an active trade
               or business; and

     o    that would be allowable as a deduction if paid or incurred in
          connection with the expansion of an existing business.

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If it is ultimately determined by the IRS or the courts that any of a
partnership's expenses constituted start-up expenditures, that partnership's
deductions for those expenses, including your share, if any, of those deductions
under the partnership agreement would be amortized over the 180-month period.

TAX RETURNS AND IRS AUDITS

The tax treatment of most partnership items is determined at the partnership,
rather than the partner level. Accordingly, you are required to treat the
partnership's tax items of the partnership in which you invest on your
individual federal income tax returns in a manner that is consistent with the
treatment of the partnership items on the partnership's federal information
income tax returns, unless you disclose to the IRS, by attaching the required
IRS notice to your individual federal income tax return, that your tax treatment
of the partnership's tax items on your personal federal income tax returns is
different from their partnership's tax treatment of those partnership tax items.
I.R.C. Sections 6221 and 6222. Treasury Regulations define partnership tax items
for this purpose as including distributive share items that must be allocated
among the partners, such as partnership liabilities, data pertaining to the
computation of the depletion allowance, and guaranteed payments. Treas. Reg.
Section 301.6231(a)(3)-1.

In most cases, the IRS must make an administrative determination as to
partnership tax items at the partnership level before conducting deficiency
proceedings against a partner, and the partners must file a request for an IRS
administrative determination with respect to the partnership before filing suit
for any credit or refund. Also, the period for assessing tax against you and the
other investors because of a partnership tax item may be extended by agreement
between the IRS and the managing general partner, which will serve as each
partnership's representative ("Tax Matters Partner") in all administrative tax
proceedings and tax litigation, if any, conducted at the partnership level.

The Tax Matters Partner may enter into a settlement on behalf of, and binding
on, any investor owning less than a 1% profits interest in a partnership if
there are more than 100 partners in the partnership, unless that investor timely
files a statement with the Secretary of the Treasury providing that the Tax
Matters Partner does not have authority to enter into a settlement agreement on
behalf of that investor. Based on its past experience, the managing general
partner anticipates that there will be more than 100 investors in each
partnership in which units are offered for sale. However, by executing the
Subscription Agreement you also are executing the partnership agreement if your
Subscription Agreement is accepted by the managing general partner. Under the
partnership agreement, you and the other investors in that partnership agree
that you will not form or exercise any right as a member of a notice group and
will not file a statement notifying the IRS that the Tax Matters Partner does
not have binding settlement authority. In addition, a partnership with at least
100 partners may elect to be governed under simplified tax reporting and audit
rules as an "electing large partnership." However, most limitations affecting
the calculation of the taxable income and tax credits of an electing large
partnership are applied at the partnership level and not the partner level.
Thus, the managing general partner does not anticipate that the partnerships
will make this election, although they reserve the right to do so.

All expenses of any tax proceedings involving a partnership and the managing
general partner acting as Tax Matters Partner, which might be substantial, will
be paid for by the partnership and not by the managing general partner from its
own funds. The managing general partner, however, is not obligated to contest
any adjustments made by the IRS to a partnership's federal information income
tax returns, even if the adjustment also would affect the individual federal
income tax returns of you and the other investors in that partnership. The
managing general partner will notify you and the other investors in your
partnership of any IRS audits or other tax proceedings involving your
partnership, and will provide you and the other investors any other information
regarding the proceedings as may be required by the partnership agreement or
law.

TAX RETURNS. Your individual income tax returns are your responsibility. Each
partnership will provide its investors with the tax information applicable to
their investment in the partnership necessary to prepare their tax returns.

PROFIT MOTIVE, IRS ANTI-ABUSE RULE AND JUDICIAL DOCTRINES LIMITATIONS ON
DEDUCTIONS

Under Section 183 of the Code, your ability to deduct your share of your
partnership's deductions could be limited or lost if the partnership lacks the
appropriate profit motive as determined from an examination of all facts and
circumstances at the time. Section 183 of the Code creates a presumption that an
activity is engaged in for profit if, in any three of five consecutive taxable
years, the gross income derived from the activity exceeds the deductions
attributable to the activity. Thus, if your

                                      130
partnership fails to show a profit in at least three out of five consecutive
years this presumption will not be available and the possibility that the IRS
could successfully challenge the partnership deductions claimed by you would be
substantially increased. The fact that the possibility of ultimately obtaining
profits is uncertain, standing alone, does not appear under the Treasury
Regulations to be sufficient grounds for the denial of losses. Also, if a
principal purpose of a partnership is to reduce substantially the partners'
federal income tax liability in a manner that is inconsistent with the intent of
the partnership rules of the Code, based on all the facts and circumstances, the
IRS is authorized under Treasury Regulation Section 1.701-2 to remedy the abuse.
Finally, under potentially relevant judicial doctrines such as the step
transaction, business purpose, economic substance, substance over form, and sham
transaction doctrines, tax deductions and tax credits from a transaction,
including each partnership's deduction for intangible drilling costs in 2007,
would be disallowed if your partnership were found by the IRS or the courts, to
have no economic substance apart from the tax benefits.

With respect to these issues, special counsel has given its opinions that the
partnerships will possess the requisite profit motive, and the IRS anti-abuse
rule in Treas. Reg. Section 1.701-2 and the potentially relevant judicial
doctrines listed above will not have a material adverse effect on the tax
consequences of an investment in a partnership by a typical investor as
described in special counsel's opinions. These opinions are based in part on the
results of the previous partnerships sponsored by the managing general partner
as set forth in "Prior Activities" and the managing general partner's
representations to special counsel, which are set forth in its tax opinion
letter attached as Exhibit 8 to the Registration Statement of which this
prospectus is a part. The managing general partner's representations include
that each partnership will be operated as described in this prospectus (see
"Management" and "Proposed Activities") and the principal purpose of each
partnership is to locate, produce and market natural gas and oil on a profitable
basis to its investors, apart from tax benefits, as described in this
prospectus. Also, see the information concerning the partnerships' proposed
drilling areas in "Proposed Activities," and the geological evaluations and
other information for the specific prospects proposed to be drilled by Atlas
America Public #16-2007(A) L.P. included in Appendix A to this prospectus, which
represent a portion of the prospects to be drilled if that partnership's
targeted maximum subscription proceeds of $100 million are received (which is
not binding on the partnership) as described in "Terms of the Offering -
Subscription to a Partnership." Also, the managing general partner has
represented that Appendix A in this prospectus will be supplemented or amended
to cover a portion of the specific prospects proposed to be drilled by Atlas
America Public #16-2007(B) L.P. if units in that partnership are offered to
prospective investors.

FEDERAL INTEREST AND TAX PENALTIES

Taxpayers must pay tax and interest on underpayments of federal income taxes and
the Code contains various penalties, including penalties for negligence and
substantial valuation misstatements with respect to their individual federal
income tax returns. In addition, there is a penalty equal to 20% of the amount
of a substantial understatement of federal income tax liability. There is a
substantial understatement by a noncorporate taxpayer if the correct income tax,
as finally determined by the IRS or the courts, exceeds the income tax liability
shown on the taxpayer's federal income tax return by the greater of 10% of the
correct tax, or $5,000. In the case of a corporation, other than an S
corporation, or a personal holding company as defined in Section 542 of the
Code, an understatement is substantial if it exceeds the lesser of: (i) 10% of
the correct tax (or, if greater, $10,000); or (ii) $10 million). I.R.C. Section
6662. A noncorporate taxpayer may avoid this penalty if the understatement was
not attributable to a "tax shelter," as that term is defined below, and there is
or was substantial authority for the taxpayer's tax treatment of the item that
caused the understatement, or if the relevant facts were adequately disclosed on
the taxpayer's individual federal income tax return or a statement attached to
the return and the taxpayer had a "reasonable basis" for the tax treatment of
that item. In the case of an understatement that is attributable to a "tax
shelter," however, which may include each of the partnerships for this purpose,
the penalty may be avoided by a non-corporate taxpayer only if there was
reasonable cause for the underpayment and the taxpayer acted in good faith, or
there is or was substantial authority for the taxpayer's treatment of the item
that caused the understatement, and the taxpayer reasonably believed that his or
her treatment of the item on his individual federal income tax return was more
likely than not the proper treatment.

For purposes of this penalty, the term "tax shelter" includes a partnership if a
significant purpose of the partnership is the avoidance or evasion of federal
income tax. Because the IRS has not explained what a "significant" purpose of
avoiding or evading federal income taxes means, special counsel cannot give an
opinion as to whether the partnerships are "tax shelters" as defined by the Code
for purposes of this penalty.

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Also, under Section 6662A of the Code, there is a 20% penalty for reportable
transaction understatements of federal income taxes on a taxpayer's individual
federal income tax return for any tax year. However, if the disclosure rules for
reportable transactions under the Code and the Treasury Regulations are not met
by the taxpayer, this penalty is increased from 20% to 30%, and a "reasonable
cause" exception to the penalty that is set forth in Section 6664(d) of the Code
will not be available to the taxpayer. Under Treasury Regulation Section
1.6011-4, a taxpayer who participates in a reportable transaction in any taxable
year must attach to his individual federal income tax return IRS Form 8886
"Reportable Transaction Disclosure Statement," and file it with the IRS as
directed in the Regulation, in order to comply with the disclosure rules.

A tax item is subject to the reportable transaction rules if the tax item is
attributable to:

     o    any listed transaction, which is a transaction that is the same as, or
          substantially similar to, a transaction that the IRS has publicly
          pronounced to be a tax avoidance transaction; or

     o    any of four additional types of reportable transactions, if a
          significant purpose of the transaction is federal income tax avoidance
          or evasion.

A "loss transaction" is one type of reportable transaction, but only if a
"significant" purpose of the transaction is federal income tax avoidance or
evasion. As set forth above, special counsel cannot give an opinion with respect
to whether or not each partnership has a "significant" purpose of avoiding or
evading federal income taxes, because the IRS has not explained what that phrase
means for purposes of this penalty. Subject to the foregoing, under Treasury
Regulation Section 1.6011-4(b)(5), there is a loss transaction if a partnership
or any of its noncorporate partners claims a loss under Section 165 of the Code
of at least $2 million, in the aggregate, in any taxable year of the
partnership, or at least $4 million, in the aggregate, over the partnership's
first six years. In this regard, however, special counsel has given its opinion
that the partnerships are not, and should not be in the future, reportable
transactions under the Code.

For purposes of the "loss transaction" rules, a Section 165 loss includes an
amount deductible under a provision of the Code that treats a transaction as a
sale or other disposition of property, or otherwise results in a deduction under
Section 165. A Section 165 loss includes, for example, a loss resulting from a
sale or exchange of a partnership interest, such as an investor's units in a
partnership. The amount of a Section 165 loss is adjusted for any salvage value
and for any insurance or other compensation received. However, a Section 165
loss for this purpose does not take into account offsetting gains or other
income limitations under the Code.

Each partnership will incur a tax loss in 2007 in excess of $2 million if the
partnership receives subscription proceeds of approximately $2,225,000 or more,
or a loss in excess of $4 million if subscription proceeds of at least
$4,450,000 are received by the partnership, due primarily to the amount of
intangible drilling costs for productive wells that each partnership intends to
claim as a deduction. Notwithstanding the foregoing, in special counsel's
opinion the partnerships' losses resulting from deductions claimed for
intangible drilling costs for productive wells properly should be treated as
losses under Section 263(c) of the Code and Treas. Reg. Section 1.612-4(a), and
should not be treated as Section 165 losses for purposes of the "loss
transaction" rules under Treas. Reg. 1.6011-4(b)(5). However, the partnerships
may incur losses under Section 165 of the Code, such as losses for the
abandonment by a partnership of:

     o    wells drilled that are nonproductive (i.e. a "dry hole"), if any, in
          which case the intangible drilling costs, the tangible costs, and
          possibly the lease acquisition costs of the abandoned wells would be
          deducted as Section 165 losses; and

     o    wells that have been operated until their commercial natural gas and
          oil reserves have been depleted, in which case the undepreciated
          tangible costs, if any, and possibly the lease acquisition costs,
          would be deducted as Section 165 losses.

In this regard, based primarily on its past experience (as shown in "Prior
Activities"), including Atlas America's 97% completion rate for wells drilled by
its previous development drilling partnerships in the Appalachian Basin (see "-
Management"), the managing general partner has represented the following:

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o    when a well is plugged and abandoned by a partnership, the salvage
          value of the well's equipment usually will cover a substantial amount
          of the costs of abandoning and reclaiming the well site;

     o    each partnership will drill relatively few non-productive wells (i.e.,
          "dry holes"), if any;

     o    each productive well drilled by a partnership will have a different
          productive life and the wells will not all be depleted and abandoned
          in the same taxable year;

     o    each productive well drilled by a partnership will produce for more
          than six years; and

     o    approximately 389 gross wells (which is approximately 355) net wells
          will be drilled by Atlas America Public #16-2007(A) L.P. if its
          targeted maximum subscription proceeds of $100 million are received,
          based on the managing general partner's estimate of the average
          weighted cost of drilling and completing the partnership's wells. (See
          "Compensation - Drilling Contracts).

STATE AND LOCAL TAXES

Each partnership will operate in states and localities that may impose a tax on
it, or on you and the partnership's other investors, based on the partnership's
assets or income or your share of its assets or income. Because of widespread
state budget deficits, several states are evaluating ways to subject
partnerships to entity-level taxation through the imposition of state income,
franchise or other forms of taxation. If any state were to impose a tax upon
your partnership as an entity, the cash available for distribution to you would
be reduced. Each partnership also may be subject to state income tax withholding
requirements on its income allocable to you and its other investors, whether or
not the revenues that created the income are distributed to you and its other
investors. Deductions and credits, including federal marginal well production
credits, if any, which may be available to you for federal income tax purposes,
may not be available to you for state or local income tax purposes. If you
reside in a state or locality that imposes income taxes on its residents, you
likely will be required under those income tax laws to include your share of
your partnership's net income or net loss in determining your reportable income
for state or local tax purposes in the jurisdiction in which you reside. To the
extent that you pay tax to another state because of partnership operations
within that state, you may be entitled to a deduction or credit against tax owed
to your state of residence with respect to the same income. Also, due to a
partnership's operations in a state or local jurisdiction, state or local estate
or inheritance taxes may be payable on the death of an investor in addition to
taxes imposed by his own domicile.

Each partnership's units may be sold in all 50 states and the District of
Columbia and other jurisdictions, and it is not practical for special counsel to
evaluate the many different state and local tax laws that may affect one or more
of a partnership's investors with respect to their investment in the
partnership. You are urged to seek advice based on your particular circumstances
from an independent tax advisor to determine the effect state and local taxes,
including gift and death taxes as well as income taxes, may have on you in
connection with an investment in a partnership.

SEVERANCE AND AD VALOREM (REAL ESTATE) TAXES

Each partnership will incur various ad valorem or severance taxes imposed by
state or local taxing authorities on its natural gas and oil wells and/or
natural gas and oil production from the wells. These taxes will reduce the
amount of each partnership's cash available for distribution to you and its
other investors.

SOCIAL SECURITY BENEFITS AND SELF-EMPLOYMENT TAX

A limited partner's share of income or loss from a partnership is excluded from
the definition of "net earnings from self-employment." No increased benefits
under the Social Security Act will be earned by limited partners and if any
limited partners are currently receiving Social Security benefits, their shares
of partnership taxable income will not be taken into account in determining any
reduction in benefits because of "excess earnings."

An investor general partner's share of income or loss from a partnership will
constitute "net earnings from self-employment" for these purposes. The ceiling
for social security tax of 12.4% in 2006 was $94,200, which will be adjusted
annually for inflation in 2007 and subsequent years. There is no ceiling for
medicare tax of 2.9%. Self-employed individuals can deduct one-half of their
self-employment tax.

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FARMOUTS

Under a farmout by a partnership, if a property interest, other than an interest
in the drilling unit assigned to the partnership well in question, is earned by
the farmee (anyone other than the partnership) from the farmor (the partnership)
as a result of the farmee drilling or completing the well, then the farmee must
recognize income equal to the fair market value of the outside interest earned,
and the farmor must recognize gain or loss on a deemed sale equal to the
difference between the fair market value of the outside interest and the
farmor's tax basis in the outside interest. Neither the farmor nor the farmee
would have received any cash to pay the tax. The managing general partner has
represented that it will attempt to eliminate or reduce any gain to a
partnership from a farmout, if any. However, if the IRS claims that a farmout by
a partnership results in taxable income to the partnership and its position is
ultimately sustained, you and the other investors in that partnership would be
required to include your share of the resulting taxable income on your
individual income tax returns, even though the partnership and you and the other
investors in that partnership received no cash from the farmout.

FOREIGN PARTNERS

Each partnership will be required to withhold and pay income tax to the IRS at
the highest rate under the Code applicable to partnership income allocable to
its foreign investors, even if no cash distributions are made to them. In the
event of overwithholding, a foreign investor must seek a refund on his
individual United States federal income tax return. For withholding purposes, a
foreign investor means an investor who is not a United States person and
includes a nonresident alien individual, a foreign corporation, a foreign
partnership, and a foreign trust or estate, unless the investor has certified to
his partnership the investor's status as a U.S. person on Form W-9 or any other
form permitted by the IRS for that purpose.

Foreign investors are urged to seek advice based on their particular
circumstances from an independent tax advisor regarding the applicability of
these rules and the other tax consequences of an investment in a partnership to
them.

ESTATE AND GIFT TAXATION

There is no federal tax on lifetime or testamentary transfers of property
between spouses. The gift tax annual exclusion amount was $12,000 per donee in
2007, which will be adjusted in 2007 and subsequent years for inflation. Under
the Economic Growth and Tax Relief Reconciliation Act of 2001 (the "2001 Tax
Act"), the maximum estate and gift tax rate is 45% from 2007 through 2009.
Estates of $2.0 million or less in 2007, which increases to estates of $3.5
million or less in 2009, are not subject to federal estate tax to the extent
those exemption amounts (i.e., unified credit amounts) were not previously used
by the decedent to reduce gift taxes on any lifetime gifts in excess of the
applicable annual exclusion amount for gifts. Under the 2001 Tax Act, the
federal estate tax will be repealed in 2010, and the maximum gift tax rate in
2010 will be 35%. In 2011, however, the federal estate and gift taxes are
scheduled to be reinstated under the rules in effect before the 2001 Tax Act was
enacted.

CHANGES IN THE LAW

Your tax benefits from an investment in a partnership may be affected by changes
in the tax laws. For example, in 2003 the top four federal income tax brackets
for individuals were reduced through December 31, 2010, including reducing the
top bracket to 35% from 38.6%. The lower federal income tax rates will reduce to
some degree the amount of taxes you can save by virtue of your share of your
partnership's deductions for intangible drilling costs, depletion and
depreciation, and marginal well production credits, if any. On the other hand,
the lower federal income tax rates also will reduce the amount of federal income
tax liability incurred by you on your share of your partnership's net income.
However, the federal income tax brackets discussed above could be changed again,
even before 2011, and other changes in the tax laws could be made which would
affect your tax benefits from an investment in a partnership.

You are urged to seek advice based on your particular circumstances from an
independent tax advisor with respect to the impact of recent federal tax
legislation on an investment in a partnership and the status of federal and
state legislative, regulatory or administrative tax developments and tax
proposals and their potential effect on the tax consequences to you of an
investment in a partnership.

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SUMMARY OF PARTNERSHIP AGREEMENT

The rights and obligations of the managing general partner and you and the other
investors in a partnership are governed by the form of partnership agreement, a
copy of which attached as Exhibit (A) to this prospectus. You are urged to
thoroughly review the partnership agreement before you decide to invest in a
partnership. The following is a summary of the material provisions in the
partnership agreement that are not covered elsewhere in this prospectus. Thus,
this prospectus summarizes all of the material provisions of the partnership
agreement.

LIABILITY OF LIMITED PARTNERS

Each partnership will be governed by the Delaware Revised Uniform Limited
Partnership Act. If you invest as a limited partner, then generally you will not
be liable to third-parties for the obligations of your partnership unless you:

     o    also invest as an investor general partner;

     o    take part in the control of the partnership's business in addition to
          the exercise of your rights and powers as a limited partner; or

     o    fail to make a required capital contribution to the extent of the
          required capital contribution.

In addition, you may be required to return any distribution you receive from a
partnership if you knew at the time the distribution was made that it was
improper because it rendered the partnership insolvent.

AMENDMENTS

Amendments to the partnership agreement of a partnership may be proposed in
writing by:

     o    the managing general partner and adopted with the consent of investors
          whose units equal a majority of the total units in the partnership; or

     o    investors whose units equal 10% or more of the total units in the
          partnership and adopted by an affirmative vote of investors whose
          units equal a majority of the total units in the partnership.

The partnership agreement of each partnership may also be amended by the
managing general partner without the consent of the investors for certain
limited purposes. However, an amendment that materially and adversely affects
the investors can only be made with the consent of the affected investors.

NOTICE

The following provisions apply regarding notices:

     o    when the managing general partner gives you and other investors notice
          it begins to run from the date of mailing the notice and is binding
          even if it is not received;

     o    the notice periods are frequently quite short, a minimum of 22
          calendar days, and apply to matters that may seriously affect your
          rights; and

     o    if you fail to respond in the specified time to the managing general
          partner's second request for approval of or concurrence in a proposed
          action, then you will conclusively be deemed to have approved the
          action unless the partnership agreement expressly requires your
          affirmative approval.

VOTING RIGHTS

Other than as set forth below, you generally will not be entitled to vote on any
partnership matters at any partnership meeting. At any time, however, investors
whose units equal 10% or more of the total units in a partnership may call a
meeting to vote, or vote without a meeting, on the matters set forth below
without the concurrence of the managing general

                                      135
partner. On the matters being voted on you are entitled to one vote per unit or
if you own a fractional unit that fraction of one vote equal to the fractional
interest in the unit. Investors whose units equal a majority of the total units
in a partnership may vote to:

     o    dissolve the partnership;

     o    remove the managing general partner and elect a new managing general
          partner;

     o    elect a new managing general partner if the managing general partner
          elects to withdraw from the partnership;

     o    remove the operator and elect a new operator;

     o    approve or disapprove the sale of all or substantially all of the
          partnership's assets;

     o    cancel any contract for services with the managing general partner,
          the operator, or their affiliates without penalty on 60 days notice;
          and

     o    amend the partnership agreement, however, any amendment may not:

          o    without the approval of you or the managing general partner
               increase the duties or liabilities of you or the managing general
               partner, or increase or decrease the profits or losses or
               required capital contribution of you or the managing general
               partner; or

          o    without the unanimous approval of all investors in the
               partnership, affect the classification of partnership income and
               loss for federal income tax purposes.

The managing general partner, its officers, directors, and affiliates may also
subscribe for units in each partnership on a discounted basis, and they may vote
on all matters, including the issues set forth above, other than:

     o    removing the managing general partner and operator; and

     o    any transaction between the managing general partner or its affiliates
          and the partnership.

Any units owned by the managing general partner and its affiliates will not be
included in determining the requisite number of units necessary to approve any
partnership matter on which the managing general partner and its affiliates may
not vote or consent.

ACCESS TO RECORDS

You will have access to all records of your partnership at any reasonable time
on adequate notice. However, logs, well reports, and other drilling and
operating data may be kept confidential for reasonable periods of time. Also,
your ability to obtain the list of investors is subject to additional
requirements set forth in the partnership agreement.

WITHDRAWAL OF MANAGING GENERAL PARTNER

After 10 years the managing general partner may voluntarily withdraw as managing
general partner of a partnership for any reason by giving 120 days' written
notice to you and the other investors in the partnership. Although the
withdrawing managing general partner is not required to provide a substitute
managing general partner, a new managing general partner may be substituted by
the affirmative vote of investors whose units equal a majority of the total
units in the partnership. If the investors, however, choose not to continue the
partnership and do not select a substitute managing general partner, then the
partnership would dissolve and terminate, which could result in adverse tax and
other consequences to you.

                                      136
Also, the managing general partner may assign its general partner interest in
the partnership to its affiliates, and it may withdraw a property interest in
the form of a working interest in the partnership's wells equal to or less than
its revenue interest at any time if the withdrawal is:

     o    to satisfy the bona fide request of its creditors; or

     o    approved by investors in the partnership whose units equal a majority
          of the total units.

(See "Management - Managing General Partner and Operator" and "Conflicts of
Interest - Conflicts Regarding the Managing General Partner Withdrawing or
Assigning an Interest."

RETURN OF SUBSCRIPTION PROCEEDS IF FUNDS ARE NOT INVESTED IN TWELVE MONTHS

Although the managing general partner anticipates that each partnership will
spend all of its subscription proceeds soon after the offering of the
partnership closes, each partnership will have 12 months in which to use or
commit its subscription proceeds to drilling activities. If within the 12-month
period the partnership has not used, or committed for use, all of its
subscription proceeds, then the managing general partner will distribute the
remaining subscription proceeds to you and the other investors in the
partnership in accordance with your respective subscription amounts as a return
of capital.

                   SUMMARY OF DRILLING AND OPERATING AGREEMENT

The managing general partner will serve as the operator under the drilling and
operating agreement, Exhibit (II) to the partnership agreement. The operator may
be replaced at any time on 60 days' advance written notice by the managing
general partner acting on behalf of a partnership on the affirmative vote of
investors whose units equal a majority of the total units in the partnership.
You are urged to thoroughly review the drilling and operating agreement before
you decide to invest in a partnership. The following is a summary of the
material provisions of the drilling and operating agreement that are not covered
elsewhere in this prospectus. Thus, this prospectus summarizes all of the
material provisions of the drilling and operating agreement.

The drilling and operating agreement includes the material provisions set forth
below.

     o    The operator's right to resign after five years.

     o    The operator's right beginning one year after a partnership well
          begins producing to retain $200 per month to cover future plugging and
          abandonment costs of the well.

     o    The grant of a first lien and security interest in the wells and
          related production to secure payment of amounts due to the operator by
          a partnership.

     o    The prescribed insurance coverage to be maintained by the operator.

     o    Limitations on the operator's authority to incur extraordinary costs
          with respect to producing wells in excess of $5,000 per well.

     o    Restrictions on the partnership's ability to transfer its interest in
          fewer than all wells unless the transfer is of an equal undivided
          interest in all of the wells.

     o    The limitation of the operator's liability to a partnership except for
          the operator's:

          o    violations of law;

          o    negligence or misconduct by it, its employees, agents or
               subcontractors; or

          o    breach of the drilling and operating agreement.

                                      137
o    The excuse for nonperformance by the operator due to force majeure
          which generally means acts of God, catastrophes and other causes which
          preclude the operator's performance and are beyond its control.

                              REPORTS TO INVESTORS

Under the partnership agreement for each partnership you and certain state
securities commissions will be provided the reports and information set forth
below for your partnership, which your partnership will pay as a direct cost.

     o    Beginning with the calendar year in which your partnership closes, you
          will be provided an annual report within 120 days after the close of
          the calendar year, and beginning with the following calendar year, a
          report within 75 days after the end of the first six months of its
          calendar year, containing at least the following information.

          o    Audited financial statements of the partnership prepared on an
               accrual basis in accordance with generally accepted accounting
               principles with a reconciliation for information furnished for
               income tax purposes. Independent certified public accountants
               will audit the financial statements to be included in the annual
               report, but semiannual reports will not be audited.

          o    A summary of the total fees and compensation paid by the
               partnership to the managing general partner, the operator, and
               their affiliates. In this regard, the independent certified
               public accountant will provide written attestation annually,
               which will be included in the annual report, that the method used
               to make allocations was consistent with the method described in
               Section 4.04(a)(2)(c) of the partnership agreement and that the
               total amount of costs allocated did not materially exceed the
               amounts actually incurred by the managing general partner.

               If the managing general partner subsequently decides to allocate
               expenses in a manner different from that described in Section
               4.04(a)(2)(c) of the partnership agreement, then the change must
               be reported to you and the other investors with an explanation of
               the reason for the change and the basis used for determining the
               reasonableness of the new allocation method.

          o    A description of each prospect owned by the partnership,
               including the cost, location, number of acres, and the interest.

          o    A list of the wells drilled or abandoned by the partnership
               indicating:

               o    whether each of the wells has or has not been completed; and

               o    a statement of the cost of each well completed or abandoned.

          o    A description of all farmouts, farmins, and joint ventures.

          o    A schedule reflecting:

               o    the total partnership costs;

               o    the costs paid by the managing general partner and the costs
                    paid by the investors;

               o    the total partnership revenues; and

               o    the revenues received or credited to the managing general
                    partner and the revenues received or credited to you and the
                    other investors.

                                      138
o    On request the managing general partner will provide you the
          information specified by Form 10-Q (if that report is required to be
          filed with the SEC) within 45 days after the close of each quarterly
          fiscal period. Also, this information is available at the SEC website
          www.sec.gov.

     o    By March 15 of each year you will receive the information that is
          required for you to file your federal and state income tax returns.

     o    Beginning with the second calendar year after your partnership closes,
          and every year thereafter, you will receive a computation of the
          partnership's total natural gas and oil proved reserves and its dollar
          value. The reserve computations will be based on engineering reports
          prepared by the managing general partner and reviewed by an
          independent expert.

                               PRESENTMENT FEATURE

Beginning with the fifth calendar year after your partnership closes, you and
the other investors in your partnership may present your units to the managing
general partner to purchase your units. However, you are not required to offer
your units to the managing general partner, and you may receive a greater return
if you retain your units. The managing general partner will not purchase less
than one unit unless the fractional unit represents your entire interest in the
partnership.

The managing general partner has no obligation or intention to establish a
reserve to satisfy the presentment feature and it may immediately suspend the
presentment obligation by notice to you if it determines, in its sole
discretion, that it:

     o    does not have the necessary cash flow; or

     o    cannot borrow funds for this purpose on terms it deems reasonable.

If fewer than all units presented at any time are to be purchased by the
managing general partner, then the units to be purchased will be selected by
lot.

The managing general partner's obligation to purchase the units presented may be
discharged for its benefit by a third-party or an affiliate. If you sell your
unit it will be transferred to the party who pays for it, and you will be
required to deliver an executed assignment of your unit along with any other
documents that the managing general partner requests. Your presentment of your
units to the managing general partner for purchase is subject to the following
conditions:

     o    the managing general partner will not purchase more than 5% of the
          total outstanding units in a partnership in any calendar year;

     o    your presentment request must be made within 120 days of the
          partnership reserve report discussed below;

     o    in accordance with Treas. Reg. Section 1.7704-1(f) the managing
          general partner may not purchase your units until at least 60 calendar
          days after you notify the partnership in writing of your intent to
          present your units for purchase; and

     o    the purchase of your units will not be considered effective until the
          presentment price has been paid to you in cash.

The amount of the presentment price for your units that is attributable to a
partnership's natural gas and oil reserves, as discussed below, will be
determined based on the last reserve report prepared by the managing general
partner and reviewed by an independent expert. Beginning with the second
calendar year after your partnership closes and every year thereafter, the
managing general partner will estimate the present worth of future net revenues
attributable to your partnership's interest in proved reserves. In making this
estimate, the managing general partner will use:

                                      139
o    a 10% discount rate;

     o    a constant oil price; and

     o    base natural gas prices on the existing natural gas contracts at the
          time of the presentment.

Your presentment price will be based on your share of your partnership's net
assets and liabilities as described below, based on the ratio that your number
of units bears to the total number of units in your partnership. The presentment
price will include the sum of the following partnership items:

     o    an amount based on 70% of the present worth of future net revenues
          from the proved reserves determined as described above;

     o    cash on hand;

     o    prepaid expenses and accounts receivable, less a reasonable amount for
          doubtful accounts; and

     o    the estimated market value of all assets not separately specified
          above, determined in accordance with standard industry valuation
          procedures.

There will be deducted from the foregoing sum the following partnership items:

     o    an amount equal to all debts, obligations, and other liabilities,
          including accrued expenses; and

     o    any distributions made to you between the date of your presentment
          request and the date the presentment price is paid to you. However, if
          any cash distributed to you by the partnership, after your presentment
          request was derived from the sale of oil, natural gas, or a producing
          property the amount of those cash distributions will be discounted at
          the same rate used to take into account the risk factors employed to
          determine the present worth of the partnership's proved reserves for
          purposes of determining the reduction of the presentment price.

The presentment price may be further adjusted by the managing general partner
for estimated changes from the date of the reserve report discussed above to the
date of payment of the presentment price to you due to the following:

     o    the production or sales of, or additions to, reserves and lease and
          well equipment, sale or abandonment of leases, and similar matters
          occurring before the presentment request; and

     o    any of the following occurring before payment of the presentment price
          to you;

          o    changes in well performance;

          o    increases or decreases in the market price of oil, natural gas,
               or other minerals;

          o    revision of regulations relating to the importing of
               hydrocarbons; and

          o    changes in income, ad valorem, and other tax laws such as
               material variations in the provisions for depletion; and

          o    similar matters.

As of September 15 2006, approximately 230 units have been presented to the
managing general partner for purchase in its previous 53 limited partnerships.

                                      140
TRANSFERABILITY OF UNITS

RESTRICTIONS ON TRANSFER IMPOSED BY THE SECURITIES LAWS, THE TAX LAWS AND THE
PARTNERSHIP AGREEMENT

Your ability to sell or otherwise transfer your units in your partnership is
restricted by the securities laws, the tax laws, and the partnership agreement
as described below. Also, the sale or other transfer of your units may create
negative tax consequences to you as described in "Federal Income Tax
Consequences - Disposition of Units."

First, due to the tax laws, the partnership agreement provides that you will not
be able to sell, assign, exchange, or transfer your unit if it would, in the
opinion of counsel for the partnership, result in the following:

     o    the termination of your partnership for tax purposes; or

     o    your partnership being treated as a "publicly traded" partnership for
          tax purposes.

Second, under the partnership agreement sales or other transfers of the units
are subject to the following additional limitations:

     o    except as provided by operation of law, the partnership will recognize
          the transfer of only one or more whole units unless you own less than
          a whole unit, in which case your entire fractional interest must be
          transferred;

     o    the costs and expenses associated with the transfer must be paid by
          the person transferring the unit;

     o    the form of transfer must be in a form satisfactory to the managing
          general partner; and

     o    the terms of the transfer must not contravene those of the partnership
          agreement.

Your transfer of a unit will not:

     o    relieve you of your responsibility for any obligations related to your
          units under the partnership agreement;

     o    grant rights under the partnership agreement as among your
          transferees, to more than one party unanimously designated by the
          transferees to the managing general partner; nor

     o    require an accounting of the partnership by the managing general
          partner.

If the assignee of the unit does not become a substituted partner as described
below in "- Conditions to Becoming a Substitute Partner," the transfer will be
effective as of midnight of the last day of the calendar month in which it is
made or, at the managing general partner's election, 7:00 A.M. of the following
day.

Finally, you will not be able to sell, assign, pledge, hypothecate, or transfer
your unit if the managing general partner requires, in its sole discretion, that
you must provide an opinion of counsel acceptable to the managing general
partner that the registration and qualification under any applicable federal or
state securities laws are not required.

CONDITIONS TO BECOMING A SUBSTITUTE PARTNER

An assignee of a unit will not be entitled to any of the rights granted to a
partner under the partnership agreement, other than the right to receive all or
part of the share of the profits, losses, income, gain, credits and cash
distributions or returns of capital to which his assignor would otherwise be
entitled, unless the assignee becomes a substituted partner in accordance with
the provisions set forth below. The conditions to become a substitute partner
are as follows:

     o    the assignor gives the assignee the right;

     o    the assignee pays all costs and expenses incurred in connection with
          the substitution; and

                                      141
o    the assignee executes and delivers, in a form acceptable to the
          managing general partner, the instruments necessary to establish that
          a legal transfer has taken place and to confirm his agreement to be
          bound by all of the terms and provisions of the partnership agreement.

A substitute partner is entitled to all of the rights of full ownership of the
assigned units, including the right to vote. Each partnership will amend its
records at least once each calendar quarter to effect the substitution of
substituted partners.

                              PLAN OF DISTRIBUTION

COMMISSIONS

The units in each partnership will be offered on a "best efforts" basis by
Anthem Securities, which is an affiliate of the managing general partner, acting
as dealer-manager and by other selected registered broker/dealers that are
members of the NASD acting as selling agents. Anthem Securities was formed for
the purpose of serving as dealer-manager of partnerships sponsored by the
managing general partner and became an NASD member firm in April, 1997.

The dealer-manager will manage and oversee the offering of the units as
described above. Best efforts generally means that the dealer-manager and
selling agents will not guarantee that a certain number of units will be sold.
Units may also be sold by the officers and directors of the managing general
partner in those states where they are licensed to do so or are exempt from
licensing. All offers and sales of units by the managing general partner's
remaining officers and directors will be made under the SEC safe harbor from
broker/dealer registration provided by Rule 3a4-1.

Subject to the exceptions described below, the dealer-manager will receive on
each unit sold:

     o    a 2.5% dealer-manager fee;

     o    a 7% sales commission; and

     o    an up to .5% reimbursement of the selling agent's bona fide due
          diligence expenses.

All of the reimbursement of the selling agents' bona fide due diligence expenses
and generally all of the 7% sales commission will be reallowed by the
dealer-manager to the selling agents. With respect to the up to .5%
reimbursement of a selling agent's bona fide due diligence expenses, any bill
presented by a selling agent to the dealer-manager for reimbursement of costs
associated with its due diligence activities must be for actual costs, including
overhead, incurred by the selling agent and may not include a profit margin. It
is the responsibility of the managing general partner and the dealer-manager to
ensure compliance with the above guideline. If the selling agent provides the
dealer-manager an itemized bill for actual due diligence expenses which is in
excess of .5%, then the excess over .5% will not be included within the 10%
compensation guideline, but instead will be included within the 4.5%
organization and offering cost guideline under NASD Conduct Rule 2810.

From the 2.5% dealer-manager fee, the dealer-manager may pay up to a .5%
marketing fee if the selling agent meets certain sales thresholds and provides
marketing support. Additionally, the Dealer-Manager may use a portion of its
Dealer-Manager fee to pay for permissible non-cash compensation. Under Rule 2810
of the NASD Conduct Rules, non-cash compensation means any form of compensation
received in connection with the sale of the units that is not cash compensation,
including but not limited to merchandise, gifts and prizes, travel expenses,
meals and lodging. Permissible non-cash compensation includes the following:

     o    an accountable reimbursement for training and education meetings for
          associated persons of the selling agents;

     o    gifts that do not exceed $100 per year and are not preconditioned on
          achievement of a sales target;

                                      142
o    an occasional meal, a ticket to a sporting event or the theater, or
          comparable entertainment which is neither so frequent nor so extensive
          as to raise any question of propriety and is not preconditioned on
          achievement of a sales target; and

     o    contributions to a non-cash compensation arrangement between a selling
          agent and its associated persons, provided that neither the managing
          general partner nor the dealer-manager directly or indirectly
          participates in the selling agent's organization of a permissible
          non-cash compensation arrangement.

In no event shall a selling agent receive non-cash compensation and the
marketing fee if it represents more than .5% per unit.

The managing general partner is also using the services of wholesalers who are
employed by it or its affiliates and are registered through Anthem Securities.
The wholesalers include four Regional Marketing Directors. A portion of the 2.5%
dealer-manager fee will be reallowed to the affiliated wholesalers for
subscriptions obtained through their efforts and their reimbursement of
expenses. The dealer-manager will retain the remainder of the dealer-manager fee
not reallowed to the wholesalers or as described in the prior paragraph.

The offering will be made in compliance with Rule 2810 of the NASD Conduct Rules
and all compensation, including non-cash compensation, to broker/dealers and
wholesalers, regardless of the source, will be limited to 10% of the gross
proceeds of the offering plus the .5% reimbursement for bona fide due diligence
expenses on each subscription. Also, the offering will be made in compliance
with Rule 2810(b)(2)(C) of the NASD Conduct Rules and the broker/dealers and
wholesalers will not execute a transaction for the purchase of units in a
discretionary account without the prior written approval of the transaction by
the customer. Finally, the offering will be conducted in compliance with SEC
Rule 15c2-4.

Subject to the following, you and the other investors will pay $10,000 per unit
and generally will share costs, revenues, and distributions in the partnership
in which you invest in proportion to your respective number of units. However,
the subscription price for certain investors will be reduced as set forth below:

     o    the subscription price for the managing general partner, its officers,
          directors, and affiliates, and investors who buy units through the
          officers and directors of the managing general partner, will be
          reduced by an amount equal to the 2.5% dealer-manager fee, the 7%
          sales commission and the .5% reimbursement for bona fide due diligence
          expenses, which will not be paid with respect to these sales; and

     o    the subscription price for registered investment advisors and their
          clients, and selling agents and their registered representatives and
          principals, will be reduced by an amount equal to the 7% sales
          commission, which will not be paid with respect to these sales.

No more than 5% of the total units in each partnership may be sold with the
discounts described above. These investors who pay a reduced price for their
units generally will share in a partnership's costs, revenues, and distributions
on the same basis as the other investors who pay $10,000 per unit as discussed
in "Participation in Costs and Revenues - Allocation and Adjustments Among
Investors." Although the managing general partner and its affiliates may buy up
to 5% of the units, they do not currently anticipate buying any units. If they
do buy units, then those units will not be applied towards the minimum
subscription proceeds required for a partnership to begin operations.

To help assure an orderly market for the units, the managing general partner,
the dealer-manager and the selling agents may use such methods as they deem
appropriate to allocate units among interested investors if they anticipate that
demand for units will exceed the available supply, provided that no changes to
compensation may be made. These methods may include, but will not be limited to:

     o    allocations of units to selling agents;

     o    priority acceptance of subscriptions from previous investors in
          partnerships sponsored by the managing general partner;

                                      143
o    priority treatment for investors whose subscriptions were declined by
          earlier partnerships sponsored by the managing general partner because
          the number of units available was not sufficient to accommodate their
          subscriptions; or

     o    any other methods as may be approved by the managing general partner.

After the minimum subscription proceeds are received in a partnership and the
checks have cleared the banking system, the dealer-manager fee and the sales
commissions will be paid to the dealer-manager and selling agents approximately
every two weeks until the offering closes.

INDEMNIFICATION

The dealer-manager is an underwriter as that term is defined in the 1933 Act and
the sales commissions and dealer-manager fees will be deemed underwriting
compensation. The managing general partner and the dealer-manager have agreed to
indemnify each other, and it is anticipated that the dealer-manager and each
selling agent will agree to indemnify each other against certain liabilities,
including liabilities under the 1933 Act.

                                 SALES MATERIAL

In addition to the prospectus, the managing general partner intends to use the
following sales material with the offering of the units:

     o    a flyer entitled "Atlas America Public #16-2007 Program";

     o    an article entitled "Tax Rewards with Oil and Gas Partnerships";

     o    a brochure of tax scenarios entitled "How an Investment in Atlas
          America Public #16-2007 Program Can Help Achieve an Investor's Tax
          Objectives";

     o    a booklet entitled "Outline of Tax Consequences of Oil and Gas
          Drilling Programs";

     o    a brochure entitled "Investment Insights - Tax Time";

     o    a brochure entitled "Frequently Asked Questions";

     o    a brochure entitled "The Drilling Process"; and

     o    possibly other supplementary materials.

The managing general partner has not authorized the use of other sales material
and the offering of units is made only by means of this prospectus. The sales
material is subject to the following considerations:

     o    it must be preceded or accompanied by this prospectus;

     o    it is not complete;

     o    it does not contain any information which is inconsistent with this
          prospectus; and

     o    it should not be considered a part of or incorporated into this
          prospectus or the registration statement of which this prospectus is a
          part.

In addition, supplementary materials, including prepared presentations for group
meetings, must be submitted to the state administrators before they are used and
their use must either be preceded by or accompanied by a prospectus. Also, all

                                       144
advertisements of, and oral or written invitations to, "seminars" or other group
meetings at which the units are to be described, offered, or sold will clearly
indicate the following:

     o    that the purpose of the meeting is to offer the units for sale;

     o    the minimum purchase price of the units;

     o    the suitability standards to be employed; and

     o    the name of the person selling the units.

Also, no cash, merchandise, or other items of value may be offered as an
inducement to you or any other prospective investor to attend the meeting. All
written or prepared audiovisual presentations, including scripts prepared in
advance for oral presentations to be made at the meetings, must be submitted to
the state administrators within a prescribed review period. These provisions,
however, will not apply to meetings consisting only of the registered
representatives of the selling agents.

You should rely only on the information contained in this prospectus in making
your investment decision. No one is authorized to provide you with information
that is different.

                                 LEGAL OPINIONS

Kunzman & Bollinger, Inc., has issued its opinion to the managing general
partner regarding the validity and due issuance of the units, including
assessibility, and its opinion on the material and any significant federal tax
issues involving individual typical investors in the partnerships. However, the
factual statements in this prospectus are those of the partnerships or the
managing general partner, and counsel has not given any opinions with respect to
any of the tax or other legal aspects of this offering except as expressly set
forth above.

                                     EXPERTS

The financial statements included in this prospectus for Atlas Resources, LLC,
the managing general partner, as of and for the years ended September 30, 2005
and 2004 and the balance sheet for Atlas America Public #16-2007(A) L.P. have
been audited by Grant Thornton LLP, as of the dates indicated in its reports
which appear elsewhere in this prospectus. These financial statements have been
included in this prospectus in reliance on the reports of Grant Thornton LLP on
the authority of that firm as an expert in accounting and auditing.

The information concerning the estimated future net cash flows from proved
reserves presented under "Prior Activities - Table 3 Investor Operating
Results-Including Expenses" was reviewed by Wright & Company, Inc., Brentwood,
Tennessee, independent petroleum consultants, which is not affiliated with the
managing general partner or its affiliates, and is included in this prospectus
in reliance on Wright & Company, Inc. as an expert in petroleum consulting.

The geologic evaluations of United Energy Development Consultants, Inc., which
is not affiliated with the managing general partner or its affiliates, appearing
elsewhere in this prospectus have been included in this prospectus on the
authority of United Energy Development Consultants, Inc. as an expert with
respect to the matters covered by the evaluations and in the giving of the
evaluations.

                                   LITIGATION

The managing general partner knows of no litigation pending or threatened to
which the managing general partner or the partnerships are subject or may be a
party, which it believes would have a material adverse effect on the
partnerships or their business, and no such proceedings are known to be
contemplated by governmental authorities or other parties.

                                       145
FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL PARTNER AND ATLAS AMERICA
                             PUBLIC #16-2007(A) L.P.

Financial information concerning the managing general partner and the second
partnership in the program, Atlas America Public #16-2007(A) L.P., is reflected
in the following financial statements. With respect to the managing general
partner's financial information, the managing general partner was changed from a
corporation to a limited liability company in March, 2006. (See "Management -
Managing General Partner and Operator.")

The securities offered by this prospectus are not securities of, nor are you
acquiring an interest in the managing general partner, its affiliates, or any
other entity other than the partnership in which you purchase units.

                          INDEX TO FINANCIAL STATEMENTS

ATLAS AMERICA PUBLIC #16-2007(A) L.P. FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm dated September
   30, 2006..............................................................    F-1
Balance Sheet as of September 30, 2006...................................    F-2
Notes to Financial Statement dated September 30, 2006....................    F-3

ATLAS RESOURCES, INC. AND SUBSIDIARY AUDITED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm dated January
   6, 2006 (except for Note 10, as to which the date is April 7, 2006)...    F-8
Atlas Resources, Inc. and Subsidiary Consolidated Balance Sheets for
   the years ended September 30, 2005 and 2004...........................    F-9
Atlas Resources, Inc. and Subsidiary Consolidated Statements of Income
   for the years ended September 30, 2005 and 2004.......................   F-10
Atlas Resources, Inc. and Subsidiary Consolidated Statements of Changes
   in Stockholder's Equity for the years ended September 30, 2005 and
   2004..................................................................   F-11
Atlas Resources, Inc. and Subsidiary Consolidated Statements of Cash
   Flows for the years ended September 30, 2005 and 2004.................   F-12
Atlas Resources, Inc. and Subsidiary Notes to Consolidated Financial
   Statements dated January 6, 2006 (except for Note 10, as to which
   the date is April 7, 2006)............................................   F-13

ATLAS RESOURCES, LLC AND SUBSIDIARY CONSOLIDATED FINANCIAL STATEMENTS
   (UNAUDITED) AS OF JUNE 30, 2006

Atlas Resources, LLC and Subsidiary Consolidated Balance Sheets
   (Unaudited) as of June 30, 2006 and September 30, 2005................   F-29
Atlas Resources, LLC and Subsidiary Consolidated Statements of Income
   for the nine months ended June 30, 2006 and 2005 (Unaudited)..........   F-30
Atlas Resources, LLC and Subsidiary Consolidated Statements of Changes
   in Member's Equity for the nine months ended June 30, 2006
   (Unaudited)...........................................................   F-31
Atlas Resources, LLC and Subsidiary Consolidated Statements of Cash
   Flows for the nine months ended June 30, 2006 and 2005 (Unaudited)....   F-32
Atlas Resources, LLC and Subsidiary Notes to Consolidated Financial
   Statements dated as of June 30, 2006 (Unaudited)......................   F-33

                                       146
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners
ATLAS AMERICA PUBLIC 16-2007 (A) L.P.
(A DELAWARE LIMITED PARTNERSHIP)

We have audited the accompanying balance sheet of Atlas America Public 16-2007
(A) L.P. (A Delaware Limited Partnership) as of September 30, 2006. This
financial statement is the responsibility of the Partnership's management. Our
responsibility is to express an opinion on this financial statement based on our
audit.

We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statement is free of material misstatement. The Partnership is not
required to have, nor were we engaged to perform an audit of its internal
control over financial reporting. Our audit included consideration of internal
control over financial reporting as a basis for designing audit procedures that
are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Partnership's internal control over
financial reporting. Accordingly, we express no such opinion. An audit also
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.

In our opinion, the financial statement referred to above presents fairly, in
all material respects, the financial position of Atlas America Public 16-2007
(A) L.P. as of September 30, 2006, in conformity with accounting principles
generally accepted in the United States of America.

                                        /s/ GRANT THORNTON LLP

Cleveland, Ohio
October 6, 2006

                                       F-1
Atlas America Public 16-2007 (A) L.P.
                        (A Delaware Limited Partnership)

                                  BALANCE SHEET

                               September 30, 2006

                                     ASSETS

Cash                $100
                    ====

                                PARTNER'S CAPITAL

Partners' capital   $100
                    ====

   The accompanying notes to financial statement are an integral part of this
                                   statement.

                                       F-2
Atlas America Public 16-2007 (A) L.P.
                        (A Delaware Limited Partnership)

                          NOTES TO FINANCIAL STATEMENT

                               SEPTEMBER 30, 2006

1.   ORGANIZATION AND DESCRIPTION OF BUSINESS

     Atlas America Public 16-2007 (A) L.P. (the "Partnership") is a Delaware
     limited partnership in which Atlas Resources, LLC ("Atlas Resources") of
     Pittsburgh, Pennsylvania (a second-tier wholly-owned subsidiary of Atlas
     America, Inc., a publicly traded company), will be Managing General Partner
     and Operator, and subscribers to units will be either Limited Partners or
     Investor General Partners depending upon their individual elections.

     The Partnership will be funded to drill development wells which are
     proposed to be located primarily in the Appalachian Basin located in
     western Pennsylvania, eastern and southern Ohio, western New York and north
     central Tennessee.

     Subscriptions at a cost of $10,000 per unit, subject to discounts for
     certain investors, generally will be sold using wholesalers and through
     broker-dealers including Anthem Securities, Inc., an affiliated company,
     which will receive on each unit sold to an investor, a 2.5% dealer-manager
     fee, a 7% sales commission and up to a .5% reimbursement of the selling
     agents' bona fide due diligence expenses. Commencement of Partnership
     operations is subject to the receipt of minimum Partnership subscriptions
     of $2,000,000 (up to a maximum of $200,000,000) by December 31, 2007.

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     BASIS OF ACCOUNTING

     The Partnership prepares its financial statements in accordance with
     accounting principles generally accepted in the United States of America.

     OIL AND GAS PROPERTIES

     The Partnership will use the successful efforts method of accounting for
     oil and gas producing activities. Costs to acquire mineral interests in oil
     and gas properties and to drill and equip wells will be capitalized.
     Depreciation and depletion will be computed on a field-by field basis by
     the unit-of-production method based on periodic estimates of oil and gas
     reserves. Undeveloped leaseholds and proved properties will be assessed
     periodically or whenever events or circumstances indicate that the carrying
     amount of these assets may not be recoverable. Proved properties will be
     assessed based on estimates of future cash flows.

                                      F-3
Atlas America Public 16-2007 (A) L.P.
                        (A Delaware Limited Partnership)

                    NOTES TO FINANCIAL STATEMENT (CONTINUED)

                               SEPTEMBER 30, 2006

2    SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

     USE OF ESTIMATES

     The preparation of financial statements in conformity with accounting
     principles generally accepted in the United States of America requires
     management to make estimates and assumptions that affect the amounts
     reported in the financial statements and accompanying notes. Actual results
     could differ from those estimates.

3.   FEDERAL INCOME TAXES

     The Partnership will not be treated as a taxable entity for federal income
     tax purposes. Any item of income, gain, loss, deduction or credit would
     flow through to the partners as though each partner has incurred such item
     directly. As a result, each partner must take into account his or her
     pro-rata share under the partnership agreement of all items of Partnership
     income and deductions in computing his or her federal income tax liability.

4.   PARTICIPATION IN REVENUES AND COSTS

     The Managing General Partner and the investor partners will participate in
     revenues and costs in the following manner:
MANAGING
                                                                            GENERAL   INVESTOR
                                                                            PARTNER   PARTNERS
                                                                           --------   --------
PARTNERSHIP COSTS
Organization and offering costs                                            100%         0%
Lease costs                                                                100%         0%
Intangible drilling costs (1)                                                0%       100%
Equipment costs                                                               (2)        (2)
Operating costs, administrative costs, direct costs, and all other costs      (3)        (3)

PARTNERSHIP REVENUES
Interest income                                                               (4)        (4)
Equipment proceeds                                                            (2)        (2)
All other revenues including production revenues                              (5)(6)     (5)(6)
F-4
Atlas America Public 16-2007 (A) L.P.
                        (A Delaware Limited Partnership)

                    NOTES TO FINANCIAL STATEMENT (CONTINUED)

                               SEPTEMBER 30, 2006

4.   PARTICIPATION IN REVENUES AND COSTS (CONTINUED)

     (1)  An amount equal to 90% of the subscription proceeds of investor
          partners in the partnership will be used to pay 100% of the intangible
          drilling costs incurred by the partnership in drilling and completing
          its wells.

     (2)  An amount equal to 10% of the subscription proceeds of investor
          partners in the partnership will be used to pay a portion of the
          equipment costs incurred by the partnership in drilling and completing
          its wells. All equipment costs in excess of that amount will be
          charged to the Managing General Partner. Equipment proceeds, if any,
          will be credited in the same percentage in which the equipment costs
          were charged.

     (3)  These costs will be charged to the parties in the same ratio as the
          related production revenues are being credited. These costs also
          include plugging and abandonment costs of the wells after the wells
          have been drilled and produced.

     (4)  Interest earned on subscription proceeds before the final closing of
          the partnership will be credited to investor partners' accounts and
          paid not later than the partnerships first cash distribution from
          operations. After the final closing of the partnership and until the
          subscription proceeds are invested in the partnership's natural gas
          and oil operations any interest income from temporary investments will
          be allocated pro rata to the investor partners providing the
          subscription proceeds. All other interest income, including interest
          earned on the deposit of operating revenues, will be credited as
          natural gas and oil production revenues are credited.

     (5)  The managing general partner and the investor partners in the
          partnership will share in all of the partnership's other revenues in
          the same percentage as their respective capital contributions bear to
          the total partnership capital contributions except that the managing
          general partner will receive an additional 7% of the partnership
          revenues. However, the managing general partner's total revenue share
          may not exceed 40% of partnership revenues.

          The partnership will enter into a drilling and operating agreement
          with Atlas Resources to drill and complete all of the partnership
          wells for an amount equal to the sum of the following items (i) the
          cost of permits, supplies, materials, equipment, and all other items
          used in the drilling and completion of a well provided by
          third-parties, or if the foregoing items are provided by affiliates of
          the managing general partner, then those items will be charged at
          competitive rates; (ii) fees for third-party services; (iii) fees for
          services provided by the managing general partner's affiliates, which
          will be charged at competitive rates; (iv) an administration and
          oversight fee of $15,000 per well, which will be charged to the
          investors as part of each well's intangible drilling costs and the
          portion of equipment costs paid by the investors; and (v) a mark-up in
          an amount equal to 15% of the sum of (i), (ii), (iii) and (iv), above,
          for the managing general partner's services as general drilling
          contractor. This will be proportionately reduced if the partnership's
          working interest in a well is less than 100%.

                                      F-5
Atlas America Public 16-2007 (A) L.P.
                        (A Delaware Limited Partnership)

                    NOTES TO FINANCIAL STATEMENT (CONTINUED)

                               SEPTEMBER 30, 2006

4.   PARTICIPATION IN REVENUES AND COSTS (CONTINUED)

     (6)  The actual allocation of partnership revenues between the managing
          general partner and the investor partners will vary from the
          allocation described in (5) above if a portion of the managing general
          partner's partnership net production revenues is subordinated as
          described in note 7.

5.   TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES

     The Partnership intends to enter into the following significant
     transactions with Atlas Resources and its affiliates as provider under the
     Partnership agreement:

     The partnership will enter into a drilling and operating agreement with
     Atlas Resources to drill and complete all of the partnership wells for an
     amount equal to the sum of the following items (i) the cost of permits,
     supplies, materials, equipment, and all other items used in the drilling
     and completion of a well provided by third-parties, or if the foregoing
     items are provided by affiliates of the managing general partner, then
     those items will be charged at competitive rates; (ii) fees for third-party
     services; (iii) fees for services provided by the managing general
     partner's affiliates, which will be charged at competitive rates; (iv) an
     administration and oversight fee of $15,000 per well, which will be charged
     to the investors as part of each well's intangible drilling costs and the
     portion of equipment costs paid by the investors; and (v) a mark-up in an
     amount equal to 15% of the sum of (i), (ii), (iii) and (iv), above, for the
     managing general partner's services as general drilling contractor. This
     will be proportionately reduced if the partnership's working interest in a
     well is less than 100%. The cost of the wells will include all ordinary and
     actual costs of drilling, testing and completing the wells.

     Atlas Resources will receive an unaccountable, fixed payment reimbursement
     for its administrative costs at $75 per well per month, which will be
     proportionately reduced if the partnership's working interest in a well is
     less than 100%.

     Atlas Resources will receive well supervision fees for operating and
     maintaining the wells during producing operations at a competitive rate
     (currently the competitive rate is $362 per well per month in the primary
     and secondary drilling areas). The well supervision fees will be
     proportionately reduced if the partnership's working interest in a well is
     less than 100%.

     Atlas Resources will charge the partnership a fee for gathering and
     transportation at a competitive rate (currently 10% of the natural gas
     price).

     Atlas Resources will contribute all the undeveloped leases necessary to
     cover each of the partnership's prospects and will receive a credit for its
     capital account in the partnership equal to the cost of the leases
     (approximately $11,310 per prospect which will be proportionately reduced
     if the Partnership's working interest is the prospect is less than 100%).

                                      F-6
Atlas America Public 16-2007 (A) L.P.
                        (A Delaware Limited Partnership)

                    NOTES TO FINANCIAL STATEMENT (CONTINUED)

                               SEPTEMBER 30, 2006

5.   TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES (CONTINUED)

     As the Managing General Partner, Atlas Resources will perform all
     administrative and management functions for the partnership including
     billing and collecting revenues and paying expenses. Atlas Resources will
     be reimbursed for all direct costs expended on behalf of the partnership.

6.   PURCHASE COMMITMENT

     Subject to certain conditions, investor partners may present their
     interests after five years from the partnership's first cash distribution
     from operations for purchase by the Managing General Partner. The Managing
     General Partner is not obligated to purchase more than 5% of the units in
     any calendar year. In the event that the Managing General Partner is unable
     to obtain the necessary funds, the Managing General Partner may suspend its
     purchase obligation.

7.   SUBORDINATION OF PORTION OF MANAGING GENERAL PARTNER'S NET PRODUCER REVENUE
     SHARE

     The Managing General Partner will subordinate up to 50% of its share of
     production revenues of the Partnership, net of related operating costs,
     direct costs, administrative costs, and all other costs not specifically
     allocated, to the receipt by the investor partners of cash distributions
     from the Partnership equal to at least 10% per unit, based on $10,000 per
     unit regardless of the actual price paid, determined on a cumulative basis,
     in each of the first five 12-month periods beginning with the Partnership's
     first cash distribution from operations.

8.   INDEMNIFICATION

     In order to limit the potential liability of the investor general partners
     for partnership liabilities and obligations, Atlas Resources has agreed to
     indemnify each investor general partner from any liability incurred which
     exceeds such partner's share of undistributed Partnership net assets and
     insurance proceeds.

                                      F-7
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors
ATLAS RESOURCES, INC.

We have audited the accompanying consolidated balance sheets of ATLAS RESOURCES,
INC. (a Pennsylvania corporation) and subsidiaries as of September 30, 2005 and
2004, and the related consolidated statements of income, changes in
stockholder's equity, and cash flows for the years then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. The Company is not required to
have, nor were we engaged to perform an audit of its internal control over
financial reporting. Our audit included consideration of internal control over
financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Company's internal control over financial
reporting. Accordingly, we express no such opinion. An audit also includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of ATLAS RESOURCES,
INC. and subsidiaries as of September 30, 2005 and 2004, and the consolidated
results of their operations and cash flows for the years then ended, in
conformity with accounting principles generally accepted in the United States of
America.

/s/ Grant Thornton LLP
-------------------------------------
Cleveland, Ohio
January 6, 2006 (except for Note 10, as to which the date is April 7, 2006)

                                      F-8
ATLAS RESOURCES, INC. AND SUBSIDIARY
                           CONSOLIDATED BALANCE SHEETS
                           SEPTEMBER 30, 2005 AND 2004
2005       2004
                                                                              --------   --------
                                                                                 (In thousands,
                                                                               except share data)
ASSETS
Current assets:
   Cash and cash equivalents ..............................................   $  2,856   $    242
   Accounts receivable ....................................................      9,735      7,080
   Prepaid expenses .......................................................      2,172      1,488
                                                                              --------   --------
      Total current assets ................................................     14,763      8,810
Property and equipment:
   Oil and gas properties and equipment (successful efforts) ..............    184,009    120,506
   Buildings and land .....................................................      3,000      2,947
   Other ..................................................................        389        368
                                                                              --------   --------
                                                                               187,398    123,821
Less - accumulated depreciation, depletion, and amortization ..............    (32,719)   (23,654)
                                                                              --------   --------
   Net property and equipment .............................................    154,679    100,167
Goodwill (net of accumulated amortization of $2,320) ......................     20,868     20,868
Intangible assets (net of accumulated amortization of $3,385 and $2,909)...      3,028      3,444
                                                                              --------   --------
                                                                              $193,338   $133,289
                                                                              ========   ========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
   Current portion of long-term debt ......................................   $     59   $     56
   Accounts payable .......................................................      7,054      5,304
   Liabilities associated with drilling contracts .........................     60,971     29,375
   Accrued liabilities ....................................................      4,928      3,174
   Advances and note from parent ..........................................     72,603     66,725
                                                                              --------   --------
      Total current liabilities ...........................................    145,615    104,634
Asset retirement obligation ...............................................      5,415      1,910
Long-term debt ............................................................         22         82
Stockholder's equity:
   Common stock, stated at $10 per share;
      500 authorized shares; 200 shares issued and outstanding ............          2          2
   Additional paid-in capital .............................................     30,505     16,505
   Retained earnings ......................................................     11,779     10,156
                                                                              --------   --------
      Total stockholder's equity ..........................................     42,286     26,663
                                                                              --------   --------
                                                                              $193,338   $133,289
                                                                              ========   ========
See accompanying notes to consolidated financial statements

                                      F-9
ATLAS RESOURCES, INC. AND SUBSIDIARY
                        CONSOLIDATED STATEMENTS OF INCOME
                     YEARS ENDED SEPTEMBER 30, 2005 AND 2004

                                                               2005       2004
                                                             --------   --------
                                                                (In thousands)
REVENUES
Well drilling ............................................   $134,623   $ 86,880
Gas and oil production ...................................     34,042     23,098
Well services ............................................      5,991      4,137
Transportation ...........................................      2,275      2,476
Other income .............................................         --         44
                                                             --------   --------
                                                              176,931    116,635
COSTS AND EXPENSES
Well drilling ............................................    116,816     75,548
Gas and oil production and exploration ...................      4,224      2,580
Well services ............................................      2,287      1,648
Non-direct ...............................................     38,886     24,831
Depreciation, depletion and amortization .................     10,409      8,197
Interest .................................................      2,206      2,625
                                                             --------   --------
                                                              174,828    115,429
                                                             --------   --------
Income from operations before income taxes ...............      2,103      1,206
Provision for income taxes ...............................        480        217
                                                             --------   --------
Net income ...............................................   $  1,623   $    989
                                                             ========   ========

           See accompanying notes to consolidated financial statements

                                      F-10
ATLAS RESOURCES, INC. AND SUBSIDIARY
           CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY
                     YEARS ENDED SEPTEMBER 30, 2005 AND 2004
                        (In thousands, except share data)
ACCUMULATED
                                                      ADDITIONAL       OTHER                      TOTAL
                                     COMMON STOCK       PAID-IN    COMPREHENSIVE   RETAINED   STOCKHOLDER'S
                                    SHARES   AMOUNT     CAPITAL    INCOME (LOSS)   EARNINGS       EQUITY
                                    ---------------   ----------   -------------   --------   -------------
Balance, September 30, 2003......     200      $ 2      $16,505         $--         $ 9,167      $25,674
Net income.......................      --       --           --          --             989          989
                                      ---      ---      -------         ---         -------      -------
Balance, September 30, 2004......     200        2       16,505          --          10,156       26,663
                                      ---      ---      -------         ---         -------      -------
Contributed capital..............      --       --       14,000          --              --       14,000
Net income.......................      --       --           --          --           1,623        1,623
                                      ---      ---      -------         ---         -------      -------
Balance, September 30, 2005           200      $ 2      $30,505         $--         $11,779      $42,286
                                      ===      ===      =======         ===         =======      =======
See accompanying notes to consolidated financial statements

                                      F-11
ATLAS RESOURCES, INC. AND SUBSIDIARY
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                     YEARS ENDED SEPTEMBER 30, 2005 AND 2004
2005       2004
                                                                                    --------   --------
                                                                                       (In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ......................................................................   $  1,623   $    989
Adjustments to reconcile net income to net cash provided by operating activities:
   Depreciation, depletion and amortization .....................................     10,409      8,197
   Management fees, cost allocations and inter company interest allocated
      from affiliates ...........................................................     49,465     32,809
   Gain on sale of assets .......................................................        (22)       (11)
   Change in operating assets and liabilities ...................................     31,691      4,016
                                                                                    --------   --------
Net cash provided by operating activities .......................................     93,166     46,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ............................................................    (60,216)   (33,051)
Proceeds from sale of assets ....................................................         24         33
                                                                                    --------   --------
Net cash used in investing activities ...........................................    (60,192)   (33,018)
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments on borrowings ................................................        (57)       (56)
Net payments to affiliates ......................................................    (30,303)   (17,386)
                                                                                    --------   --------
Net cash used in financing activities ...........................................    (30,360)   (17,442)
                                                                                    --------   --------
Increase (decrease) in cash and cash equivalents ................................      2,614     (4,460)
Cash and cash equivalents at beginning of year ..................................        242      4,702
                                                                                    --------   --------
Cash and cash equivalents at end of year ........................................   $  2,856   $    242
                                                                                    ========   ========
See accompanying notes to consolidated financial statements

                                      F-12
ATLAS RESOURCES, INC. AND SUBSIDIARY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                               SEPTEMBER 30, 2005

NOTE 1 - NATURE OF OPERATIONS

     Atlas Resources, Inc. (the "Company"), a Pennsylvania corporation, and its
subsidiary, ARD Investments, are engaged in the exploration for development and
production of natural gas and oil primarily in the Appalachian Basin Area. In
addition, the Company performs contract drilling and well operation services.

     The Company is a second-tier wholly-owned subsidiary of Atlas America, Inc.
("Atlas"), a publicly traded company trading under the symbol ATLS on the NASDAQ
System. The Company's operations are dependent upon the resources and services
provided by Atlas. The Company finances a substantial portion of its drilling
activities through drilling partnerships it sponsors and typically acts as the
managing general partner of and has a material interest in these partnerships.

SPIN-OFF OF ATLAS FROM RESOURCE AMERICA, INC.

     On June 30, 2005, Resource America, Inc. ("RAI") the Company's former
indirect Parent, distributed its remaining 10.7 million shares of Atlas to its
stockholders in the form of a tax-free dividend. Although the distribution
itself is tax-free to RAI stockholders, as a result of the deconsolidation there
may be some tax liability arising from prior unrelated corporate transactions
among Atlas and some of its subsidiaries. Atlas (and the Company) no longer
consolidates with RAI as of June 30, 2005. The Company does not anticipate that
there will be a direct material impact on its financial position or results of
operations.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION

     The consolidated financial statements include the accounts of the Company
and its wholly owned subsidiary. The Company also owns individual interests in
the assets, and is separately liable for its share of the liabilities of energy
partnerships, whose activities include only exploration and production
activities. In accordance with established practice in the oil and gas industry,
the Company includes in its consolidated financial statements its pro-rata share
of assets, liabilities, income and costs and expenses of the energy partnerships
in which it has an interest. All material intercompany transactions have been
eliminated.

USE OF ESTIMATES

     Preparation of the consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and the disclosure of contingent assets and
liabilities as of the date of the consolidated financial statements and the
reported amounts of revenues and costs and expenses during the reporting period.
Actual results could differ from these estimates.

                                      F-13
ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

RECLASSIFICATIONS

     Certain reclassifications have been made to the fiscal 2004 consolidated
financial statements to conform to the fiscal 2005 presentation.

COMPREHENSIVE INCOME

     Comprehensive income includes net income and all other changes in the
equity of a business during a period from transactions and other events and
circumstances from non-owner sources. There are no elements of comprehensive
income, other than net income, to report.

RECEIVABLES

     In evaluating its allowance for possible losses, the Company performs
ongoing credit evaluations of its customers and adjusts credit limits based upon
payment history and the customers' current creditworthiness, as determined by
the Company's review of its customers' credit information. The Company extends
credit on an unsecured basis to many of its energy customers. At September 30,
2005 and 2004, the Company's credit evaluation indicated that it has no need for
an allowance for possible losses.

PROPERTY AND EQUIPMENT

     Property and equipment is stated at cost. Depreciation, depletion and
amortization is based on cost less estimated salvage value primarily using the
unit-of-production or straight line method over the assets' estimated useful
lives. Maintenance and repairs are expensed as incurred. Major renewals and
improvements that extend the useful lives of property are capitalized.

     The estimated service lives of property and equipment are as follows:

Pipelines, processing and compression facilities.......   15-35 years
Rights-of-way - Mid-Continent..........................      40 years
Rights-of-way - Appalachia.............................      20 years
Land, building and improvements........................   10-40 years
Furniture and equipment................................     3-7 years
Other..................................................    3-10 years

                                      F-14
ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

PROPERTY AND EQUIPMENT (CONTINUED)

     Property and equipment consists of the following at the dates indicated:

                                                            AT SEPTEMBER 30,
                                                          -------------------
                                                            2005       2004
                                                          --------   --------
                                                             (In thousands)
Mineral interest in properties:
   Proved properties...................................   $  2,009   $  1,701
   Unproved properties.................................        465        463
Wells and related equipment............................    179,818    117,242
Support equipment......................................      1,717      1,100
Other..................................................      3,389      3,315
                                                          --------   --------
                                                           187,398    123,821
Accumulated depreciation, depletion, amortization and
valuation allowances:..................................
   Oil and gas properties..............................    (31,320)   (22,623)
   Other...............................................     (1,399)    (1,031)
                                                          --------   --------
                                                           (32,719)   (23,654)
                                                          --------   --------
                                                          $154,679   $100,167
                                                          ========   ========

OIL AND GAS PROPERTIES

     The Company follows the successful efforts method of accounting for oil and
gas producing activities. Exploratory drilling costs are capitalized pending
determination of whether a well is successful. Exploratory wells subsequently
determined to be dry holes are charged to expense. Costs resulting in
exploratory discoveries and all development costs, whether successful or not,
are capitalized. Geological and geophysical costs, delay rentals and
unsuccessful exploratory wells are expensed. Oil is converted to gas equivalent
basis ("mcfe") at the rate one-barrel equals 6 mcf. Depletion is provided on the
units-of-production method. Unproved properties are reviewed for impairment
annually, or whenever events or circumstances indicate that the carrying amount
of an asset may not be recoverable. An impairment charge would be recognized if
conditions indicated that the Company would not explore the acreage prior to
expiration of applicable leases or if the carrying value of the property
exceeded its fair value.

     The Company's long-lived assets are reviewed for impairment annually for
events or changes in circumstances that indicate that the carrying amount of an
asset may not be recoverable. Long-lived assets are reviewed for potential
impairment at the lowest levels for which there are identifiable cash flows that
are largely independent of other groups of assets. The review is done by
determining if the historical cost of proved properties less the applicable
accumulated depreciation, depletion and amortization and reserve for abandonment
is less than the estimated expected undiscounted future cash flows. The expected
future cash flows are estimated based on the Company's plans to continue to
produce and develop proved reserves. The expected future cash flows from the
sale of the production of reserves is calculated using estimated future prices
based upon market related information available to the Company, which includes

                                      F-15
ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

OIL AND GAS PROPERTIES (CONTINUED)

published futures prices. The estimated future level of production is based on
assumptions surrounding future levels of prices and costs, field decline rates,
market demand and supply, and the economic and regulatory climates. If the
carrying value exceeds such cash flows, an impairment loss is recognized for the
difference between the estimated fair market value (as determined by discounted
future cash flows), and the carrying value of the assets.

     Upon the sale or retirement of a complete unit of a proved property, its
cost is eliminated from the property accounts, and the resultant gain or loss is
reclassified to accumulated depletion. Upon the sale of an entire interest in an
unproved property that has been assessed for impairment individually, a gain or
loss is recognized in the statement of operations. If a partial interest in an
unproved property is sold, any funds received reduce the cost in the interest
retained.

ASSET RETIREMENT OBLIGATION

     If a reasonable estimate of the fair values of asset retirement obligations
can be made, such obligations are recorded when assets are acquired. Changes to
the estimated fair values of the assets are recorded in the period in which they
occur. Asset retirement obligations primarily relate to the abandonment of oil
and gas producing facilities and include costs to dismantle and relocate or
dispose of production equipment, gathering systems, wells and related
structures. Estimates, which are based on historical experience in plugging and
abandoning wells, include estimated remaining lives of the wells based on
reserve estimates, external estimates as to the cost to plug and abandon the
wells in the future and federal and state regulatory requirements. The Company
does not provide for a market risk premium associated with asset retirement
obligations because a reliable estimate cannot be determined.

FAIR VALUE OF FINANCIAL INSTRUMENTS

     The Company uses the following methods and assumptions in estimating the
fair value of each class of financial instruments for which it is practicable to
estimate fair value.

     For cash and cash equivalents, receivables and payables, the carrying
amounts approximate fair value because of the short maturity of these
instruments.

     For long-term debt, the carrying value approximates fair value because
interest rates approximate current market rates.

CONCENTRATION OF CREDIT RISK

     Financial instruments that potentially subject the Company to
concentrations of credit risk consist principally of periodic temporary
investments of cash. The Company places its temporary cash investments in
high-quality short-term money market instruments and deposits with high-quality
financial institutions and brokerage firms. At September 30, 2005, the Company
had $2,925,900 in deposits at various banks, of which $2,825,900 is over the
insurance limit of the Federal Deposit Insurance Corporation. No losses have
been experienced on such investments.

                                      F-16
ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

ENVIRONMENTAL MATTERS

     The Company is subject to various federal, state and local laws and
regulations relating to the protection of the environment. The Company has
established procedures for the ongoing evaluation of its operations to identify
potential environmental exposures and to comply with regulatory policies and
procedures.

     The Company accounts for environmental contingencies in accordance with
SFAS No. 5 "Accounting for Contingencies." Environmental expenditures that
relate to current operations are expensed or capitalized as appropriate.
Expenditures that relate to an existing condition caused by past operations, and
do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are
probable, and the costs can be reasonably estimated. The Company maintains
insurance that may cover in whole or in part certain environmental expenditures.
For the two years ended September 30, 2005 and 2004, the Company had no
environmental matters requiring specific disclosure or the recording of a
liability.

REVENUE RECOGNITION

     The Company conducts certain energy activities through, and a portion of
its revenues is attributable to, sponsored energy limited partnerships. These
energy partnerships raise capital from investors to drill gas and oil wells. The
income from the Company's general partner interest is recorded when the gas and
oil are sold by a partnership.

     The Company contracts with the energy partnerships to drill partnership
wells. The contracts require that the energy partnerships must pay the Company
the full contract price upon execution. The income from a drilling contract is
recognized as the services are performed using the percentage of completion
method. The contracts are typically completed in less than 60 days. The Company
classifies the difference between the contract payments it has received and the
revenue earned as a current liability, included in liabilities associated with
drilling contracts.

     The Company recognizes transportation revenues at the time the natural gas
is delivered to the purchaser.

     The Company recognizes well services revenues at the time the services are
performed.

     The Company is entitled to receive well operating and management fees
according to the respective partnership agreements. The Company recognizes well
operating and management fees as income when earned and includes them in well
services revenues.

                                      F-17
ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

SUPPLEMENTAL CASH FLOW INFORMATION

     The Company considers temporary investments with maturity at the date of
acquisition of 90 days or less to be cash equivalents.

                                    YEARS ENDED
                                   SEPTEMBER 30,
                                  --------------
                                   2005     2004
                                  ------   ------
                                   (In thousands)
CASH PAID DURING THE YEARS FOR:
Interest.......................    $628     $   3
Income taxes paid (refunded)...    $  1     $(223)

INCOME TAXES

     The Company is included in the consolidated federal income tax return of
its Parent. Income taxes are reported by the Company in amounts consistent with
what the Company's estimated taxes would have been had it filed a return on a
separate company basis utilizing its calculated effective rate of 23% and 18%
for fiscal years 2005 and 2004 respectively. The Company's effective tax rate is
lower than the federal statutory rate due to the benefit of percentage
depletion. Deferred tax assets and liabilities, which have been transferred to
the Parent since it files the consolidated tax return, are included in Advances
and note from Parent. These deferred taxes reflect the tax effect of temporary
differences between the tax bases of the Company's assets and liabilities and
the amounts reported in the financial statements. Separate company state tax
returns are filed in those states in which the Company is registered to do
business.

RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS

     In May 2005, the Financial Accounting Standards Board, ("FASB") issued
Statement No.154, Accounting Changes and Error Corrections ("SFAS 154"). SFAS
154 requires retrospective application to prior periods' financial statements of
changes in accounting principle. It also requires that the new accounting
principle be applied to the balances of assets and liabilities as of the
beginning of the earliest period for which retrospective application is
practicable and that a corresponding adjustment be made to the opening balance
of retained earnings for that period rather than being reported in an income
statement. The statement will be effective for accounting changes and
corrections of errors made in fiscal years beginning after December 15, 2005.
The impact of SFAS 154 will depend on the nature and extent of any voluntary
accounting changes and correction of errors after the effective date, but
management does not currently expect SFAS 154 to have a material impact on the
Company's financial position or results of operations.

                                      F-18
ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS (CONTINUED)

     In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for
Conditional Asset Retirement Obligations ("FIN 47"), which will result in (a)
more consistent recognition of liabilities relating to asset retirement
obligations, (b) more information about expected future cash outflows associated
with those obligations, and (c) more information about investments in long-lived
assets because additional asset retirement cost will be recognized as part of
the carrying amounts of the assets. FIN 47 clarifies that the term conditional
asset retirement obligation as used in SFAS No. 143, Accounting for Asset
Retirement Obligations, refers to a legal obligation to perform an asset
retirement activity in which the timing and (or) method of settlement are
conditional on a future event that may or may not be within the control of the
entity. The obligation to perform the asset retirement activity is unconditional
even though uncertainty exists about the timing and (or) method of settlement.
Uncertainty about the timing and (or) method of settlement of a conditional
asset retirement obligation should be factored into the measurement of the
liability when sufficient information exists. FIN 47 also clarifies when an
entity would have sufficient information to reasonably estimate the fair value
of an asset retirement obligation. FIN 47 is effective no later than the end of
fiscal years ending after December 15, 2005. Retrospective application of
interim financial information is permitted, but not required. Early adoption of
this interpretation is encouraged. Management does not believe the
interpretation will have a significant impact on the Company's financial
position or results of operations.

     In December 2004, the FASB issued FASB Staff Position No. FSP 109-1 ("FSP
109-1"), Application of FASB Statement No. 109, Accounting for Income Taxes, to
the Tax Deduction on Qualified Production Activities Provided by the American
Jobs Creation Act of 2004 ("AJCA"). The AJCA introduces a special 9% tax
deduction on qualified production activities. FSP 109-1 concludes that this
deduction should be accounted for as a special tax deduction in accordance with
SFAS No. 109. As such, the special deduction has no effect on deferred tax
assets and liabilities existing at the enactment date. Rather, the impact of
this deduction will be reported in the same period in which the deduction is
claimed in the Company's tax return. FSP 109-1 is not expected to have a
material impact on the Company's financial position or results of operations.

NOTE 3 -- OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL

INTANGIBLE ASSETS

     Intangible assets consist of partnership management and operating contracts
acquired through acquisitions and recorded at fair value on their acquisition
dates. The Company amortizes contracts acquired on a declining balance method,
over their respective estimated lives, ranging from five to thirteen years.
Amortization expense for the years ended September 30, 2005 and 2004 was
approximately $478,000. The estimated amortization expense for each of the next
five fiscal years is approximately $478,000.

GOODWILL

     The Company applies the provisions of SFAS No. 142 ("SFAS 142") Goodwill
and Other Intangible Assets, which requires that goodwill no longer be
amortized, but instead evaluated for impairment at least annually. The
evaluation of impairment under SFAS 142 requires the use of projections,
estimates and assumptions as to the future performance of the Company's
operations, including anticipated future revenues, expected future operating
costs and the discount factor used. Actual results could differ from
projections, resulting in revisions to the Company's assumptions and, if
required, recognition of an impairment loss. The Company evaluated goodwill and
determined that there was no impairment at September 30, 2005. The Company will
continue to evaluate its goodwill at least annually and will reflect the
impairment of goodwill, if any, within the consolidated statements of income in
the period in which such impairment is indicated.

                                      F-19
ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 4 - ASSET RETIREMENT OBLIGATION

     Effective October 1, 2002, the Company adopted the SFAS No. 143, Accounting
for Asset Retirement Obligations ("SFAS 143") which requires the Company to
recognize an estimated liability for the plugging and abandonment of its oil and
gas wells and associated pipelines and equipment. Under SFAS 143, the Company
must currently recognize a liability for future asset retirement obligations if
a reasonable estimate of the fair value of that liability can be made. The
associated asset retirement costs are capitalized as part of the carrying amount
of the long lived asset. SFAS 143 requires the Company to consider estimated
salvage value in the calculation of depreciation, depletion and amortization.
Consistent with industry practice, historically the Company had determined the
cost of plugging and abandonment on its oil and gas properties would be offset
by salvage values received. The adoption of SFAS 143 resulted in (i) an increase
of total liabilities because retirement obligations are required to be
recognized, (ii) an increase in the recognized cost of assets because the
retirement costs are added to the carrying amount of the long-lived assets and
(iii) a decrease in depletion expense, because the estimated salvage values are
now considered in the depletion calculation.

     The Company determines the estimated liability based upon its historical
experience in plugging and abandoning wells. The estimate includes consideration
of the remaining lives of the wells based on reserve estimates, external
estimates as to the cost to plug and abandon the wells in the future and federal
and state regulatory requirements. The liability is discounted using an assumed
credit-adjusted risk-free interest rate. Revisions to the liability could occur
due to changes in estimates of plugging and abandonment costs or remaining lives
of the wells, or if federal or state regulators enact new plugging and
abandonment requirements. The increase in asset retirement obligations in fiscal
2005 was due to an upward revision in the estimated cost of plugging and
abandoning wells.

     The Company has no assets legally restricted for purposes of settling asset
retirement obligations. The Company has determined that there are no material
retirement obligations associated with tangible long-lived assets.

     A reconciliation of the Company's liability for well plugging and
abandonment costs for the years ended September 30, 2005 and 2004 is as follows
(in thousands):

                                                     2005     2004
                                                    ------   ------
Asset retirement obligation, beginning of year...   $1,910   $  701
Liabilities incurred.............................      770    1,212
Liabilities settled..............................       (8)     (40)
Revision in estimates............................    2,593      (60)
Accretion expense................................      150       97
                                                    ------   ------
Asset retirement obligation, end of year.........   $5,415   $1,910
                                                    ======   ======

     The above accretion expense is included in depreciation, depletion and
amortization in the Company's consolidated statements of income.

NOTE 5 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     The Company conducts certain energy activities through, and a substantial
portion of its revenues is attributable to, energy-limited partnerships
("Partnerships"). The Company serves as general partner of the Partnerships and
assumes customary rights and obligations for the Partnerships. As the general
partner, the Company is liable for Partnership liabilities and can be liable to
limited partners if it breaches its responsibilities with respect to the
operations of the Partnerships. The Company is entitled to receive management
fees, reimbursement for administrative costs incurred, and to share in the
Partnerships' revenues, costs and expenses according to the respective
Partnership agreements.

                                      F-20
ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 5 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS (CONTINUED)

     Advances and note from Parent represents amounts owed for advances and
transactions in the normal course of business. Both the note and the advances
are subordinated to any third party debt. During fiscal 2005 the note due to
Parent was reclassified to contributed capital. Interest expense related to the
note was $1.6 million and $2.1 million for the years ended September 30, 2005
and 2004. The advances have no repayment terms, therefore, the Company has
classified the amounts due the Parent as a current liability on its Consolidated
Balance Sheets.

     The Company is dependent on its Parent for management and administrative
functions and financing for its capital expenditures. The Company paid
management fees to its Parent of $47.3 million and $23.7 million for the years
ended September 30, 2005 and 2004, respectively.

NOTE 6 - DEBT

     During the fiscal year ended September 30, 2003, the Company entered into
two loans through General Motors Acceptance Corporation to finance the purchase
of ten trucks used in its well drilling and oil and gas production activities.
One loan had a principal balance at September 30, 2005 and 2004 of $41,000 and
$69,300, respectively, and bears interest at an annual rate of 1.9%. The second
loan had a principal balance at September 30, 2005 and 2004 of $40,000 and
$69,000, respectively, and bears interest at an annual rate of 2.9%. The current
portion of the long-term debt for the periods ended September 30, 2005 and 2004
were $59,000 and $56,000, respectively. Both loans had an original term of 48
months.

NOTE 7 - COMMITMENTS AND CONTINGENCIES

     The Company is the managing general partner of various energy partnerships,
and has agreed to indemnify each investor partner from any liability that
exceeds such partner's share of partnership assets. Subject to certain
conditions, investor partners in certain energy partnerships have the right to
present their interests for purchase by the Company, as managing general
partner. The Company is not obligated to purchase more than 5% to 10% of the
units in any calendar year. Based on past experience, the Company believes that
any liability incurred would not be material.

     The Company may be required to subordinate a part of its net partnership
revenues to the receipt by investor partners of cash distributions from the
energy partnerships equal to at least 10% of their agreed subscriptions
determined on a cumulative basis, in accordance with the terms of the
partnership agreements.

     The Parent may draw from its revolving credit facility on behalf of the
Company. In March 2004, the Company's parent entered into a credit facility led
by Wachovia Bank, which has a current borrowing base of $75.0 million. The
facility permits draws based on the remaining proved developed non-producing and
proved undeveloped natural gas and oil reserves attributable to the Parent's
wells and the projected fees and revenues from operation of the wells and the
administration of the energy partnerships. Up to $50.0 million of the facility
may be in the form of standby letters of credit. The facility is secured by the
Parent's assets, including those of the Company.

     The revolving credit facility has a term ending in March 2007, when all
outstanding borrowings must be repaid. Borrowings bear interest at one of two
rates (elected at the borrower's option) which increase as the amount
outstanding under the facility increases: (i) Wachovia prime rate plus between
25 to 75 basis points, or (ii) LIBOR plus between 175 and 225 basis points. At
September 30, 2005 and 2004, the parent had $9.5 million and $26.7 million,
respectively, outstanding under this facility, including $1.5 million and $1.7
million at September 30, 2005 and 2004 under letters of credit. The interest
rates ranged from 5.52% to 7.0% at September 30, 2005.

                                      F-21
ATLAS RESOURCES, INC. AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 7 - COMMITMENTS AND CONTINGENCIES (CONTINUED)

     The Company is a party to various routine legal proceedings arising out of
the ordinary course of its business. Management believes that none of these
actions, individually or in the aggregate, will have a material adverse effect
on the Company's financial position or results of operations.

NOTE 8 - MAJOR CUSTOMERS

     The Company's natural gas is sold under contract to various purchasers. For
the year ended September 30, 2005, gas sales to Amerada Hess Corporation
(formerly First Energy Solutions Corporation) and UGI Energy Services accounted
for 52% and 30%, respectively, of total revenues. For the year ended September
30, 2004, First Energy Solutions Corporation accounted for 10% of total
revenues. No other customer accounted for 10% or more of total revenues for the
years ended September 30, 2005 and 2004.

NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION

     Results of operations from oil and gas producing activities:
YEARS ENDED SEPTEMBER 30,
                                                                 -------------------------
                                                                       2005      2004
                                                                     -------   -------
                                                                       (In thousands)
Revenues......................................................       $34,042   $23,098
Production costs..............................................        (3,320)   (2,107)
Exploration expenses..........................................          (904)     (473)
Depreciation, depletion and amortization......................        (9,562)   (7,445)
Income taxes..................................................        (8,013)   (4,256)
                                                                     -------   -------
Results of operations from oil and gas producing activities...       $12,243   $ 8,817
                                                                     =======   =======
Capitalized Costs Related to Oil and Gas Producing Activities. The
components of capitalized costs related to the Company's oil and gas-producing
activities are as follows:
AT SEPTEMBER 30,
                                                                                -------------------
                                                                                  2005       2004
                                                                                --------   --------
                                                                                   (In thousands)
Proved properties............................................................   $  2,009   $  1,701
Unproved properties..........................................................        465        463
Wells and related equipment and facilities...................................    179,818    117,242
Support equipment and facilities.............................................      1,717      1,100
                                                                                --------   --------
                                                                                $184,009   $120,506
Accumulated depreciation, depletion, amortization and valuation allowances...    (31,320)   (22,623)
                                                                                --------   --------
Net capitalized costs........................................................   $152,688   $ 97,883
                                                                                ========   ========
F-22
ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION (Continued)

     Costs Incurred in Oil and Gas Producing Activities. The costs incurred by
the Company in its oil and gas activities during the periods indicated are as
follows:

                                       YEARS ENDED SEPTEMBER 30,
                                       -------------------------
                                             2005      2004
                                           -------   -------
                                             (In thousands)
Property acquisition costs:
Unproved properties.................       $    --   $   438
Exploration costs...................       $   904   $   473
Development costs...................       $59,524   $32,766

     The development costs above for the years ended September 30, 2005 and 2004
were substantially all incurred for the development of proved undeveloped
properties.

     Oil and Gas Reserve Information (Unaudited) The estimates of the Company's
proved and unproved gas reserves are based upon evaluations made by management
and verified by Wright & Company, Inc., an independent petroleum engineering
firm, as of September 30, 2005 and 2004. All reserves are located within the
United States. Reserves are estimated in accordance with guidelines established
by the Securities and Exchange Commission and the Financial Accounting Standards
Board, which require that reserve estimates be prepared under existing economic
and operating conditions with no provisions for price and cost escalation except
by contractual arrangements.

     Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas, and natural gas liquids, which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, i.e. prices
and costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.

     o    Reservoirs are considered proved if economic feasibility is supported
          by either actual production or conclusive formation tests. The area of
          a reservoir considered proved includes (a) that portion delineated by
          drilling and defined by gas-oil and/or oil-water contacts, if any; and
          (b) the immediately adjoining portions not yet drilled, but which can
          be reasonably judged as economically productive on the basis of
          available geological and engineering data. In the absence of
          information on fluid contacts, the lowest known structural occurrence
          of hydrocarbons controls the lower proved limit of the reservoir.

                                      F-23
ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION (CONTINUED)

     o    Reserves which can be produced economically through application of
          improved recovery techniques (such as fluid injection) are included in
          the "proved" classification when successful testing by a pilot
          project, or the operation of an installed program in the reservoir,
          provides support for the engineering analysis on which the project or
          program was based.

     o    Estimates of proved reserves do not include the following: (a) oil
          that may become available from known reservoirs but is classified
          separately as "indicated additional reservoirs"; (b) crude oil,
          natural gas, and natural gas liquids, the recovery of which is subject
          to reasonable doubt because of uncertainty as to geology, reservoir
          characteristics or economic factors; (c) crude oil, natural gas and
          natural gas liquids, that may occur in undrilled prospects; and (d)
          crude oil and natural gas, and natural gas liquids, that may be
          recovered from oil shale's, coal, gilsonite and other such sources.

     Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operation
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.

     There are numerous uncertainties inherent in estimating quantities of
proven reserves and in projecting future net revenues and the timing of
development expenditures. The reserve data presented represents estimates only
and should not be construed as being exact. In addition, the standardized
measure of discounted future net cash flows may not represent the fair market
value of the Company's oil and gas reserves or the present value of future cash
flows of equivalent reserves, due to anticipated future changes in oil and gas
prices and in production and development costs and other factors for effects
have not been proved.

                                      F-24
ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION (CONTINUED)

     The Company's reconciliation of changes in proved reserve quantities is as
follows (unaudited):

                                                         GAS          OIL
                                                        (Mcf)       (Bbls)
                                                     -----------   --------
Balance at September 30, 2003                         83,830,378     62,415
   Current additions..............................    26,806,939    235,902
   Transfers to limited partnerships..............    (7,808,942)   (15,217)
   Revisions......................................    (6,493,890)    (7,135)
   Production.....................................    (3,872,923)   (15,898)
                                                     -----------    -------
Balance at September 30, 2004                         92,461,562    260,067
   Current additions..............................    31,509,029    173,068
   Transfers to limited partnerships..............    (5,397,575)  (147,153)
   Revisions......................................    (4,739,866)   (41,575)
   Production.....................................    (4,548,987)   (22,972)
                                                     -----------    -------
Balance at September 30, 2005                        109,284,163    221,435
Proved developed reserves at:
   September 30, 2005.............................    56,043,521     78,558
   September 30, 2004.............................    46,580,498    111,168

     The following schedule presents the standardized measure of estimated
discounted future net cash flows relating to proved oil and gas reserves. The
estimated future production is priced at fiscal year-end prices, adjusted only
for fixed and determinable increases in natural gas and oil prices provided by
contractual agreements. The resulting estimated future cash inflows are reduced
by estimated future costs to develop and produce the proved reserves based on
fiscal year-end cost levels. The future net cash flows are reduced to present
value amounts by applying a 10% discount factor. The standardized measure of
future cash flows was prepared using the prevailing economic conditions existing
at September 30, 2005 and 2004 and such conditions continually change.

                                      F-25
ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION (Continued)

     Accordingly, such information should not serve as a basis in making any
judgment on the potential value of recoverable reserves or in estimating future
results of operations (unaudited).
YEARS ENDED SEPTEMBER 30,
                                                                          -------------------------
                                                                              2005         2004
                                                                           ----------   ---------
                                                                               (In thousands)
Future cash inflows ...................................................    $1,616,657   $ 652,811
Future production costs................................................    $ (141,456)  $ (79,989)
Future development costs...............................................    $ (116,287)  $ (91,195)
Future income tax expense..............................................    $ (383,239)  $(122,962)
                                                                           ----------   ---------
Future net cash flows..................................................       975,675     358,665
   Less 10% annual discount for estimated timing of cash flows.........      (575,713)   (222,143)
                                                                           ----------   ---------
   Standardized measure of discounted future net cash flows............    $  399,962   $ 136,522
                                                                           ==========   =========
The future cash flows estimated to be spent to develop proved undeveloped
properties in the years ended September 30, 2005, 2006 and 2007 are $45.0
million, $46.0 million and $26.0 million, respectively.

     The following table summarizes the changes in the standardized measure of
discounted future net cash flows from estimated production of proved oil and gas
reserves after income taxes (unaudited):
YEARS ENDED SEPTEMBER 30,
                                                                          -------------------------
                                                                                2005       2004
                                                                             ---------   --------
Balance, beginning of year.............................................      $ 136,522   $ 77,734
Increase (decrease) in discounted future net cash flows:
   Sales and transfers of oil and gas, net of related costs............        (31,505)   (20,991)
   Net changes in prices and production costs..........................        265,150     59,345
   Revisions of previous quantity estimates............................        (22,272)   (10,197)
   Purchases of reserves in place......................................            458        270
   Estimated settlement of asset retirement obligations................           (201)    (1,209)
   Estimated proceeds on disposal of well equipment....................             72        190
   Development costs incurred..........................................          4,289      4,838
   Changes in future development costs.................................         (1,577)    (1,033)
   Transfers to limited partnerships...................................        (25,295)    (9,835)
   Extensions, discoveries, and improved recovery less related costs...        153,630     54,979
   Accretion of discount...............................................         17,942      9,697
   Net changes in future income taxes..................................       (104,412)   (23,737)
   Other...............................................................          7,161     (3,529)
                                                                             ---------   --------
 Balance, end of year..................................................      $ 399,962   $136,522
                                                                             =========   ========
F-26
ATLAS RESOURCES, INC. AND SUBSIDIARY
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
                               SEPTEMBER 30, 2005

NOTE 10 - SUBSEQUENT EVENTS

     Atlas recently announced that it intends to form either a wholly-owned
limited liability company or limited partnership subsidiary and transfer to that
entity substantially all of its natural gas and oil exploration and production
assets. In connection with that contemplated transaction, in March 2006 the
Company was merged into a newly-formed limited liability company, Atlas
Resources, LLC, which is anticipated to become an indirect subsidiary of Atlas'
newly-formed subsidiary. Atlas Resources, LLC, however, will continue to serve
as managing general partner of its various energy partnerships, and does not
expect that any of these transactions will have a material effect on the
Partnerships' financial position or results of operations. Atlas further intends
to make a registered initial public offering of an estimated 20% minority
interest in its newly-formed subsidiary.

                                      F-27
CONSOLIDATED FINANCIAL STATEMENTS
                                   (UNAUDITED)

                       ATLAS RESOURCES, LLC AND SUBSIDIARY

                                  JUNE 30, 2006

                                      F-28
ATLAS RESOURCES, LLC AND SUBSIDIARY
                           CONSOLIDATED BALANCE SHEETS
                      (IN THOUSANDS, EXCEPT PER SHARE DATA)
                                   (UNAUDITED)
JUNE 30,   SEPTEMBER 30,
                                                                             2006         2005
                                                                           --------   -------------
ASSETS
Current assets:
   Cash and cash equivalents ...........................................   $    196     $  2,856
   Accounts receivable .................................................     13,003        9,735
   Prepaid expenses ....................................................      2,666        2,172
   Hedge receivable short term-affiliate ...............................      3,937           --
                                                                           --------     --------
      Total current assets .............................................     19,802       14,763
Property and equipment:
   Oil and gas properties and equipment (successful efforts) ...........    240,315      184,009
   Buildings and land ..................................................      3,000        3,000
   Other ...............................................................        424          389
                                                                           --------     --------
                                                                            243,739      187,398
Less - accumulated depreciation, depletion, and amortization ...........    (45,226)     (32,719)
                                                                           --------     --------
   Net property and equipment ..........................................    198,513      154,679
Other long term assets .................................................      5,293           --
Goodwill (net of accumulated amortization of $2,320) ...................     20,868       20,868
Intangible assets (net of accumulated amortization
   of $3,743 and $3,385) ...............................................      2,663        3,028
                                                                           --------     --------
                                                                           $247,139     $193,338
                                                                           ========     ========

LIABILITIES AND MEMBERS' EQUITY
Current liabilities:
   Current portion of long-term debt ...................................   $     67     $     59
   Accounts payable ....................................................      8,634        7,054
   Liabilities associated with drilling contracts ......................     88,810       60,971
   Accrued liabilities .................................................      5,999        4,928
   Accrued hedge liability .............................................         --           --
   Advances from parent ................................................     60,655       72,603
                                                                           --------     --------
      Total current liabilities ........................................    164,165      145,615
Asset retirement obligation ............................................      7,430        5,415
Long-term debt .........................................................         45           22
Hedge liability long term-affiliate ....................................      6,528           --
Members' equity:
   Common stock, stated at $10 per share;
      500 authorized shares; 200 shares issued and outstanding .........         --            2
   Additional paid-in capital ..........................................         --       30,505
Accumulated comprehensive income (loss) ................................      2,702           --
   Retained earnings ...................................................         --       11,779
                                                                                        --------
      Total stockholder's equity .......................................         --       42,286
Member's capital .......................................................     66,269           --
                                                                           --------     --------
      Total equity .....................................................     68,971           --
                                                                           --------     --------
                                                                           $247,139     $193,338
                                                                           ========     ========
See accompanying notes to consolidated financial statements

                                      F-29
ATLAS RESOURCES, LLC AND SUBSIDIARY
                        CONSOLIDATED STATEMENTS OF INCOME
                    NINE MONTHS ENDED JUNE 30, 2006 AND 2005
                                   (UNAUDITED)

                                                               2006       2005
                                                             --------   --------
                                                               (In thousands)

REVENUES
Well construction and completion .........................   $126,833   $ 98,758
Gas and oil production ...................................     42,783     23,098
Well services ............................................      5,620      6,115
Transportation ...........................................      3,468         --
Administration and oversight .............................      6,232         --
                                                             --------   --------
                                                              184,936    127,971
COSTS AND EXPENSES
Well construction and completion .........................    110,288     85,876
Gas and oil production and exploration ...................      4,785      3,329
Well services ............................................      2,260      1,428
Non-direct ...............................................     45,610     26,315
Depreciation, depletion and amortization .................     13,031      6,813
Income tax benefit (see Note 9) ..........................    (15,246)        --
Interest expense - affiliates ............................        283      2,072
Other interest expense ...................................         44         72
Other (income) expense ...................................       (102)        66
                                                             --------   --------
                                                              160,953    125,971
                                                             --------   --------
Income from operations ...................................     23,983      2,000
Provision for income taxes ...............................         --        360
                                                             --------   --------
Net income ...............................................   $ 23,983   $  1,640
                                                             ========   ========

           See accompanying notes to consolidated financial statements

                                      F-30
ATLAS RESOURCES, LLC AND SUBSIDIARY
              CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY
                         NINE MONTHS ENDED JUNE 30, 2006
                        (IN THOUSANDS, EXCEPT SHARE DATA)
                                   (UNAUDITED)
ACCUMULATED
                                         COMMON STOCK    ADDITIONAL       OTHER                  STOCKHOLDER'S                TOTAL
                                       ---------------     PAID-IN    COMPREHENSIVE   RETAINED   EQUITY BEFORE   MEMBER'S   MEMBER'S
                                       SHARES   AMOUNT     CAPITAL    INCOME (LOSS)   EARNINGS     CONVERSION     CAPITAL    EQUITY
                                       ------   ------   ----------   -------------   --------   -------------   --------   --------
Balance, October 1, 2005 ...........    200      $ 2      $ 30,505        $   --      $ 11,779     $ 42,286       $    --   $    --
Conversion of  Corporation to LLC ..   (200)      (2)      (30,505)           --       (11,779)     (42,286)       42,286    42,286
Other Comprehensive Income .........     --       --            --         2,702            --           --            --     2,702
Net Income .........................     --       --            --            --            --           --        23,983    23,983
                                        ---      ---      --------        ------      --------     --------       -------   -------
Balance, June 30, 2006 .............     --      $--      $     --        $2,702      $     --     $     --       $66,269   $68,971
                                        ===      ===      ========        ======      ========     ========       =======   =======
F-31
ATLAS RESOURCES, LLC AND SUBSIDIARY
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                    NINE MONTHS ENDED JUNE 30, 2006 AND 2005
                                   (UNAUDITED)
2006       2005
                                                                    --------   --------
                                                                       (In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ......................................................   $ 23,983   $  1,640
   Adjustments to reconcile net income to net cash provided by
      operating activities:
   Depreciation, depletion and amortization .....................     13,031      6,813
   Management fees, cost allocations and intercompany interest
      allocated from affiliates .................................     45,074     32,435
   Deferred tax benefit .........................................    (16,896)        --
   Gain on disposal of assets ...................................        (12)       (15)
   Change in operating assets and liabilities ...................     26,735     29,914
                                                                    --------   --------
Net cash provided by operating activities .......................     91,915     70,787

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ............................................    (55,229)   (42,281)
Proceeds from sale of assets ....................................      1,336         17
                                                                    --------   --------
Net cash used in investing activities ...........................    (53,893)   (42,264)

CASH FLOWS FROM FINANCING ACTIVITIES:
Net payments on borrowings ......................................         31        (43)
Net payments to affiliates ......................................    (40,713)   (28,005)
                                                                    --------   --------
Net cash used in financing activities ...........................    (40,682)   (28,048)
                                                                    --------   --------
Decrease in cash and cash equivalents ...........................     (2,660)       475
Cash and cash equivalents at beginning of year ..................      2,856        242
                                                                    --------   --------
Cash and cash equivalents at end of year ........................   $    196   $    717
                                                                    ========   ========
See accompanying notes to consolidated financial statements

                                      F-32
ATLAS RESOURCES, LLC AND SUBSIDIARY
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                  JUNE 30, 2006
                                   (UNAUDITED)

NOTE 1 - NATURE OF OPERATIONS

     The consolidated financial statements of Atlas Resources, LLC and its
wholly-owned subsidiary (the "Company") as of June 30, 2006 are unaudited. Atlas
Resources, LLC is a wholly-owned subsidiary of Atlas America, Inc. (the "Parent"
or "Atlas"). These consolidated financial statements have been prepared in
accordance with accounting principles generally accepted in the United States of
America ("US GAAP") for interim financial information and certain rules and
regulations of the Securities and Exchange Commission. Accordingly, they do not
include all of the information and footnotes required by US GAAP for complete
financial statements. The results of operations for the nine months ended June
30, 2006 may not necessarily be indicative of the results of operations for the
full fiscal year ending September 30, 2006.

     Atlas America, Inc. recently announced that it intends to transfer
substantially all of its natural gas and oil exploration and production assets
into a newly-formed wholly-owned limited liability company subsidiary. In
connection with that transaction, the Company was formed on March 24, 2006 and
Atlas Resources, Inc. was merged into it. Atlas America, Inc. anticipates that
Atlas Resources, LLC will become an indirect subsidiary of its newly-formed
subsidiary Atlas Energy Resources, LLC ("Atlas Energy"), see Note 10. The assets
and liabilities of Atlas Resources, Inc. were transferred into Atlas Resources,
LLC without any changes to their cost bases. The shareholder's equity from Atlas
Resources, Inc. was transferred to member's equity in Atlas Resources LLC to
reflect the entity's change from a corporation to a limited liability company.
The results of operations up through March 23, 2006 are from Atlas Resources,
Inc. before it was merged into a non-taxable entity. Deferred tax assets and
liabilities were eliminated upon the merger since the Company is a non-taxable
entity. On the effective date of the merger, the Company became a single member
LLC and each share of Atlas Resources, Inc. was cancelled.

SPIN-OFF OF ATLAS FROM RESOURCE AMERICA, INC.

     On June 30, 2005, Resource America, Inc. ("RAI") Atlas Resources, Inc.'s
former indirect Parent, distributed its remaining 10.7 million shares of Atlas
to its stockholders in the form of a tax-free dividend. Although the
distribution itself is tax-free to RAI stockholders, as a result of the
deconsolidation there may be some tax liability arising from prior unrelated
corporate transactions among Atlas and some of its subsidiaries. The Company
does not anticipate that there will be a direct material impact on its financial
position or results of operations. Since June 30, 2005, Atlas (and the Company)
are no longer included within RAI's consolidated tax return.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

RECEIVABLES

     In evaluating its allowance for possible losses, the Company performs
ongoing credit evaluations of its customers and adjusts credit limits based upon
payment history and the customers' current creditworthiness, as determined by
the Company's review of its customers' credit information. The Company extends
credit on an unsecured basis to many of its energy customers. At June 30, 2006
and 2005, the Company's credit evaluation indicated that it has no need for an
allowance for possible losses.

                                      F-33
ATLAS RESOURCES, LLC AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                  JUNE 30, 2006
                                   (UNAUDITED)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

REVENUE RECOGNITION

     Because there are timing differences between the delivery of natural gas
and oil and the Company's receipt of a delivery statement, the Company has
unbilled revenues. These revenues are accrued based upon volumetric data from
the Company's records and the Company's estimates of the related transportation
and compression fees, which are, in turn, based upon applicable product prices.
The Company had unbilled trade receivables at June 30, 2006 and September 30,
2005 of $11.0 million and $8.5 million respectively, which are included in
Accounts receivable, on its Consolidated Balance Sheets.

SUPPLEMENTAL CASH FLOW INFORMATION

     The Company considers temporary investments with maturity at the date of
acquisition of 90 days or less to be cash equivalents.

                                     NINE MONTHS ENDED JUNE 30,
                                     --------------------------
                                             2006   2005
                                             ----   ----
                                           (In thousands)
CASH PAID DURING THE PERIOD FOR:

Interest..........................           $ 53   $489
Income taxes paid.................           $129   $  1

RECLASSIFICATIONS

     Certain accounts in the prior year financial statements have been
reclassified for comparative purposes to conform to the presentation in the
current year financial statements.

NOTE 3 - COMPREHENSIVE INCOME

     Comprehensive income includes net income and other gains and losses
affecting stockholders equity from non-owner sources that, under accounting
principles generally accepted in the United States of America, have not been
recognized in the calculation of net income. For the Company, this includes only
changes in the fair value of unrealized hedging gains and losses (shown in
thousands).
NINE MONTHS ENDED JUNE 30,
                                                                         --------------------------
                                                                                2006     2005
                                                                              -------   ------
Net earnings..........................................................        $23,983   $1,640
Other comprehensive income (loss):
Unrealized holding gains on hedging contracts.........................          5,490       --
Less: reclassification adjustment for gains realized in net income....         (2,788)      --
                                                                              -------   ------
                                                                                2,702       --
                                                                              =======   ======
Comprehensive income..................................................        $26,685   $1,640
                                                                              =======   ======
NOTE 4 - PROPERTY AND EQUIPMENT

     Property and equipment is stated at cost. Depletion and amortization of oil
and gas properties is calculated based on cost less estimated salvage value
primarily using the unit-of-production method. Other fixed assets are
depreciated using the straight-line method over the assets estimated useful
lives. Maintenance and repairs are expensed as incurred. Major renewals and
improvements that extend the useful lives of property are capitalized.

                                      F-34
ATLAS RESOURCES, LLC AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                  JUNE 30, 2006
                                   (UNAUDITED)

NOTE 4 - PROPERTY AND EQUIPMENT (CONTINUED)

Property and equipment consists of the following at the dates indicated (in
thousands):

                                                        JUNE 30,   SEPTEMBER 30,
                                                          2006          2005
                                                        --------   -------------

Mineral interests:

   Proved properties.................................   $  1,543      $  2,009
   Unproved properties...............................        463           465
Wells and related equipment..........................    235,844       179,818
Support equipment....................................      2,465         1,717
Other                                                      3,424         3,389
                                                        --------      --------
                                                         243,739       187,398
Accumulated depreciation, depletion and amortization:

   Oil and gas properties............................    (43,450)      (31,320)
   Other.............................................     (1,776)       (1,399)
                                                        --------      --------
                                                         (45,226)      (32,719)
                                                        --------      --------
                                                        $198,513      $154,679
                                                        ========      ========

NOTE 5 - ASSET RETIREMENT OBLIGATION

     A reconciliation of the Company's liability for well plugging and
abandonment costs for the nine months ended June 30, 2006 and 2005 is as follows
(in thousands):

                                                         2006     2005
                                                        ------   ------
Asset retirement obligation, beginning of period.....   $5,415   $1,910
Liabilities incurred.................................    1,851    2,057
Liabilities settled..................................       (1)      (7)
Revision in estimates................................       --     (183)
Accretion expense....................................      165      137
                                                        ------   ------
Asset retirement obligation, end of period...........   $7,430   $3,914
                                                        ======   ======

     The above accretion expense is included in depreciation, depletion and
amortization in the Company's consolidated statements of income.

NOTE 6 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     Advances from Parent shown on the Company's Balance Sheets represents
amounts owed for advances and other transactions in the normal course of
business. The advances are subordinated to any third party debt. The Company
incurred interest expense related to inter company transactions of $283 thousand
and $2.1 million in June 2006 and 2005, respectively. The advances have no
repayment terms, therefore, the Company has classified the amounts due the
Parent as a current liability on its Consolidated Balance Sheets.

                                      F-35
ATLAS RESOURCES, LLC AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                  JUNE 30, 2006
                                  (UNAUDITED )

NOTE 7 - COMMITMENTS AND CONTINGENCIES

     The Company is the managing general partner of various energy partnerships,
and has agreed to indemnify each investor partner from any liability that
exceeds such partner's share of partnership assets. Subject to certain
conditions, investor partners in certain energy partnerships have the right to
present their interests for purchase by the Company, as managing general
partner. The Company is not obligated to purchase more than 5% to 10% of the
units in any calendar year. Based on past experience, the Company believes that
any liability incurred would not be material.

     The Company may be required to subordinate a part of its net partnership
revenues to the receipt by investor partners of cash distributions from the
energy partnerships equal to at least 10% of their agreed subscriptions
determined on a cumulative basis, in accordance with the terms of the
partnership agreements.

     The Parent may draw from its revolving credit facility on behalf of the
Company. In April 2006, the Company's parent entered into a credit facility led
by Wachovia Bank, which has a current borrowing base of $150.0 million. The
facility permits draws based on the remaining proved developed non-producing and
proved undeveloped natural gas and oil reserves attributable to all wells that
Atlas America has an interest in, including the wells of the Company, and the
projected fees and revenues from operation of the wells and the administration
of the energy partnerships. Up to $50.0 million of the facility may be in the
form of standby letters of credit. The facility is secured by the Parent's
assets, including those of the Company. The revolving credit facility has a term
ending in April 2011, when all outstanding borrowings must be repaid and bears
interest at one of two rates (elected at the borrower's option) which increases
as the amount outstanding under the facility increases. At June 30, 2006 and
September 30, 2005, the Parent had $1.5 million and $9.5 million, respectively,
outstanding under this facility under letters of credit which are not reflected
as borrowings on the Parent's consolidated balance sheet.

     The Company is a party to various routine legal proceedings arising out of
the ordinary course of its business. Management believes that none of these
actions, individually or in the aggregate, will have a material adverse effect
on the Company's financial position or results of operations.

NOTE 8 - DERIVATIVE INSTRUMENTS

     Atlas from time to time enters into natural gas futures and option
contracts on the Company's behalf to hedge its exposure to changes in natural
gas prices. At any point in time, such contracts may include regulated New York
Mercantile Exchange ("NYMEX") futures and options contracts and non-regulated
over-the-counter futures contracts with qualified counterparties. NYMEX
contracts are generally settled with offsetting positions, but may be settled by
the delivery of natural gas.

     Atlas and the Company formally document all relationships between hedging
instruments and the items being hedged, including the Company's risk management
objectives and strategy for undertaking the hedging transactions. This includes
matching the natural gas futures and options contracts to the forecasted
transactions. Atlas and the Company assess, both at the inception of the hedge
and on an ongoing basis, whether the derivatives are highly effective in
offsetting changes in fair value of hedged items. Historically these contracts
have qualified and been designated as cash flow hedges and recorded at their
fair values. Gains or losses on future contracts are determined as the
difference between the contract price and a reference price, generally prices on
NYMEX. Such gains and losses are charged or credited to Accumulated Other
Comprehensive Income (Loss) and recognized as a component of oil and gas
production revenues in the month the hedged gas is sold. If it is determined
that a derivative is not highly effective as a hedge or it has ceased to be a
highly effective hedge, due to the loss of correlation between changes in gas
reference prices under a hedging instrument and actual gas prices, the Company
will discontinue hedge accounting for the derivative and subsequent changes in
fair value for the derivative will be recognized immediately into earnings.

                                      F-36
ATLAS RESOURCES, LLC AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                  JUNE 30, 2006
                                  (UNAUDITED )

NOTE 8 - DERIVATIVE INSTRUMENTS (CONTINUED)

     At June 30, 2006, the Company had 117 open natural gas futures contracts
allocated to it by Atlas related to natural gas sales covering 16,145,800
dekatherms ("Dth") (net to the Company) of natural gas, maturing through
December 31, 2009 at a combined average settlement price of $8.88 per Dth. At
June 30, 2006, the Company reflected net hedging assets on its balance sheet of
$2.7 million. There were no open hedge contracts at September 30, 2005. Of the
$2.7 million net gain in accumulated other comprehensive income at June 30,
2006, if the fair values of the instruments remain at current market values, the
Company will reclassify $3,936,500 of net gains to its statement of operations
over the next twelve month period as these contracts expire, and $1,234,500 of
net losses will be reclassified in later periods. Actual amounts that will be
reclassified will vary as a result of future price changes. Ineffective hedge
gains or losses are recorded within the statement of operations while the hedge
contract is open and may increase or decrease until settlement of the contract.
The Company recognized gains of $2,788,200 for the nine months ended June 30,
2006 within its statement of operations related to the settlement of qualifying
hedge instruments. The Company recognized no gains or losses during the nine
months ended June 30, 2006 and 2005 for hedge ineffectiveness or as a result of
the discontinuance of these cash flow hedges.

        Derivatives are recorded on the balance sheet as assets or liabilities
at fair value. For derivatives qualifying as hedges, the effective portion of
changes in fair value are recognized in member's equity as Accumulated Other
Comprehensive Income (Loss) and reclassified to earnings as such transactions
are settled. For non-qualifying derivatives and for the ineffective portion of
qualifying derivatives, changes in fair value are recognized in earnings as they
occur.

        At June 30, 2006, Atlas had allocated the following natural gas
fixed-price swaps in place to the Company:

NATURAL GAS FIXED - PRICE SWAPS

 TWELVE MONTH                    AVERAGE
    PERIOD         VOLUMES     FIXED PRICE       FAIR VALUE
ENDED JUNE 30,   (MMBTU)(1)   (PER MMBTU)    ASSET (LIABILITY)(2)
--------------   ----------   ------------   --------------------
     2007         2,825,500       $9.67             $ 3,937
     2008         6,155,600        8.76              (2,308)
     2009         5,121,300        8.69                 201
     2010         2,043,400        8.61                 872
                                                    -------
Total asset                                         $ 2,702
                                                    =======

----------
(1)  MMBTU represents million British Thermal Units.

(2)  Fair value based on forward NYMEX natural gas prices, as applicable.

                                      F-37
ATLAS RESOURCES, LLC AND SUBSIDIARY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
                                  JUNE 30, 2006
                                  (UNAUDITED )

NOTE 8 - DERIVATIVE INSTRUMENTS (CONTINUED)

     The following table sets forth the book and estimated fair values of
derivative instruments at the dates indicated (in thousands):

                                     JUNE 30, 2006          SEPTEMBER 30, 2005
                               -----------------------   -----------------------
                               BOOK VALUE   FAIR VALUE   BOOK VALUE   FAIR VALUE
                               ----------   ----------   ----------   ----------
Assets
Derivative instruments......     $ 9,230      $ 9,230        $--          $--
                                 -------      -------        ---          ---
                                 $ 9,230      $ 9,230        $--          $--
                                 =======      =======        ===          ===
Liabilities
Derivative instruments......     $(6,528)     $(6,528)       $--          $--
                                 -------      -------        ---          ---
                                 $ 2,702      $ 2,702        $--          $--
                                 =======      =======        ===          ===

     The fair value of the derivatives are included in the consolidate balance
sheets as follows (in thousands):

                                        JUNE 30,   SEPTEMBER 30,
                                          2006         2005
                                        --------   -------------
Unrealized hedge gains-short-term ...   $ 3,937          $--
Other assets-long term ..............     5,293           --
Unrealized hedge loss-long-term .....    (6,528)          --
                                        -------          ---
                                        $ 2,702          $--
                                        =======          ===

NOTE 9 - INCOME TAXES

     The Company was included in the consolidated federal income tax return of
its Parent up through the merger date in March 2006. After the merger, the
Company became a nontaxable single member limited liability company. The net
balance of Atlas Resources, Inc.'s deferred tax liability of $16.9 million has
been eliminated through a credit to the Company's income from operations in
accordance with Financial Accounting Standard Board Statement 109. The current
tax expense of $1.7 million incurred from October 1, 2005 up to the merger at
March 24, 2006 has also been charged to income from continuing operations.

NOTE 10 - SUBSEQUENT EVENTS

     On July 28, 2006, Atlas America Inc.'s wholly owned subsidiary, Atlas
Energy, filed a registration statement with the Securities and Exchange
Commission for an initial public offering of 5,750,000 common units,
representing an approximate 16.9% limited partner interest in it. Atlas Energy
will own substantially all of the Company's natural gas and oil exploration and
production assets. The Company will enter into a management agreement with Atlas
Energy and be responsible for its day-to-day operations.

                                      F-38
APPENDIX A

                              INFORMATION REGARDING
                          CURRENTLY PROPOSED PROSPECTS
                                       FOR
                      ATLAS AMERICA PUBLIC #16-2007(A) L.P.
INFORMATION REGARDING CURRENTLY PROPOSED PROSPECTS

The partnerships do not currently hold any interests in any prospects on which
the wells will be drilled, and the managing general partner has absolute
discretion in determining which prospects will be acquired to be drilled.
However, set forth below is information relating to certain proposed prospects
and the wells which will be drilled on the prospects by Atlas America Public
#16-2007(A) L.P., which is the first partnership in the program. It is referred
to in this section as the "2007(A) Partnership." One well will be drilled on
each development prospect, and for purposes of this discussion the well and
prospect are referred to together as the "well." The managing general partner
does not anticipate that the wells will be selected in the order in which they
are set forth below. Also, the wells currently proposed to be drilled by the
2007(A) Partnership when its subscription proceeds are released from escrow, and
from time to time thereafter, are subject to the managing general partner's
right to:

     o    withdraw the wells and to substitute other wells;

     o    take a lesser working interest in the wells;

     o    add other wells; or

     o    any combination of the foregoing.

The specified wells represent the necessary wells if subscription proceeds of
approximately $___ million are raised and the 2007(A) Partnership takes the
working interests in the wells that are set forth below in the "Lease
Information" for each area. The managing general partner has not proposed any
other wells if:

     o    a greater amount of subscription proceeds is raised;

     o    a lesser working interest in the wells is acquired; or

     o    other wells are substituted for the proposed wells for any of the
          reasons set forth below.

The managing general partner has not authorized any person to make any
representations to you concerning the possible inclusion of any other wells
which will be drilled by the 2007(A) Partnership or the other remaining
partnership, and you should rely only on the information in this prospectus. The
currently proposed wells will be assigned to the 2007(A) Partnership unless
there are circumstances which, in the managing general partner's opinion, lessen
the relative suitability of the wells. These considerations include:

     o    the amount of the subscription proceeds received by the 2007(A)
          Partnership;

     o    the latest geological and production data available;

     o    potential title or spacing problems;

     o    availability and price of drilling services, tubular goods and
          services;

     o    approvals by federal and state departments or agencies;

     o    agreements with other working interest owners in the wells;

     o    farmins; and

     o    continuing review of other properties which may be available.

Any substituted and/or additional wells will meet the same general criteria that
the managing general partner used in selecting the currently proposed wells, and
generally will be located in areas where the managing general partner or its
affiliates have

                                       1
previously conducted drilling operations. You, however, will not have the
opportunity to evaluate for yourself the relevant production and geological
information for the substituted and/or additional wells.

The information regarding the currently proposed wells is intended to help you
evaluate the economic potential and risks of drilling the proposed wells. This
includes production information for wells in the same general area as the
proposed well, which the managing general partner believes is an important
indicator in evaluating the economic potential of any well to be drilled.
However, a well drilled by the 2007(A) Partnership may not experience production
comparable to the production experienced by wells in the surrounding area since
the geological conditions in these areas can change in a short distance.
However, generally, there will be a lack of production information from
surrounding wells for the majority of the wells to be drilled by a partnership,
which results in greater uncertainty to you and the other investors. This lack
of production information results from the Pennsylvania Department of
Environmental Resources keeping production data confidential for the first five
years from the time a well starts producing, so if there was a third-party
operator and the well has been drilled within five years the production
information is not available. Also, when the managing general partner is the
operator the wells may often be drilled adjacent to wells which are not yet
completed, on-line to sell production, or have been producing for only a short
period of time so there is little or no production information available. See
"Risk Factors - Risks Related to an Investment In a Partnership - Lack of
Production Information Increases Your Risk and Decreases Your Ability to
Evaluate the Feasibility of a Partnership's Drilling Program." The managing
general partner has proposed these wells to be drilled, even though there is no
production data for other wells in the immediate area, because geologic trends
in the immediate area, such as sand thickness, porosities and water saturations,
lead the managing general partner to believe that the proposed wells also will
be productive.

When reviewing production information for each well offsetting, or in the
general area, of a proposed well to be drilled, you should consider the factors
set forth below.

     o    The length of time that the well has been on-line, and the time period
          for which production information is shown. Generally, the shorter the
          period for which production information is shown the less reliable the
          information is in predicting the ultimate recovery of reserves from a
          well.

     o    Production from a well declines throughout the life of the well. The
          rate of decline, the "decline curve," varies based on which geological
          formation is producing, and may be affected by the operation of the
          well. For example, the wells in the Clinton/Medina geological
          formation in western Pennsylvania will have a different decline curve
          from the wells in the Mississippian/Upper Devonian Sandstone Reservoir
          in Fayette, Greene and Westmoreland Counties, which also are situated
          in western Pennsylvania. Also, each well in a geological formation or
          reservoir will have a different rate of decline from the other wells
          in the same formation or reservoirs.

     o    The greatest volume of production ("flush production") from a well
          usually occurs in the early period of well operations and may indicate
          a greater reserve volume (generally, the ultimate amount of natural
          gas and oil recoverable from a well) than the well actually will
          produce. This period of flush production can vary depending on how the
          well is operated and the location of the well.

     o    The production information for the majority of the wells is incomplete
          or very limited. The designation "N/A" means:

          o    the production information was not available to the managing
               general partner for the reasons discussed in "Risk Factors -
               Risks Related to an Investment In a Partnership - Lack of
               Production Information Increases Your Risk and Decreases Your
               Ability to Evaluate the Feasibility of a Partnership's Drilling
               Program"; or

          o    if the managing general partner was the operator, then when the
               information was prepared the well was:

               o    not completed;

                                       2
o    completed, but was not on-line to sell production; or

               o    producing for only a short period of time.

     o    Production information for wells located close to a proposed well
          tends to be more relevant than production information for wells
          located farther away, although performance and volume of production
          from wells located on contiguous prospects can be much different.

     o    Consistency in production among wells tends to confirm the reliability
          and predictability of the production.

The information set forth below is included to help you become familiar with the
proposed wells.

     o    A map of western Pennsylvania and eastern Ohio showing their
          counties.

     o    Fayette County, Pennsylvania (Mississippian/Upper Devonian Sandstone
          Reservoirs)

          o    Lease information for Fayette, Greene and Westmoreland Counties,
               Pennsylvania.

          o    Location and Production Maps for Fayette, Greene and Westmoreland
               Counties, Pennsylvania showing the proposed wells and the wells
               in the area.

          o    Production data for Fayette, Greene and Westmoreland Counties,
               Pennsylvania.

          o    United Energy Development Consultants, Inc.'s geologic evaluation
               for the currently proposed wells in Fayette, Greene and
               Westmoreland Counties, Pennsylvania.

     o    Western Pennsylvania (Clinton/Medina Geological Formation)

          o    Lease information for western Pennsylvania and eastern Ohio.

          o    Location and Production Maps for western Pennsylvania and eastern
               Ohio showing the proposed wells and the wells in the area.

          o    Production data for western Pennsylvania and eastern Ohio.

          o    United Energy Development Consultants, Inc.'s geologic evaluation
               for the currently proposed wells in western Pennsylvania and
               eastern Ohio.

     o    Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee
          (Mississippian Carbonate and Devonian Shale Reservoirs)

          o    A map of Tennessee showing its Counties.

          o    Lease information for Anderson, Campbell, Morgan, Roane and Scott
               Counties, Tennessee.

          o    Location and Production Maps for Anderson, Campbell, Morgan,
               Roane and Scott Counties, Tennessee showing the proposed wells
               and the wells in the area.

          o    Production data for Anderson, Campbell, Morgan, Roane and Scott
               Counties, Tennessee.

          o    United Energy Development Consultants, Inc.'s geologic evaluation
               for the primary drilling area in Anderson, Campbell, Morgan,
               Roane and Scott Counties, Tennessee.

                                       3
EXHIBIT (A)

                                     FORM OF

                        AMENDED AND RESTATED CERTIFICATE

                      AND AGREEMENT OF LIMITED PARTNERSHIP

                                       FOR

                      ATLAS AMERICA PUBLIC #16-2007(A) L.P.

           [FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF
         LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #16-2007(B) L.P.]
TABLE OF CONTENTS

SECTION NO.                        DESCRIPTION                              PAGE
-----------                        -----------                              ----
I.    FORMATION
      1.01 Formation.....................................................     1
      1.02 Certificate of Limited Partnership............................     1
      1.03 Name, Principal Office and Residence..........................     1
      1.04 Purpose.......................................................     1

II.   DEFINITION OF TERMS
      2.01 Definitions...................................................     2

III.  SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS
      3.01 Designation of Managing General Partner and Participants......    11
      3.02 Participants..................................................    11
      3.03 Subscriptions to the Partnership..............................    11
      3.04 Capital Contributions of the Managing General Partner.........    13
      3.05 Payment of Subscriptions......................................    13
      3.06 Partnership Funds.............................................    14

IV.   CONDUCT OF OPERATIONS
      4.01 Acquisition of Leases.........................................    15
      4.02 Conduct of Operations.........................................    16
      4.03 General Rights and Obligations of the Participants and
           Restricted and Prohibited Transactions........................    20
      4.04 Designation, Compensation and Removal of Managing General
           Partner and Removal of Operator...............................    31
      4.05 Indemnification and Exoneration...............................    35
      4.06 Other Activities..............................................    37

V.    PARTICIPATION IN COSTS AND REVENUES, CAPITAL ACCOUNTS, ELECTIONS AND
      DISTRIBUTIONS
      5.01 Participation in Costs and Revenues...........................    38
      5.02 Capital Accounts and Allocations Thereto......................    41
      5.03 Allocation of Income, Deductions and Credits..................    42
      5.04 Elections.....................................................    44
      5.05 Distributions.................................................    45

VI.   TRANSFER OF UNITS
      6.01 Transferability of Units......................................    46
      6.02 Special Restrictions on Transfers of Units by Participants....    46
      6.03 Presentment...................................................    48
      6.04 Redemption of Units from Non-Citizen Assignees................    50

VII.  DURATION, DISSOLUTION, AND
      WINDING UP
      7.01 Duration......................................................    50
      7.02 Dissolution and Winding Up....................................    50

VIII. MISCELLANEOUS PROVISIONS
      8.01 Notices.......................................................    51
      8.02 Time..........................................................    52
      8.03 Applicable Law................................................    52
      8.04 Agreement in Counterparts.....................................    52
      8.05 Amendment.....................................................    52
      8.06 Additional Partners...........................................    53
      8.07 Legal Effect..................................................    53

EXHIBITS
      EXHIBIT (I-A) - Form of Managing General Partner Signature Page
      EXHIBIT (I-B) - Form of Subscription Agreement
      EXHIBIT (II)  - Form of Drilling and Operating Agreement for Atlas
                         America Public #16-2007(A) L.P. [Atlas America
                         Public #16-2007(B) L.P.]

                                        i
FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF
         LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #16-2007(A) L.P.
           [FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF
         LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #16-2007(B) L.P.]

THIS AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP
("AGREEMENT"), amending and restating the original Certificate of Limited
Partnership, is made and entered into as of the date set forth below, by and
among Atlas Resources, LLC, referred to as "Atlas" or the "Managing General
Partner," and the remaining parties from time to time signing a Subscription
Agreement for Limited Partner Units, these parties sometimes referred to as
"Limited Partners," or for Investor General Partner Units, these parties
sometimes referred to as "Investor General Partners."

                                    ARTICLE I
                                    FORMATION

1.01. FORMATION. The parties have formed a limited partnership under the
Delaware Revised Uniform Limited Partnership Act on the terms and conditions set
forth in this Agreement.

1.02. CERTIFICATE OF LIMITED PARTNERSHIP. This document is not only an agreement
among the parties, but also is the Amended and Restated Certificate and
Agreement of Limited Partnership of the Partnership. This document shall be
filed or recorded in the public offices required under applicable law or deemed
advisable in the discretion of the Managing General Partner. Amendments to the
certificate of limited partnership shall be filed or recorded in the public
offices required under applicable law or deemed advisable in the discretion of
the Managing General Partner.

1.03. NAME, PRINCIPAL OFFICE AND RESIDENCE.

1.03(a). NAME. The name of the Partnership is Atlas America Public #16-2007(A)
L.P. [Atlas America Public #16-2007(B) L.P.].

1.03(b). RESIDENCE. The residence of the Managing General Partner is its
principal place of business at 311 Rouser Road, Moon Township, Pennsylvania
15108, which shall also serve as the principal place of business of the
Partnership.

The residence of each Participant shall be as set forth on the Subscription
Agreement executed by the Participant.

All addresses shall be subject to change on notice to the parties.

1.03(c). AGENT FOR SERVICE OF PROCESS. The name and address of the agent for
service of process shall be Andrew M. Lubin at 110 S. Poplar Street, Suite 101,
Wilmington, Delaware 19801.

1.04. PURPOSE. The Partnership shall engage in all phases of the natural gas and
oil business. This includes, without limitation, exploration for, development
and production of natural gas and oil on the terms and conditions set forth
below and any other proper purpose under the Delaware Revised Uniform Limited
Partnership Act.

The Managing General Partner may not, without the affirmative vote of
Participants whose Units equal a majority of the total Units, do the following:

     (i)  change the investment and business purpose of the Partnership; or

     (ii) cause the Partnership to engage in activities outside the stated
          business purposes of the Partnership through joint ventures with other
          entities.

                                       1
ARTICLE II
                               DEFINITION OF TERMS

2.01. DEFINITIONS. As used in this Agreement, the following terms shall have the
meanings set forth below:

     1.   "Administrative Costs" means all customary and routine expenses
          incurred by the Sponsor for the conduct of Partnership administration,
          including: in-house legal, finance, in-house accounting, secretarial,
          travel, office rent, telephone, data processing and other items of a
          similar nature. Administrative Costs shall be limited as follows:

          (i)  no Administrative Costs charged shall be duplicated under any
               other category of expense or cost; and

          (ii) no portion of the salaries, benefits, compensation or
               remuneration of controlling persons of the Managing General
               Partner shall be reimbursed by the Partnership as Administrative
               Costs. Controlling persons include directors, executive officers
               and those holding a 5% or more equity interest in the Managing
               General Partner or a person having power to direct or cause the
               direction of the Managing General Partner, whether through the
               ownership of voting securities, by contract, or otherwise.

     2.   "Administrator" means the official or agency administering the
          securities laws of a state.

     3.   "Affiliate" means with respect to a specific person:

          (i)  any person directly or indirectly owning, controlling, or holding
               with power to vote 10% or more of the outstanding voting
               securities of the specified person;

          (ii) any person 10% or more of whose outstanding voting securities are
               directly or indirectly owned, controlled, or held with power to
               vote, by the specified person;

          (iii) any person directly or indirectly controlling, controlled by, or
               under common control with the specified person;

          (iv) any officer, director, trustee or partner of the specified
               person; and

          (v)  if the specified person is an officer, director, trustee or
               partner, any person for which the person acts in any such
               capacity.

     4.   "Agreement" means this Amended and Restated Certificate and Agreement
          of Limited Partnership, including all exhibits to this Agreement.

     5.   "Anthem Securities" means Anthem Securities, Inc., whose principal
          executive offices are located at 311 Rouser Road, P.O. Box 926, Moon
          Township, Pennsylvania 15108-0926.

     6.   "Assessments" means additional amounts of capital which may be
          mandatorily required of or paid voluntarily by a Participant beyond
          his subscription commitment.

     7.   "Atlas" means Atlas Resources, LLC, a Pennsylvania limited liability
          company, whose principal executive offices are located at 311 Rouser
          Road, Moon Township, Pennsylvania 15108, and any successor entity to
          Atlas Resources, LLC, whether by merger or any other form of
          reorganization, or the acquisition of all, or substantially all, of
          Atlas Resources, LLC's assets.

     8.   "Atlas America Public #16-2007 Program" means the offering of Units in
          a series of up to two limited partnerships entitled Atlas America
          Public #16-2007(A) L.P. and Atlas America Public #16-2007(B) L.P.

                                       2
9.   "Capital Account" or "account" means the account established for each
          party, maintained as provided in Section 5.02 and its subsections.

     10.  "Capital Contribution" means the amount agreed to be contributed to
          the Partnership by a Partner pursuant to Sections 3.04 and 3.05 and
          their subsections.

     11.  "Carried Interest" means an equity interest in the Partnership issued
          to a Person without consideration, in the form of cash or tangible
          property, in an amount proportionately equivalent to that received
          from the Participants.

     12.  "Code" means the Internal Revenue Code of 1986, as amended.

     13.  "Cost," when used with respect to the sale or transfer of property to
          the Partnership, means:

          (i)  the sum of the prices paid by the seller or transferor to an
               unaffiliated person for the property, including bonuses;

          (ii) title insurance or examination costs, brokers' commissions,
               filing fees, recording costs, transfer taxes, if any, and like
               charges in connection with the acquisition of the property;

          (iii) a pro rata portion of the seller's or transferor's actual
               necessary and reasonable expenses for seismic and geophysical
               services; and

          (iv) rentals and ad valorem taxes paid by the seller or transferor for
               the property to the date of its transfer to the buyer, interest
               and points actually incurred on funds used to acquire or maintain
               the property, and the portion of the seller's or transferor's
               reasonable, necessary and actual expenses for geological,
               geophysical, engineering, drafting, accounting, legal and other
               like services allocated to the property cost in conformity with
               generally accepted accounting principles and industry standards,
               except for expenses in connection with the past drilling of wells
               which are not producers of sufficient quantities of oil or gas to
               make commercially reasonable their continued operations, and
               provided that the expenses enumerated in this subsection (iv)
               shall have been incurred not more than 36 months before the sale
               or transfer to the Partnership.

          "Cost," when used with respect to services, means the reasonable,
          necessary and actual expense incurred by the seller on behalf of the
          Partnership in providing the services, determined in accordance with
          generally accepted accounting principles.

          As used elsewhere, "Cost" means the price paid by the seller in an
          arm's-length transaction.

     14.  "Dealer-Manager" means Anthem Securities, Inc., an Affiliate of the
          Managing General Partner, the broker/dealer which will manage the
          offering and sale of the Units.

     15.  "Development Well" means a well drilled within the proved area of a
          natural gas or oil reservoir to the depth of a stratigraphic Horizon
          known to be productive.

     16.  "Direct Costs" means all actual and necessary costs directly incurred
          for the benefit of the Partnership and generally attributable to the
          goods and services provided to the Partnership by parties other than
          the Sponsor or its Affiliates. Direct Costs may not include any cost
          otherwise classified as Organization and Offering Costs,
          Administrative Costs, Intangible Drilling Costs, Tangible Costs,
          Operating Costs or costs related to the Leases, but may include the
          cost of services provided by the Sponsor or its Affiliates if the
          services are provided pursuant to written contracts and in compliance
          with Section 4.03(d)(7) or pursuant to the Managing General Partner's
          role as Tax Matters Partner.

     17.  "Distribution Interest" means an undivided interest in the
          Partnership's assets after payments to the Partnership's creditors or
          the creation of a reasonable reserve therefor, in the ratio the
          positive balance of a

                                       3
party's Capital Account bears to the aggregate positive balance of the
          Capital Accounts of all of the parties determined after taking into
          account all Capital Account adjustments for the taxable year during
          which liquidation occurs (other than those made pursuant to
          liquidating distributions or restoration of deficit Capital Account
          balances). Provided, however, after the Capital Accounts of all of the
          parties have been reduced to zero, the interest in the remaining
          Partnership assets shall equal a party's interest in the related
          Partnership revenues as set forth in Section 5.01 and its subsections.

     18.  "Drilling and Operating Agreement" means the proposed Drilling and
          Operating Agreement between the Managing General Partner or an
          Affiliate as Operator, and the Partnership as Developer, a copy of the
          proposed form of which is attached to this Agreement as Exhibit (II).

     19.  "Exploratory Well" means a well drilled to:

          (i)   find commercially productive hydrocarbons in an unproved area;

          (ii)  find a new commercially productive Horizon in a field previously
                found to be productive of hydrocarbons at another Horizon; or

          (iii) significantly extend a known prospect.

     20.  "Farmout" means an agreement by the owner of the leasehold or Working
          Interest to assign his interest in certain acreage or well to the
          assignees, retaining some interest such as an Overriding Royalty
          Interest, an oil and gas payment, offset acreage or other type of
          interest, subject to the drilling of one or more specific wells or
          other performance as a condition of the assignment.

     21.  "Final Terminating Event" means any one of the following:

          (i)   the expiration of the Partnership's fixed term;

          (ii)  notice to the Participants by the Managing General Partner of
                its election to terminate the Partnership's affairs;

          (iii) notice by the Participants to the Managing General Partner of
                their similar election through the affirmative vote of
                Participants whose Units equal a majority of the total Units; or

          (iv)  the termination of the Partnership under Section 708(b)(1)(A) of
                the Code or the Partnership ceases to be a going concern.

     22.  "Horizon" means a zone of a particular formation; that part of a
          formation of sufficient porosity and permeability to form a petroleum
          reservoir.

     23.  "Independent Expert" means a person with no material relationship to
          the Sponsor or its Affiliates who is qualified and in the business of
          rendering opinions regarding the value of natural gas and oil
          properties based on the evaluation of all pertinent economic,
          financial, geologic and engineering information available to the
          Sponsor or its Affiliates.

     24.  "Initial Closing Date" means the date after the minimum amount of
          subscription proceeds has been received when subscription proceeds are
          first withdrawn from the escrow account.

     25.  "Intangible Drilling Costs" or "Non-Capital Expenditures" means those
          expenditures associated with property acquisition and the drilling and
          completion of natural gas and oil wells that under present law are
          generally accepted as fully deductible currently for federal income
          tax purposes. This includes:

          (i)  all expenditures made for any well before production in
               commercial quantities for wages, fuel, repairs, hauling, supplies
               and other costs and expenses incident to and necessary for
               drilling the

                                       4
well and preparing the well for production of natural gas or oil,
               that are currently deductible pursuant to Section 263(c) of the
               Code and Treasury Reg. Section 1.612-4, and are generally termed
               "intangible drilling and development costs,";

          (ii) the expense of plugging and abandoning any well before a
               completion attempt; and

          (iii) the costs (other than Tangible Costs and Lease acquisition
               costs) to re-enter and deepen an existing well, complete the well
               to deeper reservoirs, or plug and abandon the well if it is
               nonproductive from the targeted deeper reservoirs.

     26.  "Interim Closing Date" means those date(s) after the Initial Closing
          Date, but before the Offering Termination Date, that the Managing
          General Partner, in its sole discretion, applies additional
          subscription proceeds to additional Partnership activities, including
          drilling activities.

     27.  "Investor General Partners" means:

          (i)  the Persons signing the Subscription Agreement as Investor
               General Partners; and

          (ii) the Managing General Partner to the extent of any optional
               subscription as an Investor General Partner under Section
               3.03(b)(1).

          All Investor General Partners shall be of the same class and have the
          same rights.

     28.  "Landowner's Royalty Interest" means an interest in production, or its
          proceeds, to be received free and clear of all costs of development,
          operation, or maintenance, reserved by a landowner on the creation of
          a Lease.

     29.  "Leases" means full or partial interests in natural gas and oil
          leases, oil and natural gas mineral rights, fee rights, licenses,
          concessions, or other rights under which the holder is entitled to
          explore for and produce oil and/or natural gas, and includes any
          contractual rights to acquire any such interest.

     30.  "Limited Partners" means:

          (i)  the Persons signing the Subscription Agreement as Limited
               Partners;

          (ii) the Managing General Partner to the extent of any optional
               subscription as a Limited Partner under Section 3.03(b)(1);

          (iii) the Investor General Partners on the conversion of their
               Investor General Partner Units to Limited Partner Units pursuant
               to Section 6.01(b); and

          (iv) any other Persons who are admitted to the Partnership as
               additional or substituted Limited Partners.

          Except as provided in Section 3.05(b), with respect to the required
          additional Capital Contributions of Investor General Partners, all
          Limited Partners shall be of the same class and have the same rights.

     31.  "Managing General Partner" means:

          (i)  Atlas; or

          (ii) any Person admitted to the Partnership as a general partner,
               other than as an Investor General Partner, who is designated to
               exclusively supervise and manage the operations of the
               Partnership.

     32.  "Managing General Partner Signature Page" means an execution and
          subscription instrument in the form attached as Exhibit (I-A) to this
          Agreement, which is incorporated in this Agreement by reference.

                                       5
33.  "Offering Termination Date" means the date after the minimum amount of
          subscription proceeds has been received on which the Managing General
          Partner determines, in its sole discretion, that the Partnership's
          subscription period is closed and the acceptance of subscriptions
          ceases, which may be any date up to and including December 31, 2007.

          Notwithstanding the above, the Offering Termination Date may not
          extend beyond the time that subscriptions for the maximum number of
          Units set forth in Section 3.03(c)(1) have been received and accepted
          by the Managing General Partner.

     34.  "Operating Costs" means expenditures made and costs incurred in
          producing and marketing natural gas or oil from completed wells. These
          costs include, but are not limited to:

          (i)  labor, fuel, repairs, hauling, materials, supplies, utility
               charges and other costs incident to or related to producing and
               marketing natural gas and oil;

          (ii) ad valorem and severance taxes;

          (iii) insurance and casualty loss expense; and

          (iv) compensation to well operators or others for services rendered in
               conducting these operations.

          Operating Costs also include reworking, workover, subsequent
          equipping, and similar expenses relating to any well, the Managing
          General Partner's gathering fees set forth in Section 4.04(a)(2)(d)
          and the reimbursement of the Managing General Partner's Administrative
          Costs set forth in Section 4.04(a)(2)(c); but do not include the costs
          to re-enter and deepen an existing well, complete the well to deeper
          formations or reservoirs, or plug and abandon the well if it is
          nonproductive from the targeted deeper formations or reservoirs.

     35.  "Operator" means Atlas, as operator of Partnership Wells in
          Pennsylvania, and Atlas or an Affiliate as Operator of Partnership
          Wells in other areas of the United States.

     36.  "Organization and Offering Costs" means all costs of organizing and
          selling the offering including, but not limited to:

          (i)  total underwriting and brokerage discounts and commissions,
               including fees of the underwriters' attorneys, the Dealer-Manager
               fee, sales commissions and the up to .5% reimbursement for bona
               fide due diligence expenses;

          (ii) expenses for printing, engraving, mailing, salaries of employees
               while engaged in sales activities, charges of transfer agents,
               registrars, trustees, escrow holders, depositaries, engineers and
               other experts;

          (iii) expenses of qualification of the sale of the securities under
               federal and state law, including taxes and fees, accountants' and
               attorneys' fees; and

          (iv) other front-end fees.

     37.  "Organization Costs" means all costs of organizing the offering
          including, but not limited to:

          (i)  expenses for printing, engraving, mailing, salaries of employees
               while engaged in sales activities, charges of transfer agents,
               registrars, trustees, escrow holders, depositaries, engineers and
               other experts;

          (ii) expenses of qualification of the sale of the securities under
               federal and state law, including taxes and fees, accountants' and
               attorneys' fees; and

                                       6
(iii) other front-end fees.

     38.  "Overriding Royalty Interest" means an interest in the natural gas and
          oil produced under a Lease, or the proceeds from the sale thereof,
          carved out of the Working Interest, to be received free and clear of
          all costs of development, operation, or maintenance.

     39.  "Participants" means:

          (i)  the Managing General Partner to the extent of its optional
               subscription under Section 3.03(b)(1);

          (ii) the Limited Partners; and

          (iii) the Investor General Partners.

     40.  "Partners" means:

          (i)  the Managing General Partner;

          (ii) the Investor General Partners; and

          (iii) the Limited Partners.

     41.  "Partnership" means Atlas America Public #16-2007(A) L.P. [Atlas
          America Public #16-2007(B) L.P.].

     42.  "Partnership Net Production Revenues" means gross revenues after
          deduction of the related Operating Costs, Direct Costs, Administrative
          Costs and all other Partnership costs not specifically allocated.

     43.  "Partnership Well" means a well, some portion of the revenues from
          which is received by the Partnership.

     44.  "Person" means a natural person, partnership, corporation,
          association, trust or other legal entity.

     45.  "Production Purchase" or "Income" Program means any program whose
          investment objective is to directly acquire, hold, operate, and/or
          dispose of producing oil and gas properties. Such a program may
          acquire any type of ownership interest in a producing property,
          including, but not limited to, working interests, royalties, or
          production payments. A program which spends at least 90% of capital
          contributions and funds borrowed (excluding offering and
          organizational expenses) in the above described activities is presumed
          to be a production purchase or income program.

     46.  "Program" means one or more limited or general partnerships or other
          investment vehicles formed, or to be formed, for the primary purpose
          of:

          (i)  exploring for natural gas, oil and other hydrocarbon substances;
               or

          (ii) investing in or holding any property interests which permit the
               exploration for or production of hydrocarbons or the receipt of
               such production or its proceeds.

     47.  "Prospect" means an area covering lands which are believed by the
          Managing General Partner to contain subsurface structural or
          stratigraphic conditions making it susceptible to the accumulations of
          hydrocarbons in commercially productive quantities at one or more
          Horizons. The area, which may be different for different Horizons,
          shall be:

          (i)  designated by the Managing General Partner in writing before the
               conduct of Partnership operations; and

                                       7
(ii) enlarged or contracted from time to time on the basis of
               subsequently acquired information to define the anticipated
               limits of the associated hydrocarbon reserves and to include all
               acreage encompassed therein.

          If the well to be drilled by the Partnership is to a Horizon
          containing Proved Reserves, then a "Prospect" for a particular Horizon
          may be limited to the minimum area permitted by state law or local
          practice, whichever is applicable, to protect against drainage from
          adjacent wells. Subject to the foregoing sentence, "Prospect" shall be
          deemed the drilling or spacing unit for the Clinton/Medina geological
          formation and the Mississippian and/or Upper Devonian Sandstone
          reservoirs in Ohio, Pennsylvania, and New York and the Mississippian
          Carbonate or the Devonian Shale reservoirs in Anderson, Campbell,
          Morgan, Roane and Scott Counties, Tennessee.

     48.  "Prospectus" means the Prospectus included in the Registration
          Statement on Form S-1 relating to the offer and sale of the Units
          which has been filed with the Securities and Exchange Commission (the
          "Commission") under the Securities Act of 1933, as amended (the
          "Act"). As used in this Agreement, the terms "Prospectus" and
          "Registration Statement" refer solely to the Prospectus and
          Registration Statement, as amended, described above, except that:

          (i)  from and after the date on which any post-effective amendment to
               the Registration Statement is declared effective by the
               Commission, the term "Registration Statement" shall refer to the
               Registration Statement as amended by that post-effective
               amendment, and the term "Prospectus" shall refer to the
               Prospectus then forming a part of the Registration Statement; and

          (ii) if the Prospectus filed pursuant to Rule 424(b) or (c)
               promulgated by the Commission under the Act differs from the
               Prospectus on file with the Commission at the time the
               Registration Statement or any post-effective amendment thereto
               shall have become effective, the term "Prospectus" shall refer to
               the Prospectus filed pursuant thereto from and after the date on
               which it was filed.

     49.  "Proved Developed Oil and Gas Reserves" means reserves that can be
          expected to be recovered through existing wells with existing
          equipment and operating methods. Additional oil and gas expected to be
          obtained through the application of fluid injection or other improved
          recovery techniques for supplementing the natural forces and
          mechanisms of primary recovery should be included as "proved developed
          reserves" only after testing by a pilot project or after the operation
          of an installed program has confirmed through production response that
          increased recovery will be achieved.

     50.  "Proved Reserves" means the estimated quantities of crude oil, natural
          gas, and natural gas liquids which geological and engineering data
          demonstrate with reasonable certainty to be recoverable in future
          years from known reservoirs under existing economic and operating
          conditions, i.e., prices and costs as of the date the estimate is
          made. Prices include consideration of changes in existing prices
          provided only by contractual arrangements, but not on escalations
          based upon future conditions.

          (i)   Reservoirs are considered proved if economic producibility is
                supported by either actual production or conclusive formation
                test. The area of a reservoir considered proved includes:

               (a)  that portion delineated by drilling and defined by gas-oil
                    and/or oil-water contacts, if any; and

               (b)  the immediately adjoining portions not yet drilled, but
                    which can be reasonably judged as economically productive on
                    the basis of available geological and engineering data.

          In the absence of information on fluid contacts, the lowest known
          structural occurrence of hydrocarbons controls the lower proved limit
          of the reservoir.

                                       8
(ii)  Reserves which can be produced economically through application
                of improved recovery techniques (such as fluid injection) are
                included in the "proved" classification when successful testing
                by a pilot project, or the operation of an installed program in
                the reservoir, provides support for the engineering analysis on
                which the project or program was based.

          (iii) Estimates of proved reserves do not include the following:

               (a)  oil that may become available from known reservoirs but is
                    classified separately as "indicated additional reserves";

               (b)  crude oil, natural gas, and natural gas liquids, the
                    recovery of which is subject to reasonable doubt because of
                    uncertainty as to geology, reservoir characteristics, or
                    economic factors;

               (c)  crude oil, natural gas, and natural gas liquids, that may
                    occur in undrilled prospects; and

               (d)  crude oil, natural gas, and natural gas liquids, that may be
                    recovered from oil shales, coal, gilsonite and other such
                    sources.

     51.  "Proved Undeveloped Reserves" means reserves that are expected to be
          recovered from either:

          (i)  new wells on undrilled acreage; or

          (ii) from existing wells where a relatively major expenditure is
               required for recompletion.

          Reserves on undrilled acreage shall be limited to those drilling units
          offsetting productive units that are reasonably certain of production
          when drilled. Proved reserves for other undrilled units can be claimed
          only where it can be demonstrated with certainty that there is
          continuity of production from the existing productive formation. Under
          no circumstances should estimates for proved undeveloped reserves be
          attributable to any acreage for which an application of fluid
          injection or other improved recovery technique is contemplated, unless
          such techniques have been proved effective by actual tests in the area
          and in the same reservoir.

     52.  "Roll-Up" means a transaction involving the acquisition, merger,
          conversion or consolidation, either directly or indirectly, of the
          Partnership and the issuance of securities of a Roll-Up Entity. The
          term does not include:

          (i)  a transaction involving securities of the Partnership that have
               been listed for at least 12 months on a national exchange or
               traded through the National Association of Securities Dealers
               Automated Quotation National Market System; or

          (ii) a transaction involving the conversion to corporate, trust or
               association form of only the Partnership if, as a consequence of
               the transaction, there will be no significant adverse change in
               any of the following:

               (a)  voting rights;

               (b)  the Partnership's term of existence;

               (c)  the Managing General Partner's compensation; and

               (d)  the Partnership's investment objectives.

     53.  "Roll-Up Entity" means a partnership, trust, corporation or other
          entity that would be created or survive after the successful
          completion of a proposed roll-up transaction.

                                       9
54.  "Sales Commissions" means all underwriting and brokerage discounts and
          commissions incurred in the sale of Units payable to registered
          broker/dealers, but excluding the following:

          (i)  the 2.5% Dealer-Manager fee; and

          (ii) the up to .5% reimbursement for bona fide due diligence expenses.

     55.  "Selling Agents" means the broker/dealers which are selected by the
          Dealer-Manager to participate in the offer and sale of the Units.

     56.  "Sponsor" means any person directly or indirectly instrumental in
          organizing, wholly or in part, a program or any person who will manage
          or is entitled to manage or participate in the management or control
          of a program. The definition includes:

          (i)  the managing and controlling general partner(s) and any other
               person who actually controls or selects the person who controls
               25% or more of the exploratory, development or producing
               activities of the program, or any segment thereof, even if that
               person has not entered into a contract at the time of formation
               of the program; and

          (ii) whenever the context so requires, the term "sponsor" shall be
               deemed to include its affiliates.

               "Sponsor" does not include wholly independent third-parties such
               as attorneys, accountants, and underwriters whose only
               compensation is for professional services rendered in connection
               with the offering of units.

     57.  "Subscription Agreement" means an execution and subscription
          instrument in the form attached as Exhibit (I-B) to this Agreement,
          which is incorporated in this Agreement by reference.

     58.  "Tangible Costs" or "Capital Expenditures" means those costs
          associated with property acquisition and drilling and completing
          natural gas and oil wells which are generally accepted as capital
          expenditures under the Code. This includes all of the following:

          (i)   costs of equipment, parts and items of hardware used in drilling
                and completing a well;

          (ii)  the costs (other than Intangible Drilling Costs and Lease
                acquisition costs) to re-enter and deepen an existing well,
                complete the well to deeper reservoirs, or plug and abandon the
                well if it is nonproductive from the targeted deeper reservoirs;
                and

          (iii) those items necessary to deliver acceptable natural gas and oil
                production to purchasers to the extent installed downstream from
                the wellhead of any well and which are required to be
                capitalized under the Code and its regulations.

     59.  "Tax Matters Partner" means the Managing General Partner.

     60.  "Units" or "Units of Participation" means up to 100 Limited Partner
          interests in the Partnership and up to 19,900 Investor General Partner
          interests in the Partnership, which will be converted to up to 19,900
          Limited Partner Units as set forth in Section 6.01(b), purchased by
          Participants in the Partnership under the provisions of Section 3.03
          and its subsections, including any rights to profits, losses, income,
          gain, credits, deductions, cash distributions or returns of capital or
          other attributes of the Units.

     61.  "Working Interest" means an interest in a Lease which is subject to
          some portion of the cost of development, operation, or maintenance of
          the Lease.

                                       10
ARTICLE III
                 SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS

3.01. DESIGNATION OF MANAGING GENERAL PARTNER AND PARTICIPANTS. Atlas shall
serve as Managing General Partner of the Partnership. Atlas shall further serve
as a Participant to the extent of any subscription made by it pursuant to
Section 3.03(b)(1).

Limited Partners and Investor General Partners, including the Managing General
Partner and its Affiliates to the extent, if any, they purchase Units, shall
serve as Participants.

3.02. PARTICIPANTS.

3.02(a). LIMITED PARTNER AT FORMATION. Atlas America, Inc., as Original Limited
Partner, has acquired one Unit and has made a Capital Contribution of $100. On
the admission of one or more Limited Partners, the Partnership shall return to
the Original Limited Partner its Capital Contribution and shall reacquire its
Unit. The Original Limited Partner shall then cease to be a Limited Partner in
the Partnership with respect to that Unit.

3.02(b). OFFERING OF INTERESTS. The Partnership is authorized to admit to the
Partnership at the Initial Closing Date, any Interim Closing Date(s), and the
Offering Termination Date additional Participants whose Subscription Agreements
are accepted by the Managing General Partner if, after the admission of the
additional Participants, the total Units sold do not exceed the maximum number
of Units set forth in Section 3.03(c)(1).

3.02(c). ADMISSION OF PARTICIPANTS. No action or consent by the Participants
shall be required for the admission of additional Participants pursuant to this
Agreement.

All subscribers' funds shall be held in an interest bearing account or accounts
by an independent escrow holder and shall not be released to the Partnership
until the receipt and acceptance of the minimum amount of subscription proceeds
set forth in Section 3.03(c)(2). Thereafter, subscriptions may be paid directly
to the Partnership account.

3.03. SUBSCRIPTIONS TO THE PARTNERSHIP.

3.03(a). SUBSCRIPTIONS BY PARTICIPANTS.

3.03(a)(1). SUBSCRIPTION PRICE AND MINIMUM SUBSCRIPTION. The subscription price
of a Unit in the Partnership shall be $10,000, except as set forth below, and
shall be designated on each Participant's Subscription Agreement and payable as
set forth in Section 3.05(b)(1). The minimum subscription per Participant shall
be one Unit ($10,000). Larger subscriptions shall be accepted in $1,000
increments, beginning with $11,000, $12,000, etc.

Notwithstanding the foregoing, the subscription price for:

     (i)  the Managing General Partner, its officers, directors, and Affiliates,
          and Participants who buy Units through the officers and directors of
          the Managing General Partner, shall be reduced by an amount equal to
          the 2.5% Dealer-Manager fee, the 7% Sales Commission and the .5%
          reimbursement of the Selling Agents' bona fide due diligence expenses,
          which shall not be paid with respect to those sales; and

     (ii) Registered Investment Advisors and their clients, and Selling Agents
          and their registered representatives and principals, shall be reduced
          by an amount equal to the 7% Sales Commission, which shall not be paid
          with respect to those sales.

No more than 5% of the total Units in the Partnership shall be sold with the
discounts described above.

3.03(a)(2). EFFECT OF SUBSCRIPTION. Execution of a Subscription Agreement shall
serve as an agreement by the Participant to be bound by each and every term of
this Agreement.

                                       11
3.03(b). OPTIONAL SUBSCRIPTIONS FOR UNITS BY MANAGING GENERAL PARTNER.

3.03(b)(1). MANAGING GENERAL PARTNER'S OPTIONAL SUBSCRIPTIONS FOR UNITS. In
addition to the Managing General Partner's required Capital Contributions under
Section 3.04(a), the Managing General Partner may subscribe for up to 5% of the
total Units sold in the Partnership under the provisions of Section 3.03(a) and
its subsections, and, subject to the limitations on voting rights set forth in
Section 4.03(c)(3), to that extent shall be deemed to be a Participant in the
Partnership for all purposes under this Agreement.

3.03(b)(2). EFFECT OF AND EVIDENCING SUBSCRIPTION. The Managing General Partner
has executed a Managing General Partner Signature Page which:

     (i)  evidences the Managing General Partner's required Capital
          Contributions under Section 3.04(a); and

     (ii) may be amended, from time-to-time, to reflect the amount of any
          optional subscriptions for Units as a Participant under Section
          3.03(b)(1).

Execution of the Managing General Partner Signature Page serves as an agreement
by the Managing General Partner to be bound by each and every term of this
Agreement.

3.03(c). MAXIMUM AND MINIMUM NUMBER OF UNITS.

3.03(c)(1). MAXIMUM NUMBER OF UNITS. The maximum number of Units may not exceed
20,000 Units, which is up to $200,000,000 of cash subscription proceeds,
excluding the subscription discounts permitted under Section 3.03(a)(1).
Notwithstanding the foregoing, the maximum number of Units in all of the
partnerships in the Atlas America Public #16-2007 Program, in the aggregate,
shall not exceed 20,000 Units which is up to $200,000,000 of cash subscription
proceeds excluding the subscription discounts permitted under Section
3.03(a)(1).

3.03(c)(2). MINIMUM NUMBER OF UNITS. The minimum number of Units shall equal at
least 200 Units, but in any event not less than the number of Units that
provides the Partnership with cash subscription proceeds of $2,000,000,
excluding the subscription discounts permitted under Section 3.03(a)(1).

If subscriptions for the minimum number of Units have not been received and
accepted at the Offering Termination Date, then all monies deposited by
subscribers shall be promptly returned to them. They shall receive interest
earned on their subscription proceeds from the date the monies were deposited in
escrow through the date of refund, without deduction for any fees.

The partnership may break escrow and begin its drilling activities, in the
Managing General Partner's sole discretion, on receipt and acceptance of the
minimum subscription proceeds.

3.03(d). ACCEPTANCE OF SUBSCRIPTIONS.

3.03(d)(1). DISCRETION BY THE MANAGING GENERAL PARTNER. Acceptance of
subscriptions is discretionary with the Managing General Partner. The Managing
General Partner may reject any subscription for any reason it deems appropriate.

3.03(d)(2). TIME PERIOD IN WHICH TO ACCEPT SUBSCRIPTIONS. Subscriptions shall be
accepted or rejected by the Managing General Partner within 30 days of their
receipt. If a subscription is rejected, then all of the subscriber's funds shall
be returned to the subscriber promptly, with interest earned and without
deduction for any fees.

3.03(d)(3). ADMISSION TO THE PARTNERSHIP. The Participants shall be admitted to
the Partnership as follows:

     (i)  not later than 15 days after the release from the escrow account of
          Participants' subscription proceeds to the Partnership; or

                                       12
(ii) if a Participant's subscription proceeds are received by the
          Partnership after the close of the escrow account, then not later than
          the last day of the calendar month in which his Subscription Agreement
          was accepted by the Managing General Partner.

3.04. CAPITAL CONTRIBUTIONS OF THE MANAGING GENERAL PARTNER.

3.04(a). MANAGING GENERAL PARTNER'S REQUIRED CAPITAL CONTRIBUTIONS. The Managing
General Partner, as a general partner and not as a Participant, is required to
pay the costs or make the other required Capital Contributions charged to it
under this Agreement, including contributing to the Partnership the Leases which
will be drilled by the Partnership on the terms set forth in Section 4.01(a)(4),
in an amount equal to not less than 25%, in the aggregate, of all Capital
Contributions to the Partnership, at the time the costs are required to be paid
by the Partnership, but no later than December 31, 2008.

3.04(b). ON LIQUIDATION THE MANAGING GENERAL PARTNER MUST CONTRIBUTE DEFICIT
BALANCE IN ITS CAPITAL ACCOUNT. The Managing General Partner shall contribute to
the Partnership any deficit balance in its Capital Account on the occurrence of
either of the following events:

     (i)  the liquidation of the Partnership; or

     (ii) the liquidation of the Managing General Partner's interest in the
          Partnership.

This shall be determined after taking into account all adjustments for the
Partnership's taxable year during which the liquidation occurs, other than
adjustments made pursuant to this requirement, by the end of the taxable year in
which the liquidation occurs or, if later, within 90 days after the date of the
liquidation.

3.04(c). MANAGING GENERAL PARTNER'S PARTNERSHIP INTEREST FOR CAPITAL
CONTRIBUTIONS. The interest of the Managing General Partner, as Managing General
Partner and not as a Participant, in the capital and profits of the Partnership
is fully vested and nonforfeitable as of the date of the formation of the
Partnership and is in consideration for, and is the only consideration for, its
required Capital Contributions to the Partnership.

3.04(d). MANAGING GENERAL PARTNER'S RIGHT TO ASSIGN ITS PARTNERSHIP INTEREST.
Subject to Section 5.01(b)(4)(a) regarding the Managing General Partner's
subordination obligation, the Managing General Partner has the right at any
time, in its discretion, without the consent of the Participants, and without
affecting the allocation of costs and revenues to the Participants or the
Managing General Partner's voting rights under this Agreement, to sell,
contribute, exchange or otherwise transfer all or any portion of its interest as
Managing General Partner or as a Participant (if it purchases Units) in the
Partnership, or any interest therein to an Affiliate of the Managing General
Partner. In that event, except as otherwise may be permitted under this
Agreement, if the Affiliated transferee of the Managing General Partner's
transferred interest in the Partnership does not become a substituted Managing
General Partner in the Partnership, the Affiliated transferee, as a partner in
the Partnership for tax purposes only, shall have the right to receive the share
of the Partnership's profits, losses, income, gains, deductions, credits and
depletion allowances, or items thereof, and cash distributions and returns of
capital (including, but not limited to, cash distributions and returns of
capital on dissolution and liquidation of the Partnership) to which the Managing
General Partner would otherwise be entitled under this Agreement with respect to
its transferred interest in the Partnership.

Subject to the foregoing, the transfer of the Managing General Partner's
interest in the Partnership to any of its Affiliates may be made on any terms
and conditions as the Managing General Partner determines, in its discretion,
and the Partnership and the Participants shall have no right to receive or
otherwise share in any consideration received by the Managing General Partner
from its Affiliates for the transfer of the Managing General Partner's interest
in the Partnership.

No transfer of the Managing General Partner's interest in the Partnership to its
Affiliates under this Section 3.04(d) shall require an accounting by the
Managing General Partner or the Partnership to the Participants.

                                       13
3.05. PAYMENT OF SUBSCRIPTIONS.

3.05(a). MANAGING GENERAL PARTNER'S SUBSCRIPTIONS. The Managing General Partner
shall pay any optional subscription under Section 3.03(b)(1) as set forth in
Section 3.05(b)(1).

3.05(b). PARTICIPANT SUBSCRIPTIONS AND ADDITIONAL CAPITAL CONTRIBUTIONS OF THE
INVESTOR GENERAL PARTNERS.

3.05(b)(1). PAYMENT OF SUBSCRIPTION AGREEMENTS. A Participant shall pay the
subscription amount designated on his Subscription Agreement 100% in cash at the
time of subscribing. A Participant shall receive interest on the amount he pays
from the time his subscription proceeds are deposited in the escrow account, or
a Partnership account after the minimum number of Units have been received as
provided in Section 3.06(b), until the Offering Termination Date.

3.05(b)(2). ADDITIONAL REQUIRED CAPITAL CONTRIBUTIONS OF THE INVESTOR GENERAL
PARTNERS. Investor General Partners must make Capital Contributions to the
Partnership when called by the Managing General Partner, in addition to their
subscription amounts, for their pro rata share of any Partnership obligations
and liabilities which are recourse to the Investor General Partners and are
represented by their ownership of Units before the conversion of Investor
General Units to Limited Partner Units under Section 6.01(b).

3.05(b)(3). DEFAULT PROVISIONS. The failure of an Investor General Partner to
timely make a required additional Capital Contribution under this section
results in his personal liability to the other Investor General Partners for the
amount in default. The remaining Investor General Partners, in proportion to
their respective number of Units, must pay the defaulting Investor General
Partner's share of Partnership liabilities and obligations called for by the
Managing General Partner. In that event, the remaining Investor General
Partners:

     (i)   shall have a first and preferred lien on the defaulting Investor
           General Partner's interest in the Partnership to secure payment of
           the amount in default plus interest at the legal rate;

     (ii)  shall be entitled to receive 100% of the defaulting Investor General
           Partner's cash distributions, in proportion to their respective
           number of Units, until the amount in default is recovered in full
           plus interest at the legal rate; and

     (iii) may commence legal action to collect the amount due plus interest at
           the legal rate.

3.06. PARTNERSHIP FUNDS.

3.06(a). FIDUCIARY DUTY. The Managing General Partner has a fiduciary
responsibility for the safekeeping and use of all funds and assets of the
Partnership, whether or not in the Managing General Partner's possession or
control. The Managing General Partner shall not employ, or permit another to
employ, the funds and assets of the Partnership in any manner except for the
exclusive benefit of the Partnership.

Neither this Agreement nor any other agreement between the Managing General
Partner and the Partnership shall contractually limit any fiduciary duty owed to
the Participants by the Managing General Partner under applicable law, except as
provided in Sections 4.01, 4.02, 4.03, 4.04, 4.05 and 4.06 of this Agreement.

3.06(b). SPECIAL ACCOUNT AFTER THE RECEIPT OF THE MINIMUM PARTNERSHIP
SUBSCRIPTIONS. Following the receipt of the minimum number of Units and breaking
escrow, the funds of the Partnership shall be held in a separate
interest-bearing account maintained for the Partnership and shall not be
commingled with funds of any other entity.

3.06(c). INVESTMENT.

3.06(c)(1). INVESTMENTS IN OTHER ENTITIES. Partnership funds shall not be
invested in the securities of another person except in the following instances:

     (i)   investments in Working Interests or undivided Lease interests made in
           the ordinary course of the Partnership's business;

                                       14
(ii)  temporary investments made as set forth in Section 3.06(c)(2);

     (iii) multi-tier arrangements meeting the requirements of Section
           4.03(d)(15);

     (iv)  investments involving less than 5% of the Partnership's subscription
           proceeds which are a necessary and incidental part of a property
           acquisition transaction; and

     (v)   investments in entities established solely to limit the Partnership's
           liabilities associated with the ownership or operation of property or
           equipment, provided that duplicative fees and expenses shall be
           prohibited.

3.06(c)(2). PERMISSIBLE INVESTMENTS BEFORE INVESTMENT IN PARTNERSHIP ACTIVITIES.
After the Initial Closing Date and until proceeds from the offering are invested
in the Partnership's operations, the proceeds may be temporarily invested in
income producing short-term, highly liquid investments, in which there is
appropriate safety of principal, such as U.S. Treasury Bills.

                                   ARTICLE IV
                              CONDUCT OF OPERATIONS

4.01. ACQUISITION OF LEASES.

4.01(a). ASSIGNMENT TO PARTNERSHIP.

4.01(a)(1). IN GENERAL. The Managing General Partner shall select, acquire and
assign or cause to have assigned to the Partnership full or partial interests in
Leases, by any method customary in the natural gas and oil industry, subject to
the terms and conditions set forth below.

The Partnership and the other partnerships in the Atlas America Public #16-2007
Program may acquire and develop interests in Leases covering one or more of the
same Prospects, in the Managing General Partner's discretion.

The Partnership shall acquire only Leases reasonably expected to meet the stated
purposes of the Partnership. No Leases shall be acquired for the purpose of a
subsequent sale, Farmout, or other disposition unless the acquisition is made
after a well has been drilled to a depth sufficient to indicate that the
acquisition would be in the Partnership's best interest.

4.01(a)(2). FEDERAL AND STATE LEASES. The Partnership is authorized to acquire
Leases on federal and state lands.

4.01(a)(3). MANAGING GENERAL PARTNER'S DISCRETION AS TO TERMS AND BURDENS OF
ACQUISITION. Subject to the provisions of Section 4.03(d) and its subsections,
the acquisitions of Leases or other property may be made under any terms and
obligations, including any limitations as to the Horizons to be assigned to the
Partnership and subject to any burdens as the Managing General Partner deems
necessary in its sole discretion.

4.01(a)(4). COST OF LEASES. All Leases shall be:

     (i)  contributed to the Partnership by the Managing General Partner or its
          Affiliates; and

     (ii) credited towards the Managing General Partner's required Capital
          Contribution set forth in Section 3.04(a) at the Cost of the Lease,
          unless the Managing General Partner has cause to believe that Cost is
          materially more than the fair market value of the property, in which
          case the credit for the contribution must be made at a price not in
          excess of the fair market value.

A determination of fair market value must be supported by an appraisal from an
Independent Expert.

4.01(a)(5). THE MANAGING GENERAL PARTNER, OPERATOR OR THEIR AFFILIATES' RIGHTS
IN THE REMAINDER INTERESTS. Subject to the provisions of Section 4.03(d) and its
subsections, to the extent the Partnership does not acquire a full interest in a
Lease from the Managing General Partner or its Affiliates, the remainder of the
interest in the Lease may be held by the Managing General Partner or its
Affiliates. They may either:

                                       15
(i)  retain and exploit the remaining interest for their own account; or

     (ii) sell or otherwise dispose of all or a part of the remaining interest.

Profits from the exploitation and/or disposition of their retained interests in
the Leases shall be for the benefit of the Managing General Partner or its
Affiliates to the exclusion of the Partnership and the Participants.

4.01(a)(6). NO BREACH OF DUTY. Subject to the provisions of Section 4.03 and its
subsections, acquisition of Leases from the Managing General Partner, the
Operator or their Affiliates shall not be considered a breach of any obligation
owed by them to the Partnership or the Participants.

4.01(b). NO OVERRIDING ROYALTY INTERESTS. Neither the Managing General Partner,
the Operator nor any Affiliate shall retain any Overriding Royalty Interest on
the Leases acquired by the Partnership.

4.01(c). TITLE AND NOMINEE ARRANGEMENTS.

4.01(c)(1). LEGAL TITLE. Legal title to all Leases acquired by the Partnership
shall be held on a permanent basis in the name of the Partnership. However,
Partnership properties may be held temporarily in the name of:

     (i)   the Managing General Partner;

     (ii)  the Operator;

     (iii) their Affiliates; or

     (iv)  in the name of any nominee designated by the Managing General Partner
           to facilitate the acquisition of the properties.

4.01(c)(2). MANAGING GENERAL PARTNER'S DISCRETION. The Managing General Partner
shall take the steps which are necessary in its best judgment to render title to
the Leases to be acquired by the Partnership acceptable for the purposes of the
Partnership. The Managing General Partner shall be free, however, to use its own
best judgment in waiving title requirements.

The Managing General Partner shall not be liable to the Partnership or to the
other parties for any mistakes of judgment; nor shall the Managing General
Partner be deemed to be making any warranties or representations, express or
implied, as to the validity or merchantability of the title to the Leases
assigned to the Partnership or the extent of the interest covered thereby except
as otherwise provided in the Drilling and Operating Agreement.

4.01(c)(3). COMMENCEMENT OF OPERATIONS. The Partnership shall not begin
operations on its Leases unless the Managing General Partner is satisfied that
necessary title requirements have been satisfied.

4.02. CONDUCT OF OPERATIONS.

4.02(a). IN GENERAL. The Managing General Partner shall establish a program of
operations for the Partnership. Subject to the limitations contained in Article
III of this Agreement concerning the maximum Capital Contribution which can be
required of a Limited Partner, the Managing General Partner, the Limited
Partners, and the Investor General Partners agree to participate in the program
so established by the Managing General Partner.

4.02(b). MANAGEMENT. Subject to any restrictions contained in this Agreement,
the Managing General Partner shall exercise full control over all operations of
the Partnership.

4.02(c). GENERAL POWERS OF THE MANAGING GENERAL PARTNER.

4.02(c)(1). IN GENERAL. Subject to the provisions of Section 4.03 and its
subsections, and to any authority that may be granted the Operator under Section
4.02(c)(3)(b), the Managing General Partner shall have full authority to do all
things deemed necessary or

                                       16
desirable by it in the conduct of the business of the Partnership. Without
limiting the generality of the foregoing, the Managing General Partner is
expressly authorized to engage in:

     (i)    the making of all determinations of which Leases, wells and
            operations will be participated in by the Partnership, which
            includes:

            (a)  which Leases are developed;

            (b)  which Leases are abandoned; or

            (c)  which Leases are sold or assigned to other parties, including
                 other investor ventures organized by the Managing General
                 Partner, the Operator, or any of their Affiliates;

     (ii)   the negotiation and execution on any terms deemed desirable in its
            sole discretion of any contracts, conveyances, or other instruments,
            considered useful to the conduct of the operations or the
            implementation of the powers granted it under this Agreement,
            including, without limitation:

            (a)  the making of agreements for the conduct of operations,
                 including agreements and financial instruments relating to
                 hedging the Partnership's natural gas and oil;

            (b)  the exercise of any options, elections, or decisions under any
                 such agreements; and

            (c)  the furnishing of equipment, facilities, supplies and material,
                 services, and personnel;

     (iii)  the exercise, on behalf of the Partnership or the parties, as the
            Managing General Partner in its sole judgment deems best, of all
            rights, elections and options granted or imposed by any agreement,
            statute, rule, regulation, or order;

     (iv)   the making of all decisions concerning the desirability of payment,
            and the payment or supervision of the payment, of all delay rentals
            and shut-in and minimum or advance royalty payments;

     (v)    the selection of full or part-time employees and outside consultants
            and contractors and the determination of their compensation and
            other terms of employment or hiring;

     (vi)   the maintenance of insurance for the benefit of the Partnership and
            the parties as it deems necessary, but in no event less in amount or
            type than the following:

            (a)  worker's compensation insurance in full compliance with the
                 laws of the Commonwealth of Pennsylvania and any other
                 applicable state laws;

            (b)  liability insurance, including automobile, which has a
                 $1,000,000 combined single limit for bodily injury and property
                 damage in any one accident or occurrence and in the aggregate;
                 and

            (c)  liability and excess liability insurance as to bodily injury
                 and property damage with combined limits of $50,000,000 during
                 drilling operations and thereafter, per occurrence or accident
                 and in the aggregate, which includes $1,000,000 of seepage,
                 pollution and contamination insurance which protects and
                 defends the insured against property damage or bodily injury
                 claims from third-parties, other than a co-owner of the Working
                 Interest, alleging seepage, pollution or contamination damage
                 resulting from a pollution incident. The excess liability
                 insurance, which is for general liability only, shall be in
                 place and effective no later than the date drilling operations
                 begin and, for purposes of satisfying this requirement, the
                 Partnership shall have the benefit of the Managing General
                 Partner's $50,000,000 liability insurance on the same basis as
                 the Managing General Partner and its other Affiliates,
                 including the Managing General Partner's other Programs;

                                       17
(vii)  the use of the funds and revenues of the Partnership, and the
            borrowing on behalf of, and the loan of money to, the Partnership,
            on any terms it sees fit, for any purpose, including without
            limitation:

            (a)  the conduct or financing, in whole or in part, of the drilling
                 and other activities of the Partnership;

            (b)  the conduct of additional operations; and

            (c)  the repayment of any borrowings or loans used initially to
                 finance these operations or activities;

     (viii) the disposition, hypothecation, sale, exchange, release, surrender,
            reassignment or abandonment of any or all assets of the Partnership,
            including without limitation, the Leases, wells, equipment and
            production therefrom, provided that the sale of all or substantially
            all of the assets of the Partnership shall only be made as provided
            in Section 4.03(d)(6);

     (ix)   the formation of any further limited or general partnership, tax
            partnership, joint venture, or other relationship which it deems
            desirable with any parties who it, in its sole discretion, selects,
            including any of its Affiliates;

     (x)    the control of any matters affecting the rights and obligations of
            the Partnership, including:

            (a)  the employment of attorneys to advise and otherwise represent
                 the Partnership;

            (b)  the conduct of litigation and incurring other legal expenses;
                 and

            (c)  the settlement of claims and litigation;

     (xi)   the operation of producing wells drilled on the Leases or on a
            Prospect which includes any part of the Leases;

     (xii)  the exercise of the rights granted to it under the power of attorney
            created under this Agreement; and

     (xiii) the incurring of all costs and the making of all expenditures in any
            way related to any of the foregoing.

4.02(c)(2). SCOPE OF POWERS. The Managing General Partner's powers shall extend
to any operation participated in by the Partnership or affecting its Leases, or
other property or assets, irrespective of whether or not the Managing General
Partner is designated operator of the operation by any outside persons
participating therein.

4.02(c)(3). DELEGATION OF AUTHORITY.

4.02(c)(3)(a). IN GENERAL. The Managing General Partner may subcontract and
delegate all or any part of its duties under this Agreement to any entity chosen
by it, including an entity Affiliated with it, which party shall have the same
powers in the conduct of the duties as would the Managing General Partner. The
delegation, however, shall not relieve the Managing General Partner of its
responsibilities under this Agreement.

4.02(c)(3)(b). DELEGATION TO OPERATOR. The Managing General Partner is
specifically authorized to delegate any or all of its duties to the Operator by
executing the Drilling and Operating Agreement. This delegation shall not
relieve the Managing General Partner of its responsibilities under this
Agreement.

In no event shall any consideration received for operator services be in excess
of competitive rates or duplicative of any consideration or reimbursements
received under this Agreement. The Managing General Partner may not benefit by
interpositioning itself between the Partnership and the actual provider of
operator services.

4.02(c)(4). RELATED PARTY TRANSACTIONS. Subject to the provisions of Section
4.03 and its subsections, any transaction which the Managing General Partner is
authorized to enter into on behalf of the Partnership under the authority
granted in this section

                                       18
and its subsections, may be entered into by the Managing General Partner with
itself or with any other general partner, the Operator, or any of their
Affiliates.

4.02(d). ADDITIONAL POWERS. In addition to the powers granted the Managing
General Partner under Section 4.02(c) and its subsections or elsewhere in this
Agreement, the Managing General Partner, when specified, shall have the
following additional express powers.

4.02(d)(1). DRILLING CONTRACTS. All Partnership Wells shall be drilled under the
Drilling and Operating Agreement for an amount equal to the sum of the following
items:

     (i)   the Cost of permits, supplies, materials, equipment, and all other
           items used in the drilling and completion of a well provided by
           third-parties, or if the foregoing items are provided by Affiliates
           of the Managing General Partner, then those items will be charged at
           competitive rates;

     (ii)  fees for third-party services;

     (iii) fees for services provided by the Managing General Partner's
           Affiliates, which will be charged at competitive rates;

     (iv)  an administration and oversight fee of $15,000 per well, which will
           be charged to the Participants as part of each well's Intangible
           Drilling Costs and the portion of equipment costs paid by the
           Participants; and

     (v)   a mark-up in an amount equal to 15% of the sum of (i), (ii), (iii)
           and (iv), above, for the Managing General Partner's services as
           general drilling contractor.

The Managing General Partner or its Affiliates, as drilling contractor, may not
receive a rate that is not competitive with the rates charged by unaffiliated
contractors in the same geographic region, enter into a turnkey drilling
contract with the Partnership, profit by drilling in contravention of its
fiduciary obligations to the Partnership, or benefit by interpositioning itself
between the Partnership and the actual provider of drilling contractor services.

4.02(d)(2). POWER OF ATTORNEY.

4.02(d)(2)(a). IN GENERAL. Each Participant appoints the Managing General
Partner his true and lawful attorney-in-fact for him and in his name, place, and
stead and for his use and benefit, from time to time:

     (i)  to create, prepare, complete, execute, file, swear to, deliver,
          endorse, and record any and all documents, certificates, government
          reports, or other instruments as may be required by law, or are
          necessary to amend this Agreement as authorized under the terms of
          this Agreement, or to qualify the Partnership as a limited partnership
          or partnership in commendam and to conduct business under the laws of
          any jurisdiction in which the Managing General Partner elects to
          qualify the Partnership or conduct business; and

     (ii) to create, prepare, complete, execute, file, swear to, deliver,
          endorse and record any and all instruments, assignments, security
          agreements, financing statements, certificates, and other documents as
          may be necessary from time to time to implement the borrowing powers
          granted under this Agreement.

4.02(d)(2)(b). FURTHER ACTION. Each Participant authorizes the attorney-in-fact
to take any further action which the attorney-in-fact considers necessary or
advisable in connection with any of the foregoing powers and rights granted the
Managing General Partner under this section and its subsections. Each party
acknowledges that the power of attorney granted under Section 4.02(d)(2)(a):

     (i)  is a special power of attorney coupled with an interest and is
          irrevocable; and

     (ii) shall survive the assignment by the Participant of the whole or a
          portion of his Units; except when the assignment is of all of the
          Participant's Units and the purchaser, transferee, or assignee of the
          Units is admitted as a successor Participant, the power of attorney
          shall survive the delivery of the assignment for

                                       19
the sole purpose of enabling the attorney-in-fact to execute,
          acknowledge, and file any agreement, certificate, instrument or
          document necessary to effect the substitution.

4.02(d)(2)(c). POWER OF ATTORNEY TO OPERATOR. The Managing General Partner is
hereby authorized to grant a Power of Attorney to the Operator on behalf of the
Partnership.

4.02(e). BORROWINGS AND USE OF PARTNERSHIP REVENUES.

4.02(e)(1). POWER TO BORROW OR USE PARTNERSHIP REVENUES.

4.02(e)(1)(a). IN GENERAL. If additional funds over the Participants' Capital
Contributions are needed for Partnership operations, then the Managing General
Partner may:

     (i)  use Partnership revenues for such purposes; or

     (ii) the Managing General Partner and its Affiliates may advance the
          necessary funds to the Partnership under Section 4.03(d)(8)(b),
          although they are not obligated to advance the funds to the
          Partnership.

4.02(e)(1)(b). LIMITATION ON BORROWING. Partnership borrowings, other than
credit transactions on open account customary in the industry to obtain goods
and services, shall be subject to the following limitations:

     (i)  the borrowings must be without recourse to the Investor General
          Partners and the Limited Partners except as otherwise provided in this
          Agreement; and

     (ii) the amount that may be borrowed at any one time may not exceed an
          amount equal to 5% of the Partnership's subscription proceeds.

4.02(f). TAX MATTERS PARTNER.

4.02(f)(1). DESIGNATION OF TAX MATTERS PARTNER. The Managing General Partner is
hereby designated the Tax Matters Partner of the Partnership under Section
6231(a)(7) of the Code. The Managing General Partner is authorized to act in
this capacity on behalf of the Partnership and the Participants and to take any
action, including settlement or litigation, which it in its sole discretion
deems to be in the best interest of the Partnership.

4.02(f)(2). COSTS INCURRED BY TAX MATTERS PARTNER. Costs incurred by the Tax
Matters Partner shall be considered a Direct Cost of the Partnership.

4.02(f)(3). NOTICE TO PARTICIPANTS OF IRS PROCEEDINGS. The Tax Matters Partner
shall notify all of the Participants of any administrative or other legal
proceedings involving the Partnership and the IRS or any other taxing authority,
and thereafter shall furnish all of the Participants periodic reports at least
quarterly on the status of the proceedings.

4.02(f)(4). PARTICIPANT RESTRICTIONS. Each Participant agrees as follows:

     (i)   he will not file the statement described in Section 6224(c)(3)(B) of
           the Code prohibiting the Managing General Partner as the Tax Matters
           Partner for the Partnership from entering into a settlement on his
           behalf with respect to partnership items, as that term is defined in
           Section 6231(a)(3) of Code, of the Partnership;

     (ii)  he will not form or become and exercise any rights as a member of a
           group of Partners having a 5% or greater interest in the profits of
           the Partnership under Section 6223(b)(2) of the Code; and

     (iii) the Managing General Partner is authorized to file a copy of this
           Agreement, or pertinent portions of this Agreement, with the IRS
           under Section 6224(b) of the Code if necessary to perfect the waiver
           of rights under this subsection.

                                       20
4.03. GENERAL RIGHTS AND OBLIGATIONS OF THE PARTICIPANTS AND RESTRICTED AND
PROHIBITED TRANSACTIONS.

4.03(a)(1). LIMITED LIABILITY OF LIMITED PARTNERS. Limited Partners shall not be
bound by the obligations of the Partnership other than as provided under the
Delaware Revised Uniform Limited Partnership Act. Limited Partners shall not be
personally liable for any debts of the Partnership or any of the obligations or
losses of the Partnership beyond the subscription amount designated on the
Subscription Agreement executed by each respective Limited Partner unless:

     (i)  they also subscribe to the Partnership as Investor General Partners;
          or

     (ii) in the case of the Managing General Partner, it purchases Limited
          Partner Units.

4.03(a)(2). NO MANAGEMENT AUTHORITY OF PARTICIPANTS. Participants, other than
the Managing General Partner if it buys Units, shall have no power over the
conduct of the affairs of the Partnership. No Participant, other than the
Managing General Partner if it buys Units, shall take part in the management of
the business of the Partnership, or have the power to sign for or to bind the
Partnership.

4.03(b). REPORTS AND DISCLOSURES.

4.03(b)(1). ANNUAL REPORTS AND FINANCIAL STATEMENTS. Beginning with the calendar
year in which the Partnership had its Offering Termination Date, the Partnership
shall provide each Participant an annual report within 120 days after the close
of that calendar year, and beginning with the following calendar year, a report
within 75 days after the end of the first six months of its calendar year,
containing except as otherwise indicated, at least the information set forth
below:

     (i)   Audited financial statements of the Partnership, including a balance
           sheet and statements of income, cash flow, and Partners' equity,
           which shall be prepared on an accrual basis in accordance with
           generally accepted accounting principles with a reconciliation with
           respect to information furnished for income tax purposes and
           accompanied by an auditor's report containing an opinion of an
           independent public accountant selected by the Managing General
           Partner stating that his audit was made in accordance with generally
           accepted auditing standards and that in his opinion the financial
           statements present fairly the financial position, results of
           operations, partners' equity, and cash flows in accordance with
           generally accepted accounting principles. Semiannual reports are not
           required to be audited.

     (ii)  A summary itemization, by type and/or classification of the total
           fees and compensation, including any nonaccountable, fixed payment
           reimbursements for Administrative Costs and Operating Costs, paid by,
           or on behalf of, the Partnership to the Managing General Partner, the
           Operator, and their Affiliates.

           Also, the independent certified public accountant shall provide
           written attestation annually, which will be included in the annual
           report, that the method used to make allocations of the Partnership's
           Administrative Costs was consistent with the method described in
           Section 4.04(a)(2)(c) of this Agreement and that the total amount of
           Administrative Costs allocated did not materially exceed the amounts
           actually incurred by the Managing General Partner in providing
           administrative services to, or on behalf of, the Partnership as
           described in Section 4.04(a)(2)(c), including administrative services
           provided to the Partnership by the Managing General Partner's
           Affiliates or independent third-parties at the sole expense of the
           Managing General Partner. If the Managing General Partner
           subsequently decides to allocate Administrative Costs in a manner
           different from that described in Section 4.04(a)(2)(c) of this
           Agreement, then the change must be reported to the Participants
           together with an explanation of the reason for the change and the
           basis used for determining the reasonableness of the new allocation
           method.

     (iii) A description of each Prospect in which the Partnership owns an
           interest, including:

           (a)  the cost, location, and number of acres under Lease; and

           (b)  the Working Interest owned in the Prospect by the Partnership.

                                       21
Succeeding reports, however, must only contain material changes, if
           any, regarding the Prospects.

     (iv)  A list of the wells drilled or abandoned by the Partnership during
           the period of the report, indicating:

           (a)  whether each of the wells has or has not been completed;

           (b)  a statement of the cost of each well completed or abandoned; and

           (c)  justification for wells abandoned after production has begun.

     (v)   A description of all Farmouts, farmins, and joint ventures, made
           during the period of the report, including:

           (a)  the Managing General Partner's justification for the
                arrangement; and

           (b)  a description of the material terms.

     (vi)  A schedule reflecting:

           (a)  the total Partnership costs;

           (b)  the costs paid by the Managing General Partner and the costs
                paid by the Participants;

           (c)  the total Partnership revenues;

           (d)  the revenues received or credited to the Managing General
                Partner and the revenues received and credited to the
                Participants; and

           (e)  a reconciliation of the expenses and revenues in accordance with
                the provisions of Article V.

Additionally, on request the Managing General Partner will provide the
information specified by Form 10-Q (if such report is required to be filed with
the SEC) within 45 days after the close of each quarterly fiscal period.

4.03(b)(2). TAX INFORMATION. The Partnership shall, by March 15 of each year,
prepare, or supervise the preparation of, and transmit to each Participant the
information needed for the Participant to file the following:

     (i)   his federal income tax return;

     (ii)  any required state income tax return; and

     (iii) any other reporting or filing requirements imposed by any
           governmental agency or authority.

4.03(b)(3). RESERVE REPORT. Beginning with the second calendar year after the
Offering Termination Date and every year thereafter, the Partnership shall
provide to each Participant the following:

     (i)   a summary of the computation of the Partnership's total natural gas
           and oil Proved Reserves;

     (ii)  a summary of the computation of the present worth of the reserves
           determined using:

           (a)  a discount rate of 10%;

           (b)  a constant price for the oil; and

           (c)  basing the price of natural gas on the existing natural gas
                contracts;

     (iii) a statement of each Participant's interest in the reserves; and

                                       22
(iv)  an estimate of the time required for the extraction of the reserves
           with a statement that because of the time period required to extract
           the reserves the present value of revenues to be obtained in the
           future is less than if immediately receivable.

The reserve computations shall be based on engineering reports prepared by the
Managing General Partner and reviewed by an Independent Expert.

Also, if any event reduces the Partnership's Proved Reserves by 10% or more,
excluding a reduction of reserves as a result of normal production, sales of
reserves, or natural gas or oil price changes, then a computation and estimate
of the amount of the reduction in reserves must be sent to each Participant
within 90 days after the Managing General Partner determines that such a
reduction in reserves has occurred.

4.03(b)(4). COST OF REPORTS. The cost of all reports described in this Section
4.03(b) shall be paid by the Partnership as Direct Costs.

4.03(b)(5). PARTICIPANT ACCESS TO RECORDS. The Participants and/or their
representatives shall be permitted access to all Partnership records, provided
that access to the list of Participants shall be subject to Section 4.03(b)(7)
below. Subject to the foregoing, a Participant may inspect and copy any of the
Partnership's records after giving adequate notice to the Managing General
Partner at any reasonable time.

Notwithstanding the foregoing, the Managing General Partner may keep logs, well
reports, and other drilling and operating data confidential for reasonable
periods of time. The Managing General Partner may release information concerning
the operations of the Partnership to the sources that are customary in the
industry or required by rule, regulation, or order of any regulatory body.

4.03(b)(6). REQUIRED LENGTH OF TIME TO HOLD RECORDS. The Managing General
Partner must maintain and preserve during the term of the Partnership and for
six years thereafter all accounts, books and other relevant documents which
include:

     (i)  a record that a Participant meets the suitability standards
          established in connection with an investment in the Partnership; and

     (ii) any appraisal of the fair market value of the Leases as set forth in
          Section 4.01(a)(4), along with associated supporting information, or
          fair market value of any producing property as set forth in Section
          4.03(d)(3).

4.03(b)(7). PARTICIPANT LISTS. The following provisions apply regarding access
to the list of Participants:

     (i)   an alphabetical list of the names, addresses, and business telephone
           numbers of the Participants along with the number of Units held by
           each of them (the "Participant List") must be maintained as a part of
           the Partnership's books and records and be available for inspection
           by any Participant or his designated agent at the home office of the
           Partnership on the Participant's request;

     (ii)  the Participant List must be updated at least quarterly to reflect
           changes in the information contained in the Participant List;

     (iii) a copy of the Participant List must be mailed to any Participant
           requesting the Participant List within 10 days of the written
           request, printed in alphabetical order on white paper, and in a
           readily readable type size in no event smaller than 10-point type and
           a reasonable charge for copy work will be charged by the Partnership;

     (iv)  the purposes for which a Participant may request a copy of the
           Participant List include, without limitation, matters relating to
           Participant's voting rights under this Agreement and the exercise of
           Participant's rights under the federal proxy laws; and

     (v)   if the Managing General Partner neglects or refuses to exhibit,
           produce, or mail a copy of the Participant List as requested, the
           Managing General Partner shall be liable to any Participant
           requesting the list for the

                                       23
costs, including attorneys fees, incurred by that Participant for
          compelling the production of the Participant List, and for actual
          damages suffered by any Participant by reason of the refusal or
          neglect. It shall be a defense that the actual purpose and reason for
          the request for inspection or for a copy of the Participant List is to
          secure the list of Participants or other information for the purpose
          of selling the list or information or copies of the list, or of using
          the same for a commercial purpose other than in the interest of the
          applicant as a Participant relative to the affairs of the Partnership.
          The Managing General Partner will require the Participant requesting
          the Participant List to represent in writing that the list was not
          requested for a commercial purpose unrelated to the Participant's
          interest in the Partnership. The remedies provided under this
          subsection to Participants requesting copies of the Participant List
          are in addition to, and shall not in any way limit, other remedies
          available to Participants under federal law or the laws of any state.

4.03(b)(8). STATE FILINGS. Concurrently with their transmittal to Participants,
and as required, the Managing General Partner shall file a copy of each report
provided for in this Section 4.03(b) with:

     (i)   the California Commissioner of Corporations;

     (ii)  the Arizona Corporation Commission;

     (iii) the Alabama Securities Commission; and

     (iv)  the securities commissions of other states which request the report.

4.03(c). MEETINGS OF PARTICIPANTS.

4.03(c)(1). PROCEDURE FOR A PARTICIPANT MEETING.

4.03(c)(1)(a). MEETINGS MAY BE CALLED BY MANAGING GENERAL PARTNER OR
PARTICIPANTS. Meetings of the Participants may be called as follows:

     (i)   by the Managing General Partner; or

     (ii)  by Participants whose Units equal 10% or more of the total Units for
           any matters on which Participants may vote.

The call for a meeting by the Participants as described above shall be deemed to
have been made on receipt by the Managing General Partner of a written request
from holders of the requisite percentage of Units stating the purpose(s) of the
meeting.

4.03(c)(1)(b). NOTICE REQUIREMENT. The Managing General Partner shall deposit in
the United States mail within 15 days after the receipt of the request, written
notice to all Participants of the meeting and the purpose of the meeting. The
meeting shall be held on a date not less than 30 days nor more than 60 days
after the date of the mailing of the notice, at a reasonable time and place.

Notwithstanding the foregoing, the date for notice of the meeting may be
extended for a period of up to 60 days if, in the opinion of the Managing
General Partner, the additional time is necessary to permit preparation of proxy
or information statements or other documents required to be delivered in
connection with the meeting by the SEC or other regulatory authorities.

4.03(c)(1)(c). MAY VOTE BY PROXY. Participants shall have the right to vote at
any Participant meeting either:

     (i)  in person; or

     (ii) by proxy.

4.03(c)(2). SPECIAL VOTING RIGHTS. At the request of Participants whose Units
equal 10% or more of the total Units, the Managing General Partner shall call
for a vote by Participants. Each Unit is entitled to one vote on all matters,
and each

                                       24
fractional Unit is entitled to that fraction of one vote equal to the fractional
interest in the Unit. Participants whose Units equal a majority of the total
Units may, without the concurrence of the Managing General Partner or its
Affiliates, vote to:

     (i)   dissolve the Partnership;

     (ii)  remove the Managing General Partner and elect a new Managing General
           Partner;

     (iii) elect a new Managing General Partner if the Managing General Partner
           elects to withdraw from the Partnership;

     (iv)  remove the Operator and elect a new Operator;

     (v)   approve or disapprove the sale of all or substantially all of the
           assets of the Partnership;

     (vi)  cancel any contract for services with the Managing General Partner,
           the Operator, or their Affiliates without penalty on 60 days notice;
           and

     (vii) amend this Agreement; provided however:

           (a)  any amendment may not increase the duties or liabilities of any
                Participant or the Managing General Partner or increase or
                decrease the profit or loss sharing or required Capital
                Contribution of any Participant or the Managing General Partner
                without the approval of the Participant or the Managing General
                Partner, respectively; and

           (b)  any amendment may not affect the classification of Partnership
                income and loss for federal income tax purposes without the
                unanimous approval of all Participants.

4.03(c)(3). RESTRICTIONS ON MANAGING GENERAL PARTNER'S VOTING RIGHTS. With
respect to Units owned by the Managing General Partner or its Affiliates, the
Managing General Partner and its Affiliates may vote or consent on all matters
other than the following:

     (i)  the matters set forth in Section 4.03(c)(2)(ii) and (iv) above; or

     (ii) any transaction between the Partnership and the Managing General
          Partner or its Affiliates.

In determining the requisite percentage in interest of Units necessary to
approve any Partnership matter on which the Managing General Partner and its
Affiliates may not vote or consent, any Units owned by the Managing General
Partner and its Affiliates shall not be included.

4.03(c)(4). RESTRICTIONS ON LIMITED PARTNER VOTING RIGHTS. The exercise by the
Limited Partners of the rights granted Participants under Section 4.03(c),
except for the special voting rights granted Participants under Section
4.03(c)(2), shall be subject to the prior legal determination that the grant or
exercise of the powers will not adversely affect the limited liability of
Limited Partners. Notwithstanding the foregoing, if in the opinion of counsel to
the Partnership the legal determination is not necessary under Delaware law to
maintain the limited liability of the Limited Partners, then it shall not be
required. A legal determination under this paragraph may be made either pursuant
to:

     (i)  an opinion of counsel, the counsel being independent of the
          Partnership and selected on the vote of Limited Partners whose Units
          equal a majority of the total Units held by Limited Partners; or

     (ii) a declaratory judgment issued by a court of competent jurisdiction.

The Investor General Partners may exercise the rights granted to the
Participants whether or not the Limited Partners can participate in the vote if
the Investor General Partners represent the requisite percentage of Units
necessary to take the action.

                                       25
4.03(d). TRANSACTIONS WITH THE MANAGING GENERAL PARTNER.

4.03(d)(1). TRANSFER OF EQUAL PROPORTIONATE INTEREST. When the Managing General
Partner or an Affiliate (excluding another Program in which the interest of the
Managing General Partner or its Affiliates is substantially similar to or less
than their interest in the Partnership) sells, transfers or conveys any natural
gas, oil or other mineral interests or property to the Partnership, it must, at
the same time, sell, transfer or convey to the Partnership an equal
proportionate interest in all its other property in the same Prospect.
Notwithstanding, a Prospect shall be deemed to consist of the drilling or
spacing unit on which the well will be drilled by the Partnership, which is the
minimum area permitted by state law or local practice on which one well may be
drilled, if the following two conditions are met:

     (i)  the geological feature to which the well will be drilled contains
          Proved Reserves; and

     (ii) the drilling or spacing unit protects against drainage.

With respect to a Prospect located in Ohio, Pennsylvania and New York on which a
well will be drilled by the Partnership to test the Clinton/Medina geological
formation or the Mississippian and/or Upper Devonian Sandstone reservoirs, and
with respect to a Prospect located in Anderson, Campbell, Morgan, Roane and
Scott Counties, Tennessee on which a well will be drilled to test the
Mississippian carbonate or Devonian Shale reservoirs, a Prospect shall be deemed
to consist of the drilling and spacing unit if it meets the test in the
preceding sentence. Additionally, for a period of five years after the drilling
of the Partnership Well neither the Managing General Partner nor its Affiliates
may drill any well:

     (i)  to the Clinton/Medina geological formation, if the well would be
          within 1,650 feet of an existing Partnership Well in Pennsylvania or
          within 1,000 feet of an existing Partnership Well in Ohio; or

     (ii) to the Mississippian and/or Upper Devonian Sandstone reservoirs in
          Fayette, Greene and Westmoreland Counties, Pennsylvania, if the will
          would be within 1,000 feet from a producing Partnership Well, although
          the Partnership may drill a new well or re-enter an existing well
          which is closer than 1,000 feet to a plugged and abandoned well.

If the Partnership abandons its interest in a well, then the restrictions
described above shall continue for one year following the abandonment.

If the area constituting the Partnership's Prospect is subsequently enlarged to
encompass any area in which the Managing General Partner or an Affiliate
(excluding another Program in which the interest of the Managing General Partner
or its Affiliates is substantially similar to or less than their interest in the
Partnership) owns a separate property interest and the activities of the
Partnership were material in establishing the existence of Proved Undeveloped
Reserves that are attributable to the separate property interest, then the
separate property interest or a portion thereof must be sold, transferred, or
conveyed to the Partnership as set forth in this section and Sections 4.01(a)(4)
and 4.03(d)(2).

Notwithstanding the foregoing, Prospects drilled to the Clinton/Medina
geological formation, the Mississippian and/or Upper Devonian Sandstone
reservoirs, the Mississippian carbonate or Devonian Shale reservoirs, or any
other formation or reservoir shall not be enlarged or contracted if the Prospect
was limited to the drilling or spacing unit because the well was being drilled
to Proved Reserves in the geological formation and the drilling or spacing unit
protected against drainage.

4.03(d)(2). TRANSFER OF LESS THAN THE MANAGING GENERAL PARTNER'S AND ITS
AFFILIATES' ENTIRE INTEREST. A sale, transfer or a conveyance to the Partnership
of less than all of the ownership of the Managing General Partner or an
Affiliate (excluding another Program in which the interest of the Managing
General Partner or its Affiliates is substantially similar to or less than their
interest in the Partnership) in any Prospect shall not be made unless:

     (i)   the interest retained by the Managing General Partner or the
           Affiliate is a proportionate Working Interest;

     (ii)  the respective obligations of the Managing General Partner or its
           Affiliates and the Partnership are substantially the same after the
           sale of the interest by the Managing General Partner or its
           Affiliates; and

                                       26
(iii) the Managing General Partner's interest in revenues does not exceed
           the amount proportionate to its retained Working Interest.

This section does not prevent the Managing General Partner or its Affiliates
from subsequently dealing with their retained interest as they may choose with
unaffiliated parties or Affiliated partnerships.

4.03(d)(3). LIMITATIONS ON SALE OF UNDEVELOPED AND DEVELOPED LEASES TO THE
MANAGING GENERAL PARTNER. Other than another Program managed by the Managing
General Partner and its Affiliates as set forth in Sections 4.03(d)(5) and
4.03(d)(9), the Managing General Partner and its Affiliates shall not receive a
Farmout or purchase any undeveloped Leases from the Partnership other than at
the higher of Cost or fair market value.

The Managing General Partner and its Affiliates, other than an Affiliated Income
Program, shall not purchase any producing natural gas or oil property from the
Partnership unless:

     (i)   the sale is in connection with the liquidation of the Partnership; or

     (ii)  the Managing General Partner's well supervision fees under the
           Drilling and Operating Agreement for the well have exceeded the net
           revenues of the well, determined without regard to the Managing
           General Partner's well supervision fees for the well, for a period of
           at least three consecutive months.

Under both (i) and (ii) above, the sale must be at fair market value supported
by an appraisal of an Independent Expert selected by the Managing General
Partner.

4.03(d)(4). LIMITATIONS ON ACTIVITIES OF THE MANAGING GENERAL PARTNER AND ITS
AFFILIATES ON LEASES ACQUIRED BY THE PARTNERSHIP. During a period of five years
after the Offering Termination Date of the Partnership, if the Managing General
Partner or any of its Affiliates (excluding another Program in which the
interest of the Managing General Partner or its Affiliates is substantially
similar to or less than their interest in the Partnership) proposes to acquire
an interest from an unaffiliated person in a Prospect in which the Partnership
possesses an interest or in a Prospect in which the Partnership's interest has
been terminated without compensation within one year preceding the proposed
acquisition, then the following conditions shall apply:

     (i)  if the Managing General Partner or the Affiliate (excluding another
          Program in which the interest of the Managing General Partner or its
          Affiliates is substantially similar to or less than their interest in
          the Partnership) does not currently own property in the Prospect
          separately from the Partnership, then neither the Managing General
          Partner nor the Affiliate shall be permitted to purchase an interest
          in the Prospect; and

     (ii) if the Managing General Partner or the Affiliate (excluding another
          Program in which the interest of the Managing General Partner or its
          Affiliates is substantially similar to or less than their interest in
          the Partnership) currently owns a proportionate interest in the
          Prospect separately from the Partnership, then the interest to be
          acquired shall be divided between the Partnership and the Managing
          General Partner or the Affiliate in the same proportion as is the
          other property in the Prospect. Provided, however, if cash or
          financing is not available to the Partnership to enable it to complete
          a purchase of the additional interest to which it is entitled, then
          neither the Managing General Partner nor the Affiliate shall be
          permitted to purchase any additional interest in the Prospect.

4.03(d)(5). TRANSFER OF LEASES BETWEEN AFFILIATED LIMITED PARTNERSHIPS. The
transfer of an undeveloped Lease from the Partnership to another drilling
Program sponsored or managed by the Managing General Partner or its Affiliates
must be made at fair market value if the undeveloped Lease has been held by the
Partnership for more than two years. Otherwise, if the Managing General Partner
deems it to be in the best interest of the Partnership, the transfer may be made
at Cost.

An Affiliated Income Program may purchase a producing natural gas and oil
property from the Partnership at any time at:

                                       27
(i)   fair market value as supported by an appraisal from an Independent
           Expert if the property has been held by the Partnership for more than
           six months or the Partnership has made significant expenditures have
           been made in connection with the property; or

     (ii)  Cost, as adjusted for intervening operations, if the Managing General
           Partner deems it to be in the best interest of the Partnership.

However, these prohibitions shall not apply to joint ventures or Farmouts among
Affiliated partnerships, provided that:

     (i)   the respective obligations and revenue sharing of all parties to the
           transaction are substantially the same; and

     (ii)  the compensation arrangement or any other interest or right of either
           the Managing General Partner or its Affiliates is the same in each
           Affiliated partnership or if different, the aggregate compensation of
           the Managing General Partner or the Affiliate is reduced to reflect
           the lower compensation arrangement.

4.03(d)(6). SALE OF ALL ASSETS. The sale of all or substantially all of the
assets of the Partnership, including without limitation, Leases, wells,
equipment and production therefrom, shall be made only with the consent of
Participants whose Units equal a majority of the total Units.

4.03(d)(7). SERVICES.

4.03(d)(7)(a). COMPETITIVE RATES. The Managing General Partner and any Affiliate
shall not render to the Partnership any oil field, equipage, or other services
nor sell or lease to the Partnership any equipment or related supplies unless:

     (i)   the person is engaged, independently of the Partnership and as an
           ordinary and ongoing business, in the business of rendering the
           services or selling or leasing the equipment and supplies to a
           substantial extent to other persons in the natural gas and oil
           industry in addition to the partnerships in which the Managing
           General Partner or an Affiliate has an interest; and

     (ii)  the compensation, price, or rental therefor is competitive with the
           compensation, price, or rental of other persons in the area engaged
           in the business of rendering comparable services or selling or
           leasing comparable equipment and supplies which could reasonably be
           made available to the Partnership.

If the person is not engaged in such a business, then the compensation, price or
rental shall be the Cost of the services, equipment or supplies to the person or
the competitive rate which could be obtained in the area, whichever is less.

4.03(d)(7)(b). IF NOT DISCLOSED IN THE PROSPECTUS OR THIS AGREEMENT, THEN
SERVICES BY THE MANAGING GENERAL PARTNER MUST BE DESCRIBED IN A SEPARATE
CONTRACT AND CANCELABLE. Any services for which the Managing General Partner or
an Affiliate is to receive compensation, other than those described in this
Agreement or the Prospectus, shall be set forth in a written contract which
precisely describes the services to be rendered and all compensation to be paid.
These contracts shall be cancelable without penalty on 60 days written notice by
Participants whose Units equal a majority of the total Units.

4.03(d)(8). LOANS.

4.03(d)(8)(a). NO LOANS FROM THE PARTNERSHIP. No loans or advances shall be made
by the Partnership to the Managing General Partner or its Affiliates.

4.03(d)(8)(b). LOANS TO THE PARTNERSHIP. Neither the Managing General Partner
nor any Affiliate shall loan money to the Partnership if the interest to be
charged exceeds either:

     (i)   the Managing General Partner's or the Affiliate's interest cost; or

     (ii)  that which would be charged to the Partnership, without reference to
           the Managing General Partner's or the Affiliate's financial abilities
           or guarantees, by unrelated lenders, on comparable loans for the same
           purpose.

                                       28
Neither the Managing General Partner nor any Affiliate shall receive points or
other financing charges or fees, regardless of the amount, although the actual
amount of the charges incurred by them from third-party lenders may be
reimbursed to the Managing General Partner or the Affiliate.

4.03(d)(9). FARMOUTS. The Managing General Partner shall not enter into a
Farmout to avoid its paying its share of costs related to drilling a well on an
undeveloped Lease. The Partnership shall not Farmout an undeveloped Lease or
well activity to the Managing General Partner or its Affiliates except as set
forth in Section 4.03(d)(3). Notwithstanding, this restriction shall not apply
to Farmouts between the Partnership and another partnership managed by the
Managing General Partner or its Affiliates, either separately or jointly,
provided that the respective obligations and revenue sharing of all parties to
the transactions are substantially the same and the compensation arrangement or
any other interest or right of the Managing General Partner or its Affiliates is
the same in each partnership, or, if different, the aggregate compensation of
the Managing General Partner and its Affiliates is reduced to reflect the lower
compensation agreement.

The Partnership may Farmout an undeveloped lease or well activity only if the
Managing General Partner, exercising the standard of a prudent operator,
determines that:

     (i)   the Partnership lacks the funds to complete the oil and gas
           operations on the Lease or well and cannot obtain suitable financing;

     (ii)  drilling on the Lease or the intended well activity would concentrate
           excessive funds in one location, creating undue risks to the
           Partnership;

     (iii) the Leases or well activity have been downgraded by events occurring
           after assignment to the Partnership so that development of the Leases
           or well activity would not be desirable; or

     (iv)  the best interests of the Partnership would be served.

If the Partnership Farmouts a Lease or well activity, the Managing General
Partner must retain on behalf of the Partnership the economic interests and
concessions as a reasonably prudent oil and gas operator would or could retain
under the circumstances prevailing at the time, consistent with industry
practices.

4.03(d)(10). NO COMPENSATING BALANCES. Neither the Managing General Partner nor
any Affiliate shall use the Partnership's funds as compensating balances for its
own benefit.

4.03(d)(11). FUTURE PRODUCTION. Neither the Managing General Partner nor any
Affiliate shall commit the future production of a well developed by the
Partnership exclusively for its own benefit.

4.03(d)(12). MARKETING ARRANGEMENTS. Subject to Section 4.06(c), all benefits
from marketing arrangements or other relationships affecting the property of the
Managing General Partner or its Affiliates and the Partnership shall be fairly
and equitably apportioned according to the respective interests of each in the
property. The Managing General Partner shall treat all wells in a geographic
area equally concerning to whom and at what price the Partnership's natural gas
and oil will be sold and to whom and at what price the natural gas and oil of
other natural gas and oil Programs which the Managing General Partner has
sponsored or will sponsor will be sold. For example, each seller of natural gas
and oil in a given area will be paid a weighted average selling price for all
natural gas and oil sold in that geographic area. The Managing General Partner,
in its sole discretion, shall determine what constitutes a geographic area.

4.03(d)(13). ADVANCE PAYMENTS. Advance payments by the Partnership to the
Managing General Partner and its Affiliates are prohibited except when advance
payments are required to secure the tax benefits of prepaid Intangible Drilling
Costs for a business purpose as set forth in the Drilling and Operating
Agreement.

4.03(d)(14). NO REBATES. No rebates or give-ups may be received by the Managing
General Partner or any Affiliate nor may the Managing General Partner or any
Affiliate participate in any reciprocal business arrangements that would
circumvent the provisions of this section.

                                       29
4.03(d)(15). PARTICIPATION IN OTHER PARTNERSHIPS. If the Partnership
participates in other partnerships or joint ventures (multi-tier arrangements),
then the terms of any of these arrangements shall not result in the
circumvention of any of the requirements or prohibitions contained in this
Agreement, including the following:

     (i)   there shall be no duplication or increase in Organization and
           Offering Costs, the Managing General Partner's compensation,
           Partnership expenses or other fees and costs;

     (ii)  there shall be no substantive alteration in the fiduciary and
           contractual relationship between the Managing General Partner and the
           Participants; and

     (iii) there shall be no diminishment in the voting rights of the
           Participants.

4.03(d)(16). ROLL-UP LIMITATIONS.

4.03(d)(16)(a). REQUIREMENT FOR APPRAISAL AND ITS ASSUMPTIONS. In connection
with a proposed Roll-Up, an appraisal of all Partnership assets shall be
obtained from a competent Independent Expert. If the appraisal will be included
in a prospectus used to offer securities of a Roll-Up Entity, then the appraisal
shall be filed with the SEC and the Administrator as an exhibit to the
registration statement for the offering. Thus, an issuer using the appraisal
shall be subject to liability for violation of Section 11 of the Securities Act
of 1933 and comparable provisions under state law for any material
misrepresentations or material omissions in the appraisal.

Partnership assets shall be appraised on a consistent basis. The appraisal shall
be based on all relevant information, including current reserve estimates
prepared as set forth in Section 4.03(b)(3), and shall indicate the value of the
Partnership's assets as of a date immediately before the announcement of the
proposed Roll-Up transaction. The appraisal shall assume an orderly liquidation
of the Partnership's assets over a 12-month period.

The terms of the engagement of the Independent Expert shall clearly state that
the engagement is for the benefit of the Partnership and the Participants. A
summary of the independent appraisal, indicating all material assumptions
underlying the appraisal, shall be included in a report to the Participants in
connection with a proposed Roll-Up.

4.03(d)(16)(b). RIGHTS OF PARTICIPANTS WHO VOTE AGAINST PROPOSAL. In connection
with a proposed Roll-Up, Participants who vote "no" on the proposal shall be
offered the choice of:

     (i)  accepting the securities of the Roll-Up Entity offered in the proposed
          Roll-Up; or

     (ii) one of the following:

          (a)  remaining as Participants in the Partnership and preserving their
               Units in the Partnership on the same terms and conditions as
               existed previously; or

          (b)  receiving cash in an amount equal to the Participants' pro rata
               share of the appraised value of the net assets of the Partnership
               based on their respective number of Units.

4.03(d)(16)(c). NO ROLL-UP IF DIMINISHMENT OF VOTING RIGHTS. The Partnership
shall not participate in any proposed Roll-Up which, if approved, would result
in the diminishment of any Participant's voting rights under the Roll-Up
Entity's chartering agreement. In no event shall the democracy rights of
Participants in the Roll-Up Entity be less than those provided for under
Sections 4.03(c)(1) and 4.03(c)(2). If the Roll-Up Entity is a corporation, then
the democracy rights of Participants shall correspond to the democracy rights
provided for in this Agreement to the greatest extent possible.

4.03(d)(16)(d). NO ROLL-UP IF ACCUMULATION OF SHARES WOULD BE IMPEDED. The
Partnership shall not participate in any proposed Roll-Up transaction which
includes provisions that would operate to materially impede or frustrate the
accumulation of shares by any purchaser of the securities of the Roll-Up Entity,
except to the minimum extent necessary to preserve the tax status of the Roll-Up
Entity. The Partnership shall not participate in any proposed Roll-Up
transaction which would limit the ability of a Participant to exercise the
voting rights of its securities of the Roll-Up Entity on the basis of the number
of Units held by that Participant.

                                       30
4.03(d)(16)(e). NO ROLL-UP IF ACCESS TO RECORDS WOULD BE LIMITED. The
Partnership shall not participate in a Roll-Up in which Participants' rights of
access to the records of the Roll-Up Entity would be less than those provided
for under Sections 4.03(b)(5), 4.03(b)(6) and 4.03(b)(7).

4.03(d)(16)(f). COST OF ROLL-UP. The Partnership shall not participate in any
proposed Roll-Up transaction in which any of the costs of the transaction would
be borne by the Partnership if Participants whose Units equal 66% of the total
Units do not vote to approve the proposed Roll-Up.

4.03(d)(16)(g). ROLL-UP APPROVAL. The Partnership shall not participate in a
Roll-Up transaction unless the Roll-Up transaction is approved by Participants
whose Units equal 66% of the total Units.

4.03(d)(17). DISCLOSURE OF BINDING AGREEMENTS. Any agreement or arrangement
which binds the Partnership must be disclosed in the Prospectus.

4.03(d)(18). TRANSACTIONS MUST BE FAIR AND REASONABLE. Neither the Managing
General Partner nor any Affiliate shall sell, transfer, or convey any property
to or purchase any property from the Partnership, directly or indirectly, except
under transactions that are fair and reasonable, nor take any action with
respect to the assets or property of the Partnership which does not primarily
benefit the Partnership.

4.04. DESIGNATION, COMPENSATION AND REMOVAL OF MANAGING GENERAL PARTNER AND
REMOVAL OF OPERATOR.

4.04(a). MANAGING GENERAL PARTNER.

4.04(a)(1). TERM OF SERVICE. Except as otherwise provided in this Agreement,
Atlas shall serve as the Managing General Partner of the Partnership until
either it:

     (i)  is removed pursuant to Section 4.04(a)(3); or

     (ii) withdraws pursuant to Section 4.04(a)(3)(f).

4.04(a)(2). COMPENSATION OF MANAGING GENERAL PARTNER. In addition to the
compensation set forth in Sections 4.01(a)(4) and 4.02(d)(1), the Managing
General Partner shall receive the compensation set forth in Sections
4.04(a)(2)(b) through 4.04(a)(2)(g).

4.04(a)(2)(a). CHARGES MUST BE NECESSARY AND REASONABLE. Charges by the Managing
General Partner for goods and services must be fully supportable as to:

     (i)  the necessity of the goods and services; and

     (ii) the reasonableness of the amount charged.

All actual and necessary expenses incurred by the Partnership may be paid out of
the Partnership's subscription proceeds and revenues.

4.04(a)(2)(b). DIRECT COSTS. The Managing General Partner and its Affiliates
shall be reimbursed for all Direct Costs. Direct Costs, however, shall be billed
directly to and paid by the Partnership to the extent practicable.

4.04(a)(2)(c). ADMINISTRATIVE COSTS. The Managing General Partner shall receive
a nonaccountable, fixed payment reimbursement for its Administrative Costs of
$75 per well per month. The nonaccountable, fixed payment reimbursement of $75
per well per month shall be subject to the following:

     (i)   it shall not be increased in amount during the term of the
           Partnership;

     (ii)  it shall be proportionately reduced to the extent the Partnership
           acquires less than 100% of the Working Interest in the well;

                                       31
(iii) it shall be the entire payment to reimburse the Managing General
           Partner for the Partnership's Administrative Costs; and

     (iv)  it shall not be received for plugged or abandoned wells.

4.04(a)(2)(d). GAS GATHERING. The Managing General Partner, not acting as a
Partner, shall be responsible for gathering and transporting the natural gas
produced by the Partnership to interstate pipeline systems, local distribution
companies, and/or end-users in the area (the "gathering services"). In providing
the gathering services, the Managing General Partner may use the gathering
system owned by Atlas Pipeline Partners, as described in the Prospectus, and
gathering systems owned by independent third-parties and/or Affiliates of Atlas
America other than Atlas Pipeline Partners.

The Partnership shall pay a gathering fee directly to the Managing General
Partner at competitive rates for the gathering services. The gathering fee paid
by the Partnership to the Managing General Partner may be increased from
time-to-time by the Managing General Partner, in its sole discretion, but may
not increase beyond competitive rates as determined by the Managing General
Partner. Currently, the Managing General Partner has determined that the
competitive rate is an amount equal to 10% of the gross sales price received by
the Partnership for its natural gas in each of its primary or secondary areas as
described in the Prospectus. Gross sales price means the price that is actually
received, adjusted to take into account proceeds received or payments made
pursuant to hedging arrangements. The payment of a competitive fee to the
Managing General Partner for its gathering services shall be subject to the
following conditions:

     (i)   If the Partnership's natural gas production is gathered and
           transported through the gathering system owned by Atlas Pipeline
           Partners, then the Managing General Partner shall apply its gathering
           fee towards the related gathering fee obligation of Atlas America,
           Inc., Resource Energy, LLC, and Viking Resources LLC (the "Atlas
           Entities") under their agreement with Atlas Pipeline Partners as
           described in the Prospectus.

     (ii)  If a third-party gathering system is used by the Partnership, then
           the Managing General Partner shall pay a portion or all of the
           gathering fee it receives from the Partnership to the third-party
           gathering the natural gas. The Managing General Partner may retain
           the excess of any gathering fees it receives from the Partnership
           over the payments it makes to third-party gas gatherers. If the
           third-party's gathering system charges more than an amount equal to
           10% of the gross sales price, then the Managing General Partner's
           gathering fee charged to the Partnership shall be the actual
           transportation and compression fees charged by the third-party
           gathering system with respect to the Partnership's natural gas in the
           area.

     (iii) If both a third-party gathering system and the Atlas Pipeline
           Partners gathering system (or a gas gathering system owned by an
           affiliate of Atlas America other than Atlas Pipeline Partners) are
           used by the Partnership, then the Managing General Partner shall
           receive an amount equal to 10% of the gross sales price plus the
           amount charged by the third-party gathering system. For purposes of
           illustration, but not limitation, the Partnership will deliver
           natural gas produced from certain wells drilled by the Partnership in
           the Upper Devonian Sandstone Reservoirs in the McKean County,
           Pennsylvania area into a gathering system, a segment of which will be
           provided by Atlas Pipeline Partners and a segment of which will be
           provided by a third-party. The Managing General Partner will receive
           a gathering fee composed of $.35 per mcf for transportation and
           compression, which may be increased from time-to-time, that the
           Managing General Partner will pay to the third-party gathering the
           natural gas, and a gathering fee equal to 10% of the gross sales
           price of the natural gas.

With respect to the Knox project and natural gas produced from the Mississippian
and Devonian Shale Reservoirs in Anderson, Campbell, Morgan, Roane and Scott
Counties, Tennessee as described in the Prospectus, if the Coalfield Pipeline
does not have sufficient capacity to compress and transport the natural gas
produced from the Partnership's wells as determined by Atlas America, then Atlas
America or an Affiliate other than Atlas Pipeline Partners may construct an
additional gathering system and/or enhancements to the Coalfield Pipeline. On
completion of the construction, Atlas America will transfer its ownership in the
additional gathering system and/or enhancements to the owners of Coalfield
Pipeline, which will then pay Atlas America an amount equal to $.12 per mcf of
natural gas transported through the newly constructed and/or enhanced gathering
system. Coalfield Pipeline will pay this amount of $.12 per mcf to Atlas America
from its gathering and compression fees charged to the Partnership.

                                       32
4.04(a)(2)(e). DEALER-MANAGER FEE. Subject to Section 3.03(a)(1), the
Dealer-Manager shall receive on each Unit sold to investors:

     (i)   a 2.5% Dealer-Manager fee;

     (ii)  a 7% Sales Commission; and

     (iii) an up to .5% reimbursement of the Selling Agents' bona fide due
           diligence expenses.

4.04(a)(2)(f). DRILLING AND OPERATING AGREEMENT. The Managing General Partner
and its Affiliates shall receive compensation as set forth in the Drilling and
Operating Agreement.

4.04(a)(2)(g). OTHER TRANSACTIONS. The Managing General Partner and its
Affiliates may enter into transactions pursuant to Section 4.03(d)(7) with the
Partnership and shall be entitled to compensation under that section.

4.04(a)(3). REMOVAL OF MANAGING GENERAL PARTNER.

4.04(a)(3)(a). MAJORITY VOTE REQUIRED TO REMOVE THE MANAGING GENERAL PARTNER.
The Managing General Partner may be removed at any time on 60 days' advance
written notice to the outgoing Managing General Partner by the affirmative vote
of Participants whose Units equal a majority of the total Units.

If the Participants vote to remove the Managing General Partner from the
Partnership, then Participants must elect by an affirmative vote of Participants
whose Units equal a majority of the total Units either to:

     (i)  dissolve, wind-up, and terminate the Partnership; or

     (ii) continue as a successor limited partnership under all the terms of
          this Partnership Agreement as provided in Section 7.01(c).

If the Participants elect to continue as a successor limited partnership, then
the Managing General Partner shall not be removed until a substituted Managing
General Partner has been selected by an affirmative vote of Participants whose
Units equal a majority of the total Units and installed as such.

4.04(a)(3)(b). VALUATION OF MANAGING GENERAL PARTNER'S INTEREST IN THE
PARTNERSHIP. If the Managing General Partner is removed, then its interest in
the Partnership shall be determined by appraisal by a qualified Independent
Expert. The Independent Expert shall be selected by mutual agreement between the
removed Managing General Partner and the incoming Managing General Partner. The
appraisal shall take into account an appropriate discount, to reflect the risk
of recovering natural gas and oil reserves, which shall not be less than that
used to calculate the presentment price in the most recent presentment offer
under Section 6.03, if any.

The cost of the appraisal shall be borne equally by the removed Managing General
Partner and the Partnership.

4.04(a)(3)(c). INCOMING MANAGING GENERAL PARTNER'S OPTION TO PURCHASE. The
incoming Managing General Partner shall have the option to purchase 20% of the
removed Managing General Partner's interest in the Partnership as Managing
General Partner, but not as a Participant, for the value determined by the
Independent Expert.

4.04(a)(3)(d). METHOD OF PAYMENT. The method of payment for the removed Managing
General Partner's interest must be fair and protect the solvency and liquidity
of the Partnership. The method of payment shall be as follows:

     (i)  when the termination is voluntary, the method of payment shall be a
          non-interest bearing unsecured promissory note with principal payable,
          if at all, from distributions which the Managing General Partner
          otherwise would have received under this Agreement had the Managing
          General Partner not been terminated; and

                                       33
(ii) when the termination is involuntary, the method of payment shall be an
          interest bearing unsecured promissory note coming due in no less than
          five years with equal installments each year. The interest rate shall
          be that charged on comparable loans.

4.04(a)(3)(e). TERMINATION OF CONTRACTS. At the time of its removal, the removed
Managing General Partner shall cause, to the extent it is legally possible to do
so, its successor to be transferred or assigned all of its rights, obligations
and interests as Managing General Partner of the Partnership in contracts
entered into by it on behalf of the Partnership. In any event, the removed
Managing General Partner shall cause all of its rights, obligations and
interests as Managing General Partner of the Partnership in any such contract to
terminate at the time of its removal.

Notwithstanding any other provision in this Agreement, the Partnership or the
successor Managing General Partner shall not:

     (i)   be a party to any natural gas supply agreement that the Managing
           General Partner or its Affiliates enters into with a third-party;

     (ii)  have any rights pursuant to such natural gas supply agreement; or

     (iii) receive any interest in the Managing General Partner's and its
           Affiliates' pipeline or gathering system or compression facilities.

4.04(a)(3)(f). THE MANAGING GENERAL PARTNER'S RIGHT TO VOLUNTARILY WITHDRAW. At
any time beginning 10 years after the Offering Termination Date and the
Partnership's primary drilling activities, the Managing General Partner may
voluntarily withdraw as Managing General Partner on giving 120 days' written
notice of withdrawal to the Participants. If the Managing General Partner
withdraws, then the following conditions shall apply:

     (i)  the Managing General Partner's interest in the Partnership shall be
          determined as described in Section 4.04(a)(3)(b) above with respect to
          removal; and

     (ii) the interest shall be distributed to the Managing General Partner as
          described in Section 4.04(a)(3)(d)(i) above.

Any successor Managing General Partner shall have the option to purchase 20% of
the withdrawing Managing General Partner's interest in the Partnership at the
value determined as described above with respect to removal.

4.04(a)(3)(g). RIGHT OF MANAGING GENERAL PARTNER TO HYPOTHECATE ITS INTERESTS.
The Managing General Partner shall have the authority without the consent of the
Participants and without affecting the allocation of costs and revenues received
or incurred under this Agreement, to hypothecate, pledge, or otherwise encumber,
on any terms it chooses for its own general purposes, either:

     (i)  its Partnership interest; or

     (ii) an undivided interest in the assets of the Partnership equal to or
          less than its respective interest as Managing General Partner in the
          revenues of the Partnership.

All repayments of these borrowings and costs, interest or other charges related
to the borrowings shall be borne and paid separately by the Managing General
Partner. In no event shall the repayments, costs, interest, or other charges
related to the borrowing be charged to the account of the Participants.

4.04(a)(3)(h). THE MANAGING GENERAL PARTNER'S RIGHT TO WITHDRAW PROPERTY
INTEREST. The Managing General Partner shall have the right to withdraw a
property interest held by the Partnership in the form of a Working Interest in
the Partnership's Wells equal to or less than its respective interest as
Managing General Partner in the revenues of the Partnership if:

     (i)  the withdrawal is necessary to satisfy the bona fide request of its
          creditors; or

     (ii) the withdrawal is approved by Participants whose Units equal a
          majority of the total Units.

                                       34
If the Managing General Partner withdraws a property interest from the
Partnership as described above, then the Managing General Partner shall:

     (i)  pay the expenses of withdrawing; and

     (ii) fully indemnify the Partnership against any additional expenses which
          may result from the withdrawal of its property interest, including
          insuring that a greater amount of Direct Costs or Administrative Costs
          is not allocated to the Participants.

4.04(a)(4). REMOVAL OF OPERATOR. The Operator may be removed and a new Operator
may be substituted at any time on 60 days advance written notice to the outgoing
Operator by the Managing General Partner acting on behalf of the Partnership on
the affirmative vote of Participants whose Units equal a majority of the total
Units.

The Operator shall not be removed until a substituted Operator has been selected
by an affirmative vote of Participants whose Units equal a majority of the total
Units and installed as such.

4.05. INDEMNIFICATION AND EXONERATION.

4.05(a)(1). STANDARDS FOR THE MANAGING GENERAL PARTNER NOT INCURRING LIABILITY
TO THE PARTNERSHIP OR PARTICIPANTS. The Managing General Partner, the Operator,
and their Affiliates shall not have any liability whatsoever to the Partnership,
or to any Participant for any loss suffered by the Partnership or the
Participants which arises out of any action or inaction of the Managing General
Partner, the Operator, or their Affiliates if:

     (i)   the Managing General Partner, the Operator, and their Affiliates
           determined in good faith that the course of conduct was in the best
           interest of the Partnership;

     (ii)  the Managing General Partner, the Operator, and their Affiliates were
           acting on behalf of, or performing services for, the Partnership; and

     (iii) the course of conduct did not constitute negligence or misconduct of
           the Managing General Partner, the Operator, or their Affiliates.

4.05(a)(2). STANDARDS FOR MANAGING GENERAL PARTNER INDEMNIFICATION. The Managing
General Partner, the Operator, and their Affiliates shall be indemnified by the
Partnership against any losses, judgments, liabilities, expenses, and amounts
paid in settlement of any claims sustained by them in connection with the
Partnership, provided that:

     (i)   the Managing General Partner, the Operator, and their Affiliates
           determined in good faith that the course of conduct which caused the
           loss or liability was in the best interest of the Partnership;

     (ii)  the Managing General Partner, the Operator, and their Affiliates were
           acting on behalf of, or performing services for, the Partnership; and

     (iii) the course of conduct was not the result of negligence or misconduct
           of the Managing General Partner, the Operator, or their Affiliates.

Provided, however, payments arising from such indemnification or agreement to
hold harmless are recoverable only out of the following:

     (i)  the Partnership's tangible net assets, which include its revenues; and

     (ii) any insurance proceeds from the types of insurance for which the
          Managing General Partner, the Operator and their Affiliates may be
          indemnified under this Agreement.

4.05(a)(3). STANDARDS FOR SECURITIES LAW INDEMNIFICATION. Notwithstanding
anything to the contrary contained in this section, the Managing General
Partner, the Operator, and their Affiliates and any person acting as a
broker/dealer with respect

                                       35
to the offer or sale of the Units, shall not be indemnified for any losses,
liabilities or expenses arising from or out of an alleged violation of federal
or state securities laws by such party unless:

     (i)   there has been a successful adjudication on the merits of each count
           involving alleged securities law violations as to the particular
           indemnitee;

     (ii)  the claims have been dismissed with prejudice on the merits by a
           court of competent jurisdiction as to the particular indemnitee; or

     (iii) a court of competent jurisdiction approves a settlement of the claims
           against a particular indemnitee and finds that indemnification of the
           settlement and the related costs should be made, and the court
           considering the request for indemnification has been advised of the
           position of the SEC, the Massachusetts Securities Division, and any
           state securities regulatory authority in which plaintiffs claim they
           were offered or sold Units with respect to the issue of
           indemnification for violation of securities laws.

4.05(a)(4). STANDARDS FOR ADVANCEMENT OF FUNDS TO THE MANAGING GENERAL PARTNER
AND INSURANCE. The advancement of Partnership funds to the Managing General
Partner, the Operator, or their Affiliates for legal expenses and other costs
incurred as a result of any legal action for which indemnification is being
sought from the Partnership is permissible only if the Partnership has adequate
funds available and the following conditions are satisfied:

     (i)   the legal action relates to acts or omissions with respect to the
           performance of duties or services on behalf of the Partnership;

     (ii)  the legal action is initiated by a third-party who is not a
           Participant, or the legal action is initiated by a Participant and a
           court of competent jurisdiction specifically approves the
           advancement; and

     (iii) the Managing General Partner or its Affiliates undertake to repay the
           advanced funds to the Partnership, together with the applicable legal
           rate of interest thereon, in cases in which such party is found not
           to be entitled to indemnification.

The Partnership shall not bear the cost of that portion of insurance which
insures the Managing General Partner, the Operator, or their Affiliates for any
liability for which they could not be indemnified pursuant to Sections
4.05(a)(1) and 4.05(a)(2).

4.05(b). LIABILITY OF PARTNERS. Under the Delaware Revised Uniform Limited
Partnership Act, the Investor General Partners are liable jointly and severally
for all liabilities and obligations of the Partnership. Notwithstanding the
foregoing, as among themselves, the Investor General Partners agree that each
shall be solely and individually responsible only for his pro rata share of the
liabilities and obligations of the Partnership based on his respective number of
Units.

In addition, the Managing General Partner agrees to use its corporate assets to
indemnify each of the Investor General Partners against all Partnership related
liabilities which exceed the Investor General Partner's interest in the
undistributed net assets of the Partnership and insurance proceeds, if any.
Further, the Managing General Partner agrees to indemnify each Investor General
Partner against any personal liability as a result of the unauthorized acts of
another Investor General Partner.

If the Managing General Partner provides indemnification, then each Investor
General Partner who has been indemnified shall transfer and subrogate his rights
for contribution from or against any other Investor General Partner to the
Managing General Partner.

4.05(c). ORDER OF PAYMENT OF CLAIMS. Claims shall be paid as follows:

     (i)   first, out of any insurance proceeds;

     (ii)  second, out of Partnership assets and revenues; and

     (iii) last, by the Managing General Partner as provided in Sections
           3.05(b)(2) and (3) and 4.05(b).

                                       36
No Limited Partner shall be required to reimburse the Managing General Partner,
the Operator, their Affiliates, or the Investor General Partners for any
liability in excess of his agreed Capital Contribution, except:

     (i)  for a liability resulting from the Limited Partner's unauthorized
          participation in management of the Partnership; or

     (ii) from some other breach by the Limited Partner of this Agreement.

4.05(d). AUTHORIZED TRANSACTIONS ARE NOT DEEMED TO BE A BREACH. No transaction
entered into or action taken by the Partnership, or by the Managing General
Partner, the Operator, or their Affiliates, which is authorized by this
Agreement shall be deemed a breach of any obligation owed by the Managing
General Partner, the Operator, or their Affiliates to the Partnership or the
Participants.

4.06. OTHER ACTIVITIES.

4.06(a). THE MANAGING GENERAL PARTNER MAY PURSUE OTHER NATURAL GAS AND OIL
ACTIVITIES FOR ITS OWN ACCOUNT. The Managing General Partner, the Operator, and
their Affiliates are now engaged, and will engage in the future, for their own
account and for the account of others, including other investors, in all aspects
of the natural gas and oil business. This includes without limitation, the
evaluation, acquisition, and sale of producing and nonproducing Leases, and the
exploration for and production of natural gas, oil and other minerals.

The Managing General Partner is required to devote only so much of its time to
the Partnership as it determines in its sole discretion, but consistent with its
fiduciary duties, is necessary to manage the affairs of the Partnership. Except
as expressly provided to the contrary in this Agreement, and subject to
fiduciary duties, the Managing General Partner, the Operator, and their
Affiliates may do the following:

     (i)   continue their activities, or initiate further such activities,
           individually, jointly with others, or as a part of any other limited
           or general partnership, tax partnership, joint venture, or other
           entity or activity to which they are or may become a party, in any
           locale and in the same fields, areas of operation or prospects in
           which the Partnership may likewise be active;

     (ii)  reserve partial interests in Leases being assigned to the Partnership
           or any other interests not expressly prohibited by this Agreement;

     (iii) deal with the Partnership as independent parties or through any other
           entity in which they may be interested;

     (iv)  conduct business with the Partnership as set forth in this Agreement;
           and

     (v)   participate in such other investor operations, as investors or
           otherwise.

The Managing General Partner and its Affiliates shall not be required to permit
the Partnership or the Participants to participate in or share in any profits or
other benefits from any of the other operations in which the Managing General
Partner and its Affiliates may be interested as permitted under this section.
However, except as otherwise provided in this Agreement, the Managing General
Partner and its Affiliates may pursue business opportunities that are consistent
with the Partnership's investment objectives for their own account only after
they have determined that the opportunity either:

     (i)  cannot be pursued by the Partnership because of insufficient funds; or

     (ii) it is not appropriate for the Partnership under the existing
          circumstances.

4.06(b). MANAGING GENERAL PARTNER MAY MANAGE MULTIPLE PARTNERSHIPS. The Managing
General Partner or its Affiliates may manage multiple Programs simultaneously.

4.06(c). PARTNERSHIP HAS NO INTEREST IN NATURAL GAS CONTRACTS OR PIPELINES AND
GATHERING SYSTEMS. Notwithstanding any other provision in this Agreement, the
Partnership shall not:

                                       37
(i)  be a party to any natural gas supply agreement that the Managing
          General Partner, the Operator, or their Affiliates enter into with a
          third-party or have any rights pursuant to such natural gas supply
          agreement; or

     (ii) receive any interest in the Managing General Partner's, the
          Operator's, and their Affiliates' pipeline or gathering system or
          compression facilities.

                                    ARTICLE V
                      PARTICIPATION IN COSTS AND REVENUES,
                  CAPITAL ACCOUNTS, ELECTIONS AND DISTRIBUTIONS

5.01. PARTICIPATION IN COSTS AND REVENUES. Except as otherwise provided in this
Agreement, costs and revenues of the Partnership shall be charged and credited
to the Managing General Partner and the Participants as set forth in this
section and its subsections.

5.01(a). COSTS. Costs shall be charged as set forth below.

5.01(a)(1). ORGANIZATION AND OFFERING COSTS. Organization and Offering Costs
shall be charged 100% to the Managing General Partner. For purposes of sharing
in revenues under Section 5.01(b)(4), the Managing General Partner shall be
credited with Organization and Offering Costs paid by it and for services
provided by it as Organization Costs up to an amount equal to 15% of the
Partnership's subscription proceeds. Any Organization and Offering Costs paid
and/or provided in services by the Managing General Partner in excess of this
amount shall not be credited towards the Managing General Partner's required
Capital Contribution or revenue share set forth in Section 5.01(b)(4). The
Managing General Partner's credit for services provided to the Partnership as
Organization Costs shall be determined based on generally accepted accounting
principles.

5.01(a)(2). INTANGIBLE DRILLING COSTS. Ninety percent (90%) of the Partnership's
subscription proceeds received from the Participants shall be used to pay 100%
of the Intangible Drilling Costs.

5.01(a)(3). TANGIBLE COSTS. Ten percent (10%) of the Partnership's subscription
proceeds received from the Participants shall be used by the Partnership to pay
Tangible Costs. All remaining Tangible Costs in excess of an amount equal to 10%
of the Partnership's subscription proceeds shall be charged 100% to the Managing
General Partner.

5.01(a)(4). OPERATING COSTS, DIRECT COSTS, ADMINISTRATIVE COSTS AND ALL OTHER
COSTS. Operating Costs, Direct Costs, Administrative Costs, and all other
Partnership costs not specifically allocated shall be charged to the parties in
the same ratio as the related production revenues are being credited.

5.01(a)(5). ALLOCATION OF INTANGIBLE DRILLING COSTS AND TANGIBLE COSTS AT
PARTNERSHIP CLOSINGS. Intangible Drilling Costs and the Participants' share of
Tangible Costs of a well or wells to be drilled and completed with the proceeds
of a Partnership closing shall be charged 100% to the Participants who are
admitted to the Partnership in that closing and shall not be reallocated to take
into account other Partnership closings.

Although the subscription proceeds received by the Partnership in each closing
may be used to pay the costs of drilling different wells, 90% of each
Participant's subscription proceeds shall be applied to Intangible Drilling
Costs and 10% of each Participant's subscription proceeds shall be applied to
Tangible Costs regardless of when the Participant subscribes for his Units or is
admitted to the Partnership.

5.01(a)(6). LEASE COSTS. The Leases shall be contributed to the Partnership by
the Managing General Partner as set forth in Section 4.01(a)(4).

5.01(b). REVENUES. Revenues shall be credited as set forth below.

5.01(b)(1). ALLOCATION OF REVENUES ON DISPOSITION OF PROPERTY. If the parties'
Capital Accounts are adjusted to reflect the simulated depletion of a natural
gas or oil property of the Partnership, then the portion of the total amount
realized by the Partnership on the taxable disposition of the property that
represents recovery of its simulated tax basis in the property shall be
allocated to the parties in the same proportion as the aggregate adjusted tax
basis of the property was allocated to the

                                       38
parties or their predecessors in interest. If the parties' Capital Accounts are
adjusted to reflect the actual depletion of a natural gas or oil property of the
Partnership, then the portion of the total amount realized by the Partnership on
the taxable disposition of the property that equals the parties' aggregate
remaining adjusted tax basis in the property shall be allocated to the parties
in proportion to their respective remaining adjusted tax bases in the property.
Thereafter, any excess shall be allocated to the Managing General Partner in an
amount equal to the difference between the fair market value of the Lease at the
time it was contributed to the Partnership and its simulated or actual adjusted
tax basis at that time. Finally, any excess shall be credited as provided in
Section 5.01(b)(4), below.

In the event of the Partnership's sale of developed natural gas and oil
properties with equipment on the properties, the Managing General Partner may
make any reasonable allocation of the sales proceeds between the equipment and
the Leases.

5.01(b)(2). INTEREST. Interest earned on each Participant's subscription
proceeds before the Offering Termination Date under Section 3.05(b)(1) shall be
credited to the accounts of the respective subscribers who paid the subscription
proceeds to the Partnership. The interest shall be paid to the Participants not
later than the Partnership's first cash distribution from operations.

After the Offering Termination Date and until proceeds from the offering are
invested in the Partnership's natural gas and oil operations, any interest
income from temporary investments shall be allocated pro rata to the
Participants providing the subscription proceeds.

All other interest income, including interest earned on the deposit of
production revenues, shall be credited as provided in Section 5.01(b)(4), below.

5.01(b)(3). SALE OR DISPOSITION OF EQUIPMENT. Proceeds from the sale or
disposition of equipment shall be credited to the parties charged with the costs
of the equipment in the ratio in which the costs were charged.

5.01(b)(4). OTHER REVENUES. Subject to Section 5.01(b)(4)(a), the Managing
General Partner and the Participants shall share in all other Partnership
revenues in the same percentage as their respective Capital Contribution bears
to the Partnership's total Capital Contributions, except that the Managing
General Partner shall receive an additional 7% of Partnership revenues. However,
the Managing General Partner's total revenue share shall not exceed 40% of
Partnership revenues. For example, if the Managing General Partner contributes
25% of the Partnership's total Capital Contributions and the Participants
contribute 75% of the Partnership's total Capital Contributions, then the
Managing General Partner would receive 32% of the Partnership revenues and the
Participants would receive 68% of the Partnership revenues. On the other hand,
if the Managing General Partner contributes 35% of the Partnership's total
Capital Contributions and the Participants contribute 65% of the Partnership's
total Capital Contributions, then the Managing General Partner would receive 40%
of the Partnership revenues, not 42%, because its revenue share cannot exceed
40% of Partnership revenues, and the Participants would receive 60% of
Partnership revenues.

5.01(b)(4)(a). SUBORDINATION. The Managing General Partner shall subordinate up
to 50% of its share of Partnership Net Production Revenues to the receipt by
Participants of cash distributions from the Partnership equal to $1,000 per Unit
(which is 10% of $10,000 per Unit) regardless of the actual subscription price
they paid for their Units, in each of the Partnership's first five 12-month
periods of operations as set forth below. In this regard:

     (i)   the aggregate 60-month subordination period shall begin with the
           first cash distribution from operations to the Participants;

     (ii)  subsequent subordination distributions, if any, shall be determined
           and made at the time of each subsequent distribution of revenues to
           the Participants; and

     (iii) the Managing General Partner shall not subordinate more than 50% of
           its share of Partnership Net Production Revenues in any 12-month
           subordination period.

The Managing General Partner's subordination obligation shall be determined by:

                                       39
(i)  carrying forward to subsequent 12-month subordination periods the
          amount, if any, by which cumulative cash distributions to
          Participants, including any subordination payments, are less than:

          (a)  $1,000 per Unit (10% of $10,000 per Unit) in the first 12-month
               period;

          (b)  $2,000 per Unit (20% of $10,000 per Unit) in the second 12-month
               period;

          (c)  $3,000 per Unit (30% of $10,000 per Unit) in the third 12-month
               period; or

          (d)  $4,000 per Unit (40% of $10,000 per Unit) in the fourth 12-month
               period (no carry forward is required if the Participant's
               cumulative cash distributions are less than $5,000 per Unit (50%
               of $10,000 per Unit) in the fifth 12-month period, because the
               Managing General Partner's subordination obligation terminates on
               the expiration of the fifth 12-month period); and

     (ii) reimbursing the Managing General Partner for any previous
          subordination payments to the extent cumulative cash distributions to
          Participants, including any subordination payments, would exceed:

          (a)  $1,000 per Unit (10% of $10,000 per Unit) in the first 12-month
               period;

          (b)  $2,000 per Unit (20% of $10,000 per Unit) in the second 12-month
               period;

          (c)  $3,000 per Unit (30% of $10,000 per Unit) in the third 12-month
               period;

          (d)  $4,000 per Unit (40% of $10,000 per Unit) in the fourth 12-month
               period; or

          (e)  $5,000 per Unit (50% of $10,000 per Unit) in the fifth 12-month
               period.

The Managing General Partner's subordination obligation also shall be subject to
the following conditions:

     (i)   the subordination obligation may be prorated in the Managing General
           Partner's discretion (e.g. in the case of a monthly distribution, the
           Managing General Partner shall not have any subordination obligation
           if the cumulative monthly distributions to Participants equal $83.33
           per Unit (8.333% of $1,000 per Unit) or more, assuming there are no
           subordination distributions owed for any preceding period);

     (ii)  the Managing General Partner shall not be required to return
           Partnership distributions previously received by it, even though a
           subordination obligation arises after the distributions;

     (iii) subject to the foregoing provisions of this section, only Partnership
           revenues in the current distribution period shall be debited or
           credited to the Managing General Partner as may be necessary to
           provide, to the extent possible, subordination distributions to the
           Participants and reimbursements to the Managing General Partner;

     (iv)  no subordination distributions to the Participants or reimbursements
           to the Managing General Partner shall be made after the expiration of
           the fifth 12-month subordination period; and

     (v)   subordination payments to the Participants shall be subject to any
           lien or priority granted by the Managing General Partner to its
           lenders pursuant to agreements either entered into by the Managing
           General Partner before the subordination obligation arose or entered
           into or renewed by the Managing General Partner after the
           subordination obligation arose.

5.01(b)(5). COMMINGLING OF REVENUES FROM ALL PARTNERSHIP WELLS. The revenues
from all Partnership wells shall be commingled, so regardless of when a
Participant subscribes for Units or is admitted to the Partnership, he will
share in the Partnership's revenues from all of its wells on the same basis as
the other Participants.

                                       40
5.01(c). ALLOCATIONS.

5.01(c)(1). ALLOCATIONS AMONG PARTICIPANTS. Except as provided otherwise in this
Agreement, costs (other than Intangible Drilling Costs and Tangible Costs) and
revenues charged or credited to the Participants as a group, which includes all
revenue credited to the Participants under Section 5.01(b)(4), shall be
allocated among the Participants, including the Managing General Partner to the
extent of any optional subscription for Units under Section 3.03(b)(1), in the
ratio of their respective Units based on $10,000 per Unit regardless of the
actual subscription price paid by a Participant for his Units.

Intangible Drilling Costs and Tangible Costs charged to the Participants as a
group shall be allocated among the Participants, including the Managing General
Partner to the extent of any optional subscription for Units under Section
3.03(b)(1), in the ratio of the subscription amount designated on their
respective Subscription Agreements rather than the number of their respective
Units.

5.01(c)(2). COSTS AND REVENUES NOT DIRECTLY ALLOCABLE TO A PARTNERSHIP WELL.
Costs and revenues not directly allocable to a particular Partnership Well or
additional operation shall be allocated among the Partnership Wells or
additional operations in any manner the Managing General Partner in its
reasonable discretion, shall select, and shall then be charged or credited in
the same manner as costs or revenues directly applicable to the Partnership Well
or additional operation are being charged or credited.

5.01(c)(3). MANAGING GENERAL PARTNER'S DISCRETION IN MAKING ALLOCATIONS FOR
FEDERAL INCOME TAX PURPOSES. In determining the proper method of allocating
charges or credits among the parties, allocating any item of income, gain, loss,
deduction or credit pursuant to new laws or new IRS or judicial interpretations
of existing law, allocating any other item that is not otherwise specifically
allocated in this Agreement or is subsequently determined by the Managing
General Partner to be clearly inconsistent with a party's economic interest in
the Partnership, or making any other allocations under this Agreement, the
Managing General Partner may adopt any method of allocation that it selects, in
its sole discretion, after consultation with the Partnership's legal counsel or
accountants. Any new allocation provisions shall be made in a manner that is
consistent with the parties' economic interests in the Partnership and will
result in the most favorable aggregate consequences to the Participants that
are, as nearly as possible, consistent with the original allocations described
in this Agreement.

5.02. CAPITAL ACCOUNTS AND ALLOCATIONS THERETO.

5.02(a). CAPITAL ACCOUNTS FOR EACH PARTY TO THIS AGREEMENT. A single, separate
Capital Account shall be established for each party, regardless of the number of
interests owned by the party, the class of the interests and the time or manner
in which the interests were acquired.

5.02(b). CHARGES AND CREDITS.

5.02(b)(1). GENERAL STANDARD. Except as otherwise provided in this Agreement,
the Capital Account of each party shall be determined and maintained in
accordance with Treas. Reg. Section 1.704-l(b)(2)(iv) and shall be increased by:

     (i)   the amount of money contributed by him to the Partnership;

     (ii)  the fair market value of property contributed by him to the
           Partnership, without regard to Section 7701(g) of the Code, net of
           liabilities secured by the contributed property that the Partnership
           is considered to assume or take subject to under Section 752 of the
           Code; and

     (iii) allocations to him of Partnership income and gain, or items thereof,
           including income and gain exempt from tax and income and gain
           described in Treas. Reg. Section 1.704-l(b)(2)(iv)(g), but excluding
           income and gain described in Treas. Reg. Section 1.704-l(b)(4)(i);

and shall be decreased by:

     (iv)  the amount of money distributed to him by the Partnership;

                                       41
(v)   the fair market value of property distributed to him by the
           Partnership, without regard to Section 7701(g) of the Code, net of
           liabilities secured by the distributed property that he is considered
           to assume or take subject to under Section 752 of the Code;

     (vi)  allocations to him of Partnership expenditures described in
           Section 705(a)(2)(B) of the Code; and

     (vii) allocations to him of Partnership loss and deduction, or items
           thereof, including loss and deduction described in Treas. Reg.
           Section 1.704-l(b)(2)(iv)(g), but excluding items described in (vi)
           above, and loss or deduction described in Treas. Reg. Section
           1.704-l(b)(4)(i) or (iii).

5.02(b)(2). EXCEPTION. If Treas. Reg. Section 1.704-l(b)(2)(iv) fails to provide
guidance, Capital Account adjustments shall be made in a manner that:

     (i)   maintains equality between the aggregate governing Capital Accounts
           of the parties and the amount of Partnership capital reflected on the
           Partnership's balance sheet, as computed for book purposes;

     (ii)  is consistent with the underlying economic arrangement of the
           parties; and

     (iii) is based, wherever practicable, on federal tax accounting principles.

5.02(c). PAYMENTS TO THE MANAGING GENERAL PARTNER. The Capital Account of the
Managing General Partner shall be reduced by payments to it pursuant to Section
4.04(a)(2) only to the extent of the Managing General Partner's distributive
share of any Partnership deduction, loss, or other downward Capital Account
adjustment resulting from the payments. Also, in the event, and to the extent,
that the Managing General Partner is treated under the Code as having been
transferred an interest in the Partnership in connection with the performance of
services for the Partnership (whether before or after the formation of the
Partnership):

     (i)   any resulting compensation income shall be allocated 100% to the
           Managing General Partner;

     (ii)  any associated increase in Capital Accounts shall be credited 100% to
           the Managing General Partner; and

     (iii) any associated deduction to which the Partnership is entitled shall
           be allocated 100% to the Managing General Partner.

5.02(d). DISCRETION OF MANAGING GENERAL PARTNER IN THE METHOD OF MAINTAINING
CAPITAL ACCOUNTS. Notwithstanding any other provisions of this Agreement, the
method of maintaining Capital Accounts may be changed from time to time, in the
discretion of the Managing General Partner, to take into consideration Section
704 and other provisions of the Code and the related rules, regulations and
interpretations as may exist from time to time.

5.02(e). REVALUATIONS OF PROPERTY. In the discretion of the Managing General
Partner the Capital Accounts of the parties may be increased or decreased to
reflect a revaluation of Partnership property, including intangible assets such
as goodwill, on a property-by-property basis except as otherwise permitted under
Section 704(c) of the Code and the regulations thereunder, on the Partnership's
books, in accordance with Treas. Reg. Section 1.704-l(b)(2)(iv)(f).

5.02(f). AMOUNT OF BOOK ITEMS. In cases where Section 704(c) of the Code or
Section 5.02(e) applies, Capital Accounts shall be adjusted in accordance with
Treas. Reg. Section 1.704-l(b)(2)(iv)(g) for allocations of depreciation,
depletion, amortization and gain and loss, as computed for book purposes, with
respect to the property.

5.03. ALLOCATION OF INCOME, DEDUCTIONS AND CREDITS.

5.03(a). IN GENERAL.

5.03(a)(1). DEDUCTIONS ARE ALLOCATED TO PARTY CHARGED WITH EXPENDITURE. To the
extent permitted by law and except as otherwise provided in this Agreement, all
deductions and credits, including, but not limited to, intangible drilling and
development costs and depreciation, shall be allocated to the party who has been
charged with the expenditure giving rise to

                                       42
the deductions and credits; and to the extent permitted by law, these parties
shall be entitled to the deductions and credits in computing taxable income or
tax liabilities to the exclusion of any other party. Also, any Partnership
deductions that would be nonrecourse deductions if they were not attributable to
a loan made or guaranteed by the Managing General Partner or its Affiliates
shall be allocated to the Managing General Partner to the extent required by
law.

5.03(a)(2). INCOME AND GAIN ALLOCATED IN ACCORDANCE WITH REVENUES. Except as
otherwise provided in this Agreement, all items of income and gain, including
gain on disposition of assets, shall be allocated in accordance with the related
revenue allocations set forth in Section 5.01(b) and its subsections.

5.03(b). TAX BASIS OF EACH PROPERTY. Subject to Section 704(c) of the Code, the
tax basis of each oil and gas property for computation of cost depletion and
gain or loss on disposition shall be allocated and reallocated when necessary
based on the capital interest in the Partnership as to the property and the
capital interest in the Partnership for this purpose as to each property shall
be considered to be owned by the parties in the ratio in which the expenditure
giving rise to the tax basis of the property has been charged as of the end of
the year.

5.03(c). GAIN OR LOSS ON OIL AND GAS PROPERTIES. Each party shall separately
compute its gain or loss on the disposition of each natural gas and oil property
in accordance with the provisions of Section 613A(c)(7)(D) of the Code, and the
calculation of the gain or loss shall consider the party's adjusted basis in his
property interest computed as provided in Section 5.03(b) and the party's
allocable share of the amount realized from the disposition of the property.

5.03(d). GAIN ON DEPRECIABLE PROPERTY. Gain from each sale or other disposition
of depreciable property shall be allocated to each party whose share of the
proceeds from the sale or other disposition exceeds its contribution to the
adjusted basis of the property in the ratio that the excess bears to the sum of
the excesses of all parties having an excess.

5.03(e). LOSS ON DEPRECIABLE PROPERTY. Loss from each sale, abandonment or other
disposition of depreciable property shall be allocated to each party whose
contribution to the adjusted basis of the property exceeds its share of the
proceeds from the sale, abandonment or other disposition in the proportion that
the excess bears to the sum of the excesses of all parties having an excess.

5.03(f). ALLOCATION IF RECAPTURE TREATED AS ORDINARY INCOME. Any recapture
treated as an increase in ordinary income by reason of Sections 1245, 1250 or
1254 of the Code shall be allocated to the parties in the amounts in which the
recaptured items were previously allocated to them; provided that to the extent
recapture allocated to any party is in excess of the party's gain from the
disposition of the property, the excess shall be allocated to the other parties
but only to the extent of the other parties' gain from the disposition of the
property.

5.03(g). TAX CREDITS. If a Partnership expenditure, whether or not deductible,
that gives rise to a tax credit in a Partnership taxable year also gives rise to
valid allocations of Partnership loss or deduction, or other downward Capital
Account adjustments, for the year, then the parties' interests in the
Partnership with respect to the credit, or the cost giving rise thereto, shall
be in the same proportion as the parties' respective distributive shares of the
loss or deduction, and adjustments. If Partnership receipts, whether or not
taxable, that give rise to a tax credit, including a marginal well production
credit under Section 45I of the Code, in a Partnership taxable year also give
rise to valid allocations of Partnership income or gain, or other upward Capital
Account adjustments, for the year, then the parties' interests in the
Partnership with respect to the credit, or the Partnership's receipts or
production of natural gas and oil production giving rise thereto, shall be in
the same proportion as the parties' respective shares of the Partnership's
production revenues from the sales of its natural gas and oil production as
provided in Section 5.01(b)(4).

5.03(h). DEFICIT CAPITAL ACCOUNTS AND QUALIFIED INCOME OFFSET. Notwithstanding
any provision of this Agreement to the contrary, an allocation of loss or
deduction which would result in a party having a deficit Capital Account balance
as of the end of the taxable year to which the allocation relates, if charged to
the party, to the extent the Participant is not required to restore the deficit
to the Partnership, taking into account:

     (i)   adjustments that, as of the end of the year, reasonably are expected
           to be made to the party's Capital Account for depletion allowances
           with respect to the Partnership's natural gas and oil properties;

                                       43
(ii)  allocations of loss and deduction that, as of the end of the year,
           reasonably are expected to be made to the party under Sections
           704(e)(2) and 706(d) of the Code and Treas. Reg. Section
           1.751-1(b)(2)(ii); and

     (iii) distributions that, as of the end of the year, reasonably are
           expected to be made to the party to the extent they exceed offsetting
           increases to the party's Capital Account, assuming for this purpose
           that the fair market value of Partnership property equals its
           adjusted tax basis, that reasonably are expected to occur during or
           prior to the Partnership taxable years in which the distributions
           reasonably are expected to be made;

shall be charged to the Managing General Partner. Further, the Managing General
Partner shall be credited with an additional amount of Partnership income or
gain equal to the amount of the loss or deduction as quickly as possible to the
extent that the chargeback does not cause or increase deficit balances in the
parties' Capital Accounts which are not required to be restored to the
Partnership.

Notwithstanding any provision of this Agreement to the contrary, if a party
unexpectedly receives an adjustment, allocation, or distribution described in
(i), (ii), or (iii) above, or any other distribution, which causes or increases
a deficit balance in the party's Capital Account which is not required to be
restored to the Partnership, the party shall be allocated items of income and
gain, consisting of a pro rata portion of each item of Partnership income,
including gross income and gain for the year, in an amount and manner sufficient
to eliminate the deficit balance as quickly as possible.

5.03(i). MINIMUM GAIN CHARGEBACK. To the extent there is a net decrease during a
Partnership taxable year in the minimum gain attributable to a Partner
nonrecourse debt, then any Partner with a share of the minimum gain attributable
to the debt at the beginning of the year shall be allocated items of Partnership
income and gain in accordance with Treas. Reg. Section 1.704-2(i).

5.03(j). PARTNERS' ALLOCABLE SHARES. Except as otherwise provided in this
Agreement, each party's allocable share of Partnership income, gain, loss,
deductions and credits shall be determined by using any method prescribed or
permitted by the Secretary of the Treasury by regulations or other guidelines
and selected by the Managing General Partner which takes into account the
varying interests of the parties in the Partnership during the taxable year. In
the absence of those regulations or guidelines, except as otherwise provided in
this Agreement, the allocable share shall be based on actual income, gain, loss,
deductions and credits economically accrued each day during the taxable year in
proportion to each party's varying interest in the Partnership on each day
during the taxable year.

5.03(k). CONTINGENT INCOME. Subject to Section 5.04(d), if it is determined that
any taxable income results to any party by reason of its entitlement to a share
of capital of the Partnership, or a share of profits or revenues of the
Partnership before the profit or revenue has been realized by the Partnership,
the resulting deduction, as well as any resulting gain, shall not enter into
Partnership net income or loss, but shall be separately allocated to that party.

5.04. ELECTIONS.

5.04(a). ELECTION TO DEDUCT INTANGIBLE COSTS. The Partnership's federal income
tax return shall be made in accordance with an election under the option granted
by the Code to deduct intangible drilling and development costs.

5.04(b). NO ELECTION OUT OF SUBCHAPTER K. No election shall be made by the
Partnership, any Partner, or the Operator for the Partnership to be excluded
from the application of the partnership provisions of the Code, including
Subchapter K of Chapter 1 of Subtitle A of the Code.

5.04(c). Section 754 ELECTION. In the event of the transfer of an interest in
the Partnership, or on the death of an individual party hereto, or in the event
of the distribution of property to any party, the Managing General Partner may
choose for the Partnership to file an election in accordance with the applicable
Treasury Regulations to cause the basis of the Partnership's assets to be
adjusted for federal income tax purposes as provided by Sections 734 and 743 of
the Code.

5.04(d). Section 83 ELECTION. The Partnership, the Managing General Partner and
each Participant hereby agree to be legally bound by the provisions of this
Section 5.04(d) and further agree that, in the Managing General Partner's sole
discretion, the Partnership

                                       44
and all of its Partners may elect a safe harbor under which the fair market
value of a Partnership interest that is transferred in connection with the
performance of services is treated as being equal to the liquidation value of
that interest for transfers on or after the date final regulations providing the
safe harbor are published in the Federal Register. If the Managing General
Partner determines that the Partnership and all of its Partners will elect the
safe harbor, which determination may be made solely in the best interests of the
Managing General Partner, the Partnership, the Managing General Partner and each
Participant further agree that:

     (i)   the Partnership shall be authorized and directed to elect the safe
           harbor;

     (ii)  the Partnership and each of its Partners (including any Person to
           whom a Partnership interest is transferred in connection with the
           performance of services) shall comply with all requirements of the
           safe harbor with respect to all Partnership interests transferred in
           connection with the performance of services while the election
           remains effective; and

     (iii) the Managing General Partner, in its sole discretion, may cause the
           Partnership to terminate the safe harbor election, which
           determination may be made in the sole interests of the Managing
           General Partner.

5.05. DISTRIBUTIONS.

5.05(a). IN GENERAL.

5.05(a)(1). MONTHLY REVIEW OF ACCOUNTS. The Managing General Partner shall
review the accounts of the Partnership at least monthly to determine whether
cash distributions are appropriate and the amount to be distributed, if any.

5.05(a)(2). DISTRIBUTIONS. The Partnership shall distribute funds to the
Managing General Partner and the Participants allocated to their respective
accounts that the Managing General Partner deems unnecessary for the Partnership
to retain.

5.05(a)(3). NO BORROWINGS. In no event shall funds be advanced or borrowed by
the Partnership for distributions to the Managing General Partner and the
Participants if the amount of the distributions would exceed the Partnership's
accrued and received revenues for the previous four quarters, less paid and
accrued Operating Costs with respect to the revenues. The determination of
revenues and costs shall be made in accordance with generally accepted
accounting principles, consistently applied.

5.05(a)(4). DISTRIBUTIONS TO THE MANAGING GENERAL PARTNER. Cash distributions
from the Partnership to the Managing General Partner shall only be made as
follows:

     (i)  in conjunction with distributions to Participants; and

     (ii) out of funds properly allocated to the Managing General Partner's
          account.

5.05(a)(5). RESERVE. At any time after one year from the date each Partnership
Well is placed into production, the Managing General Partner shall have the
right to deduct each month from the Partnership's net sales proceeds from the
sale of the natural gas and oil production from each of its productive wells up
to $200 per well for the purpose of establishing a fund to cover the estimated
costs of plugging and abandoning the well. All of these funds shall be deposited
in a separate interest bearing account for the benefit of the Partnership, and
the total amount so retained and deposited shall not exceed the Managing General
Partner's reasonable estimate of the costs to plug and abandon the well.

5.05(b). DISTRIBUTION OF UNCOMMITTED SUBSCRIPTION PROCEEDS. Any subscription
proceeds not expended or committed for expenditure, as evidenced by a written
agreement, by the Partnership within 12 months of the Offering Termination Date,
except necessary operating capital, shall be distributed to the Participants in
the ratio that the subscription amount designated on each Participant's
Subscription Agreement bears to the total subscription amounts designated on all
of the Participants' Subscription Agreements, as a return of capital. The
Managing General Partner shall reimburse the Participants for the selling or
other offering expenses, if any, allocable to the return of capital.

                                       45
For purposes of this subsection, "committed for expenditure" shall mean
contracted for, actually earmarked for or allocated by the Managing General
Partner to the Partnership's drilling operations, and "necessary operating
capital" shall mean those funds which, in the opinion of the Managing General
Partner, should remain on hand to assure continuing operation of the
Partnership.

5.05(c). DISTRIBUTIONS ON WINDING UP. On the winding up of the Partnership
distributions shall be made as provided in Section 7.02.

5.05(d). INTEREST AND RETURN OF CAPITAL. No party shall under any circumstances
be entitled to any interest on amounts retained by the Partnership. Each
Participant shall look only to his share of distributions, if any, from the
Partnership for a return of his Capital Contribution.

                                   ARTICLE VI
                                TRANSFER OF UNITS

6.01. TRANSFERABILITY OF UNITS. A Participant's transfer of a portion or all his
Units, or any interest in his Units, is subject to all of the provisions of this
Article VI. For purposes of this Article VI, the term "transfer" shall include
any sale, exchange, gift, assignment, pledge, mortgage, hypothecation,
redemption or other form of transfer of a Unit, or any interest in a Unit, by a
Participant (which may include the Managing General Partner or its Affiliates,
if they purchase Units) or by operation of law, including any transfers of Units
which a Participant presents to the Managing General Partner for purchase under
Section 6.03.

6.01(a). RIGHTS OF ASSIGNEE. Unless a transferee of a Participant's Unit becomes
a substitute Participant with respect to that Unit in accordance with the
provisions of Section 6.02(a)(3)(a), he shall not be entitled to any of the
rights granted to a Participant under this Agreement, other than the right to
receive all or part of the share of the profits, losses, income, gains,
deductions, credits and depletion allowances, or items thereof, and cash
distributions or returns of capital to which his transferor would otherwise be
entitled under this Agreement.

6.01(b). CONVERSION OF INVESTOR GENERAL PARTNER UNITS TO LIMITED PARTNER UNITS.

6.01(b)(1). AUTOMATIC CONVERSION. After all of the Partnership Wells have been
drilled and completed, as determined by the Managing General Partner, the
Managing General Partner shall file an amended certificate of limited
partnership with the Secretary of State of the State of Delaware for the purpose
of converting the Investor General Partner Units to Limited Partner Units.

6.01(b)(2). INVESTOR GENERAL PARTNERS SHALL HAVE CONTINGENT LIABILITY. On
conversion the Investor General Partners shall be Limited Partners entitled to
limited liability; however, they shall remain liable to the Partnership for any
additional Capital Contribution required for their proportionate share of any
Partnership obligation or liability arising before the conversion of their Units
as provided in Section 3.05(b)(2).

6.01(b)(3). CONVERSION SHALL NOT AFFECT ALLOCATIONS. The conversion shall not
affect the allocation to any Participant of any item of Partnership income,
gain, loss, deduction or credit or other item of special tax significance other
than Partnership liabilities, if any. Further, the conversion shall not affect
any Participant's interest in the Partnership's natural gas and oil properties
and unrealized receivables.

6.01(b)(4). RIGHT TO CONVERT IF REDUCTION OF INSURANCE. Notwithstanding the
foregoing, the Managing General Partner shall notify all Participants at least
30 days before the effective date of any material adverse change in the
Partnership's insurance coverage. If the insurance coverage is to be materially
reduced, then the Investor General Partners shall have the right to convert
their Units into Limited Partner Units before the reduction by giving written
notice to the Managing General Partner.

6.02. SPECIAL RESTRICTIONS ON TRANSFERS OF UNITS BY PARTICIPANTS.

6.02(a). IN GENERAL. Transfers of Units by Participants are subject to the
following general conditions:

                                       46
(i)   except as provided by operation of law:

           (a) only whole Units may be transferred unless the Participant owns
               less than a whole Unit, in which case his entire fractional
               interest must be transferred; and

           (b) Units may not be transferred to a person who is under the age of
               18 or incompetent (unless an attorney-in-fact, guardian,
               custodian or conservator has been appointed to handle the affairs
               of that person) without the Managing General Partner's consent;

     (ii)  the costs and expenses associated with the transfer must be paid by
           the assignor Participant;

     (iii) the transfer documents must be in a form satisfactory to the Managing
           General Partner; and

     (iv)  the terms of the transfer must not contravene those of this
           Agreement.

Transfers of Units by Participants are subject to the following additional
restrictions set forth in Sections 6.02(a)(1) and 6.02(a)(2).

6.02(a)(1). TAX LAW RESTRICTIONS. Subject to transfers permitted by Section 6.03
and transfers by operation of law, no transfer of a Unit by a Participant shall
be made which, in the opinion of counsel to the Partnership, would result in the
Partnership being either:

     (i)  terminated for tax purposes under Section 708 of the Code; or

     (ii) treated as a "publicly-traded" partnership for purposes of Section
          469(k) of the Code.

6.02(a)(2). SECURITIES LAWS RESTRICTION. Subject to transfers permitted by
Section 6.03 and transfers by operation of law, no Unit shall be transferred by
a Participant unless there is either:

     (i)  an effective registration of the Unit under the Securities Act of
          1933, as amended, and qualification under applicable state securities
          laws; or

     (ii) an opinion of counsel acceptable to the Managing General Partner that
          the registration and qualification of the Unit is not required, unless
          this requirement is waived by the Managing General Partner.

Transfers of Units by Participants are also subject to any conditions contained
in the Subscription Agreement and Exhibit (B) to the Prospectus.

6.02(a)(3). SUBSTITUTE PARTICIPANT.

6.02(a)(3)(a). PROCEDURE TO BECOME SUBSTITUTE PARTICIPANT. Subject to Sections
6.02(a)(1) and 6.02(a)(2), a transferee of a Participant's Unit shall become a
substitute Participant entitled to all the rights of a Participant if, and only
if:

     (i)   the transferor gives the transferee the right;

     (ii)  the transferee pays to the Partnership all costs and expenses
           incurred by the Partnership in connection with the substitution; and

     (iii) the transferee executes and delivers the instruments necessary to
           establish that a legal transfer has taken place and to confirm the
           agreement of the transferee to be bound by all of the terms of this
           Agreement, in a form acceptable to the Managing General Partner.

6.02(a)(3)(b). RIGHTS OF SUBSTITUTE PARTICIPANT. A substitute Participant shall
be entitled to all of the rights attributable to full ownership of the assigned
Units including the right to vote.

                                       47
6.02(b). EFFECT OF TRANSFER.

6.02(b)(1). AMENDMENT OF RECORDS. The Partnership shall amend its records at
least once each calendar quarter to effect the substitution of substitute
Participants.

Any transfer of a Unit by a Participant which is permitted under this Article
VI, when the transferee does not become a substitute Participant, shall be
effective as follows:

     (i)  midnight of the last day of the calendar month in which it is made; or

     (ii) at the Managing General Partner's election, 7:00 A.M. of the following
          day.

6.02(b)(2). A TRANSFER OF UNITS DOES NOT RELIEVE THE TRANSFEROR OF CERTAIN
COSTS. No transfer of a Unit by a Participant, including a transfer of less than
all of a Participant's Units or the transfer of a Participant's Units to more
than one party, shall relieve the transferor of its responsibility for its
proportionate part of any expenses, obligations and liabilities under this
Agreement related to the Units so transferred, whether arising before or after
the transfer.

6.02(b)(3). A TRANSFER OF UNITS DOES NOT REQUIRE A PARTNERSHIP ACCOUNTING. No
transfer of a Unit by a Participant shall require an accounting of the
Partnership. Also, no transfer of a Unit shall grant rights under this
Agreement, including the exercise of any elections, as between the transferring
Participant and the Partnership, the Managing General Partner and the remaining
Participants to more than one Person unanimously designated by the transferee(s)
of the Unit, and, if he has retained an interest in the transferred Unit, the
transferor of the Unit.

6.02(b)(4). REQUIRED NOTICE TO MANAGING GENERAL PARTNER OF TRANSFER OF UNITS.
Until the Managing General Partner receives from the transferring Participant a
written notice in a form acceptable to the Managing General Partner that
designates the transferee(s) of a Unit, the Managing General Partner shall
continue to account only to the Person to whom it was furnishing notices
pursuant to Section 8.01 and its subsections before the purported transfer of
the Unit. This party shall continue to exercise all rights under this Agreement
applicable to the Units owned by the purported transferor of the Unit.

6.03. PRESENTMENT.

6.03(a). IN GENERAL. Participants shall have the right to present their Units to
the Managing General Partner for purchase subject to the conditions and
limitations set forth in this Section 6.03. A Participant, however, is not
obligated to present his Units for purchase.

The Managing General Partner shall not be obligated to purchase more than 5% of
the total outstanding Units in any calendar year and this 5% limit may not be
waived. The Managing General Partner shall not purchase less than one Unit
unless the lesser amount represents the Participant's entire interest in the
Partnership, however, the Managing General Partner may waive this limitation.

A Participant may present his Units in writing to the Managing General Partner
every year beginning with the fifth calendar year after the Offering Termination
Date subject to the following conditions:

     (i)   the presentment request must be made by the Participant within 120
           days of the reserve report described in Section 4.03(b)(3);

     (ii)  in accordance with Treas. Reg. Section 1.7704-1(f), the purchase may
           not be made until at least 60 calendar days after the Participant
           notifies the Partnership in writing of the Participant's intention to
           exercise the presentment right; and

     (iii) the purchase shall not be considered effective until the presentment
           price has been paid to the Participant in cash to the Participant.

6.03(b). REQUIREMENT FOR INDEPENDENT PETROLEUM CONSULTANT. The amount of the
presentment price attributable to Partnership reserves shall be determined based
on the last reserve report of the Partnership prepared by the Managing General

                                       48
Partner and reviewed by an Independent Expert. The Managing General Partner
shall estimate the present worth of future net revenues attributable to the
Partnership's interest in the Proved Reserves as described in Section
4.03(b)(3)(ii). The calculation of the presentment price shall be made as set
forth in Section 6.03(c).

6.03(c). CALCULATION OF PRESENTMENT PRICE. The presentment price shall be based
on the Partnership's net assets and liabilities and shall be allocated pro rata
to each Participant in the ratio that his number of Units bears to the total
number of Units. Subject to the foregoing, the presentment price shall include
the sum of the following Partnership items:

     (i)   an amount based on 70% of the present worth of future net revenues
           from the Proved Reserves determined as described in Section 6.03(b);

     (ii)  cash on hand;

     (iii) prepaid expenses and accounts receivable less a reasonable amount for
           doubtful accounts; and

     (iv)  the estimated market value of all assets that are not separately
           specified above, determined in accordance with standard industry
           valuation procedures.

There shall be deducted from the foregoing sum the following Partnership items:

     (i)  an amount equal to all debts, obligations, and other liabilities,
          including accrued expenses; and

     (ii) any distributions made to the Participants between the date of the
          presentment request and the date the presentment price is paid to the
          selling Participant. However, if any amount of those cash
          distributions to the Participant by the Partnership was derived from
          the sale of natural gas, oil or other mineral production, or of a
          producing property owned by the Partnership, after the date of the
          presentment request, for purposes of determining the reduction of the
          presentment price the amount of those cash distributions shall be
          discounted using the same rate used to take into account the risk
          factors employed to determine the present worth of the Partnership's
          Proved Reserves.

6.03(d). FURTHER ADJUSTMENT MAY BE ALLOWED. The presentment price may be further
adjusted by the Managing General Partner for estimated changes therein from the
date of the report to the date of payment of the presentment price to the
Selling Participant because of the following:

     (i)  the production or sales of, or additions to, reserves and lease and
          well equipment, sale or abandonment of Leases, and similar matters
          occurring before the date of the presentment request; and

     (ii) any of the following occurring before payment of the presentment price
          to the selling Participant:

          (a)  changes in well performance;

          (b)  increases or decreases in the market price of natural gas, oil or
               other minerals;

          (c)  revisions to regulations relating to the importing of
               hydrocarbons;

          (d)  changes in income, ad valorem, and other tax laws, such as
               material variations in the provisions for depletion; and

          (e)  similar matters.

6.03(e). SELECTION BY LOT. If less than all of the Units presented at any time
are to be purchased, then the Participants whose Units are to be purchased will
be selected by lot.

The Managing General Partner's obligation to purchase Units presented may be
discharged for its benefit by a third-party or an Affiliate. The Units of the
selling Participant shall be transferred to the party who pays for it. A selling
Participant shall

                                       49
be required to deliver an executed assignment of his Units, in a form
satisfactory to the Managing General Partner, together with any other
documentation as the Managing General Partner may reasonably request.

6.03(f). NO OBLIGATION OF THE MANAGING GENERAL PARTNER TO ESTABLISH A RESERVE.
The Managing General Partner shall have no obligation to establish any reserve
to satisfy the presentment feature under this section.

6.03(g). SUSPENSION OF PRESENTMENT FEATURE. The Managing General Partner may
suspend this presentment feature by so notifying Participants at any time if it
determines in its sole discretion that it:

     (i)  does not have sufficient cash flow; or

     (ii) is unable to borrow funds for this purpose on terms it deems
          reasonable.

In addition, the presentment feature may be conditioned, in the Managing General
Partner's sole discretion, on the Managing General Partner's receipt of an
opinion of counsel that the transfers will not cause the Partnership to be
treated as a "publicly traded partnership" under the Code.

The Managing General Partner shall hold the purchased Units for its own account
and not for resale.

6.04. REDEMPTION OF UNITS FROM NON-CITIZEN ASSIGNEES. If the Partnership, the
Managing General Partner or any of its Affiliates become subject to federal,
state or local laws or regulations that, in the reasonable determination of the
Managing General Partner, create a substantial risk of cancellation or
forfeiture of any property that they have an interest in because of the
nationality, citizenship or other related status of any Participant or assignee
of a Participant's Units, the Partnership may redeem, on 30 days' advance notice
to the Participant, the Participant's Units or the Units held by the assignee of
a Participant, at a reasonable redemption price per Unit as determined by the
Managing General Partner in its sole discretion.

                                   ARTICLE VII
                      DURATION, DISSOLUTION, AND WINDING UP

7.01. DURATION.

7.01(a). FIFTY YEAR TERM. The Partnership shall continue in existence for a term
of 50 years from the effective date of this Agreement unless sooner terminated
as set forth below.

7.01(b). TERMINATION. The Partnership shall terminate following the occurrence
of:

     (i)  a Final Terminating Event; or

     (ii) any event that causes the dissolution of a limited partnership under
          the Delaware Revised Uniform Limited Partnership Act.

7.01(c). CONTINUANCE OF PARTNERSHIP EXCEPT ON FINAL TERMINATING EVENT. Other
than the occurrence of a Final Terminating Event, the Partnership or any
successor limited partnership shall not be wound up, but shall be continued by
the parties and their respective successors as a successor limited partnership
under all of the terms of this Agreement. The successor limited partnership
shall succeed to all of the assets of the Partnership. As used throughout this
Agreement, the term "Partnership" shall include the successor limited
partnership and the parties to the successor limited partnership.

7.02. DISSOLUTION AND WINDING UP.

7.02(a). FINAL TERMINATING EVENT. On the occurrence of a Final Terminating Event
the affairs of the Partnership shall be wound up and there shall be distributed
to each of the parties its Distribution Interest in the remaining Partnership
assets.

7.02(b). TIME OF LIQUIDATING DISTRIBUTION. To the extent practicable and in
accordance with sound business practices in the judgment of the Managing General
Partner, liquidating distributions shall be made by:

                                       50
(i)  the end of the taxable year in which liquidation occurs, determined
          without regard to Section 706(c)(2)(A) of the Code; or

     (ii) if later, within 90 days after the date of the liquidation.

Notwithstanding, the following amounts are not required to be distributed within
the foregoing time periods so long as the withheld amounts are distributed as
soon as practical:

     (i)  amounts withheld for reserves reasonably required for liabilities of
          the Partnership; and

     (ii) installment obligations owed to the Partnership.

7.02(c). IN-KIND DISTRIBUTIONS. The Managing General Partner shall not be
obligated to offer in-kind property distributions to the Participants, but may
do so, in its discretion. Any in-kind property distributions to the Participants
shall be made to a liquidating trust or similar entity for the benefit of the
Participants, unless at the time of the distribution:

     (i)  the Managing General Partner offers the individual Participants the
          election of receiving in-kind property distributions and the
          Participants accept the offer after being advised of the risks
          associated with direct ownership; or

     (ii) there are alternative arrangements in place which assure the
          Participants that they will not, at any time, be responsible for the
          operation or disposition of Partnership properties.

If the Managing General Partner has not received a Participant's consent within
30 days after the Managing General Partner mailed the request for consent, then
it shall be presumed that the Participant has refused to give his consent.

7.02(d). SALE IF NO CONSENT. Any Partnership asset which would otherwise be
distributed in-kind to a Participant, except for the failure or refusal of the
Participant to give his written consent to the distribution, may instead be sold
by the Managing General Partner at the best price reasonably obtainable from an
independent third-party, who is not an Affiliate of the Managing General
Partner, or to the Managing General Partner itself or its Affiliates, including
an Affiliated Income Program, at fair market value as determined by an
Independent Expert selected by the Managing General Partner.

                                  ARTICLE VIII
                            MISCELLANEOUS PROVISIONS

8.01. NOTICES.

8.01(a). METHOD. Any notice required under this Agreement shall be:

     (i)  in writing; and

     (ii) given by mail or delivered by an overnight delivery company (although
          one-day delivery is not required) addressed to the party to receive
          the notice at the address designated in Section 1.03.

If there is a transfer of Units under this Agreement, no notice to the
transferee shall be required, nor shall the transferee have any rights under
this Agreement, until notice of the transfer has been given to the Managing
General Partner.

Any transfer of Units under this Agreement shall not increase the Managing
General Partner's or the Partnership's duty to give notice. If there is a
transfer of Units under this Agreement to more than one party, then notice to
any owner of any interest in the Units shall be notice to all of the owners of
the Units.

8.01(b). CHANGE IN ADDRESS. The address of any party to this Agreement may be
changed by notice as follows:

     (i)  to the Participants, if there is a change of address by the Managing
          General Partner; or

                                       51
(ii) to the Managing General Partner, if there is a change of address by a
          Participant.

8.01(c). TIME NOTICE DEEMED GIVEN. If the notice is given by the Managing
General Partner, then the notice shall be considered given, and any applicable
time shall run, from the date the notice is placed in the mail or delivered to
the overnight delivery company.

If the notice is given by any Participant, then the notice shall be considered
given and any applicable time shall run from the date the notice is received.

8.01(d). EFFECTIVENESS OF NOTICE. Any notice to a party other than the Managing
General Partner, including a notice requiring concurrence or nonconcurrence,
shall be effective, and any failure to respond binding, irrespective of the
following:

     (i)  whether or not the notice is actually received; or

     (ii) any disability or death on the part of the noticee, even if the
          disability or death is known to the party giving the notice.

8.01(e). FAILURE TO RESPOND. Except pursuant to Section 7.02(c) or when this
Agreement expressly requires affirmative approval of a Participant, any
Participant who fails to respond in writing within the time specified to a
request by the Managing General Partner as set forth below, for approval of, or
concurrence in, a proposed action shall be conclusively deemed to have approved
the action. Except pursuant to Section 7.02(c), when this Agreement expressly
requires affirmative approval of a Participant, the Managing General Partner
shall send a first request and the time period for the Participant's written
response shall not be less than 15 business days from the date of mailing of the
request. If the Participant does not respond in writing to the first request,
then the Managing General Partner shall send a second request. If the
Participant does not respond in writing to the second request within seven
calendar days from the date of mailing the second request, then the Participant
shall be conclusively deemed to have approved the action.

8.02. TIME. Time is of the essence of each part of this Agreement.

8.03. APPLICABLE LAW. The terms and provisions of this Agreement shall be
construed under the laws of the State of Delaware, other than its conflict of
law provisions, however, this section shall not be deemed to limit causes of
action for alleged violations of federal or state securities law to the laws of
the State of Delaware. Neither this Agreement nor the Subscription Agreement
shall require mandatory venue or mandatory arbitration of any or all claims by
Participants against the Sponsor.

8.04. AGREEMENT IN COUNTERPARTS. This Agreement may be executed in counterpart
and shall be binding on all of the parties executing this or similar agreements
from and after the date of execution by each party.

8.05. AMENDMENT.

8.05(a). PROCEDURE FOR AMENDMENT. No changes in this Agreement shall be binding
unless:

     (i)  proposed in writing by the Managing General Partner, and adopted with
          the consent of Participants whose Units equal a majority of the total
          Units; or

     (ii) proposed in writing by Participants whose Units equal 10% or more of
          the total Units and approved by an affirmative vote of Participants
          whose Units equal a majority of the total Units.

8.05(b). CIRCUMSTANCES UNDER WHICH THE MANAGING GENERAL PARTNER ALONE MAY AMEND.
The Managing General Partner is authorized to amend this Agreement and its
exhibits without the consent of Participants in any way deemed necessary or
desirable by it to do any or all of the following:

     (i)   add, or substitute in the case of an assigning party, additional
           Participants;

                                       52
(ii)  enhance the tax benefits of the Partnership to the parties and amend
           the allocation provisions of this Agreement as provided in
           Section 5.01(c)(3);

     (iii) satisfy any requirements, conditions, guidelines, options, or
           elections contained in any opinion, directive, order, ruling, or
           regulation of the SEC, the IRS, or any other federal or state agency,
           or in any federal or state statute, compliance with which it deems to
           be in the best interest of the Partnership; or

     (iv)  cure any ambiguity, correct or supplement any provision of this
           Agreement that may be inconsistent with any other provision of this
           Agreement, or add any provision to this Agreement with respect to
           matters, events or issues arising under this Agreement that is not
           inconsistent with the other provisions of this Agreement.

Notwithstanding the foregoing, no amendment materially and adversely affecting
the interests or rights of Participants shall be made without the consent of the
Participants whose interests or rights will be so affected.

8.06. ADDITIONAL PARTNERS. Each Participant consents to the admission to the
Partnership of additional Participants as the Managing General Partner, in its
discretion, chooses to admit.

8.07. LEGAL EFFECT. This Agreement shall be binding on and inure to the benefit
of the parties, their heirs, devisees, personal representatives, successors and
assigns, and shall run with the interests subject to this Agreement. The terms
"Partnership," "Limited Partner," "Investor General Partner," "Participant,"
"Partner," "Managing General Partner," "Operator," or "parties" shall equally
apply to any successor limited partnership, and any heir, devisee, personal
representative, successor or assign of a party.

IN WITNESS WHEREOF, the parties hereto set their hands as of the ________ day of
___________________, 2007.

ATLAS:                                  ATLAS RESOURCES, LLC
                                        Managing General Partner

                                        By:
                                            ------------------------------------

                                       53
EXHIBIT (I-A)

                                     FORM OF
                     MANAGING GENERAL PARTNER SIGNATURE PAGE
EXHIBIT (I-A)
                     MANAGING GENERAL PARTNER SIGNATURE PAGE

Attached to and made a part of the AMENDED AND RESTATED CERTIFICATE AND
AGREEMENT OF LIMITED PARTNERSHIP of ATLAS AMERICA PUBLIC #16-2007(A) L.P.

The undersigned agrees:

     1.   to serve as the Managing General Partner of ATLAS AMERICA PUBLIC
          #16-2007(A) L.P. (the "Partnership"), and hereby executes, swears to,
          and agrees to all the terms of the Partnership Agreement;

     2.   to pay the required subscription of the Managing General Partner under
          Section 3.04(a) of the Partnership Agreement; and

     3.   to subscribe to the Partnership as follows:

          (a)  $___________________ [________] Unit(s)] under Section 3.03(b)(1)
               of the Partnership Agreement as a Limited Partner; or

          (b)  $___________________ [________] Unit(s)] under Section 3.03(b)(1)
               of the Partnership Agreement as an Investor General Partner.

MANAGING GENERAL PARTNER:

Atlas Resources, LLC                    Address:

By:
    ---------------------------------   311 Rouser Road
                                        Moon Township, Pennsylvania 15108

ACCEPTED this ________ day of __________________,  2007.

                                        ATLAS RESOURCES, LLC
                                        MANAGING GENERAL PARTNER

                                        By:
                                            ------------------------------------
EXHIBIT (I-B)

                                     FORM OF
                             SUBSCRIPTION AGREEMENT
ATLAS AMERICA PUBLIC #16-2007(A) L.P.

----------------------------------------------------------------------------------------------------------
                                          SUBSCRIPTION AGREEMENT
----------------------------------------------------------------------------------------------------------

I, the undersigned, hereby offer to purchase Units of Atlas America Public #16-2007(A) L.P. in the amount
set forth on the Signature Page of this Subscription Agreement and on the terms described in the current
Prospectus for Atlas America Public #16-2007 Program, as supplemented or amended from time to time. I
acknowledge and agree that my execution of this Subscription Agreement also constitutes my execution of
the Agreement of Limited Partnership (the "Partnership Agreement") the form of which is attached as
Exhibit (A) to the Prospectus and I agree to be bound by all of the terms and conditions of the
Partnership Agreement if my subscription is accepted by Atlas Resources, LLC, the Managing General
Partner. I understand and agree that I may not assign this offer, nor may it be withdrawn after it has
been accepted by the Managing General Partner. I hereby irrevocably constitute and appoint the Managing
General Partner, and its duly authorized agents, my agent and attorney-in-fact, in my name, place and
stead, to make, execute, acknowledge, swear to, file, record and deliver the Agreement of Limited
Partnership and any certificates related thereto. I further understand that following the Signature Page
there are certain representations, warranties and covenants which I must make before the Managing General
Partner will accept my subscription.

----------------------------------------------------------------------------------------------------------
                                 SIGNATURE PAGE OF SUBSCRIPTION AGREEMENT
----------------------------------------------------------------------------------------------------------

I, the undersigned, agree to purchase _____________ Units at $10,000 per Unit in ATLAS AMERICA PUBLIC
#16-2007(A) L.P. (the "Partnership") as (check one):

                                                              SUBSCRIPTION AMOUNT

     [_] INVESTOR GENERAL PARTNER                             $__________________________

     [_] LIMITED PARTNER                                      (____________________# Units)

INSTRUCTIONS

----------------------------------------------------------------------------------------------------------
Make your check payable to: "Atlas America Public #16-2007(A) L.P., Escrow Agent, National City Bank of
PA." Minimum Subscription: one Unit ($10,000). Additional Subscriptions in $1,000 increments. If you are
an individual investor you must personally sign this Signature Page and provide the information requested
below. Wire instructions available upon request.
----------------------------------------------------------------------------------------------------------

Subscriber (All individual investors must personally sign this Signature Page.)

NAME OF TRUST, CORPORATION, LLC, PARTNERSHIP: NAME ______________________________________________________
(ENCLOSE SUPPORTING DOCUMENTS.) IF A PARTNERSHIP, CORPORATION OR TRUST, THEN THE MEMBERS, STOCKHOLDERS OR
BENEFICIARIES THEREOF ARE CITIZENS OF _________________________.

Tax I. D. No.: ____________________________________   Home Address (Do not use P.O. Box)

___________________________________________________   ____________________________________________________
Print Name                                            ____________________________________________________
                                                      ____________________________________________________
X
---------------------------------------------------
Signature

                                                      SEE THE ATTACHED "DISTRIBUTIONS NOT TO ADDRESS OF
                                                      RECORD FOR ELECTRONIC AND ALTERNATE ADDRESS
Tax I. D. No.: ____________________________________   INFORMATION.

___________________________________________________
Print Name

X
---------------------------------------------------
Signature

I received my final prospectus on _________________

(CHECK ONE): OWNERSHIP OF THE UNITS-   [_] Tenants-in-Common                             [_] Partnership
                                       [_] Joint Tenancy with Right of Survivorship      [_] C Corporation
                                       [_] Individual                                    [_] S Corporation
                                       [_] Community Property with Survivorship Rights   [_] Trust
                                       [_] Limited Liability Company                     [_] Other
1
Date: _____________________

My Telephone No.: Home ____________________________   Business ___________________________________________

My E-mail Address: ________________________________

(CHECK ONE):                      [_] I am at least twenty-one years of age   [_] I am not twenty-one
                                                                                  years of age

(CHECK ONE): I am a:              [_] Calendar Year Taxpayer                  [_] Fiscal Year Taxpayer

(CHECK IF APPLICABLE): I am a:    [_] Farmer (2/3 or more of my gross income in 2005 or 2004 is from
                                      farming)

----------------------------------------------------------------------------------------------------------
             TO BE COMPLETED BY REGISTERED REPRESENTATIVE (FOR COMMISSION AND OTHER PURPOSES)
----------------------------------------------------------------------------------------------------------

I hereby represent that I have discharged my affirmative obligations under Rule 2810(b)(2)(B) and
(b)(3)(D) of the NASD's Conduct Rules and specifically have obtained information from the above-named
subscriber concerning his/her age, net worth, annual income, federal income tax bracket, investment
objectives, investment portfolio, and other financial information and have determined that an investment
in the Partnership is suitable for such subscriber, that such subscriber is or will be in a financial
position to realize the benefits of this investment, and that such subscriber has a fair market net worth
sufficient to sustain the risks for this investment. I have also informed the subscriber of all pertinent
facts relating to the liquidity and marketability of an investment in the Partnership, of the risks of
unlimited liability regarding an investment as an Investor General Partner, and of the passive loss
limitations for tax purposes of an investment as a Limited Partner.

___________________________________________________   ____________________________________________________
Name of Registered Representative and CRD Number      Name of Broker/Dealer

___________________________________________________   ____________________________________________________
Signature of Registered Representative                Broker/Dealer CRD Number

Registered Representative Office Address:             Broker/Dealer Facsimile Number: ____________________

___________________________________________________   Broker/Dealer E-mail Address: ______________________

___________________________________________________

Phone Number: _____________________________________

Facsimile Number: _________________________________

E-mail Address: ___________________________________

___________________________________________________

Company Name (if other than Broker/Dealer Name)

NOTICE TO BROKER-DEALER:

Send SUBSCRIPTION DOCUMENTS completed and signed with CHECK MADE PAYABLE TO: "ATLAS AMERICA PUBLIC
#16-2007(A) L.P., ESCROW AGENT, NATIONAL CITY BANK OF PA" to:

Mr. Justin Atkinson
Anthem Securities, Inc.
311 Rouser Road
P.O. Box 926
Moon Township, Pennsylvania 15108-0926
(412) 262-1680
(412) 262-7430 (FAX)

WIRE TRANSFERS are available. Please contact Ms. Tammy Patterson at (412) 262-1680 for information.

----------------------------------------------------------------------------------------------------------
                              TO BE COMPLETED BY THE MANAGING GENERAL PARTNER
----------------------------------------------------------------------------------------------------------

ACCEPTED THIS __________ day                          ATLAS RESOURCES, LLC,
of ______________________, 2007                       MANAGING GENERAL PARTNER

                                                      By:
                                                          ------------------------------------------------
2
In order to induce the Managing General Partner to accept this subscription, I
hereby represent, warrant, covenant and agree as follows:

INVESTOR'S   CO-INVESTOR'S
 INITIALS       INITIALS
----------   -------------

_____        _____           I have received the Prospectus.

_____        _____           I (other than if I am a Minnesota or Maine
                             resident) recognize and understand that before this
                             offering there has been no public market for the
                             Units and it is unlikely that after the offering
                             there will be any such market, the transferability
                             of the Units is restricted, and in case of
                             emergency or other change in circumstances I cannot
                             expect to be able to readily liquidate my
                             investment in the Units.

_____        _____           I am purchasing the Units for my own account, for
                             investment purposes and not for the account of
                             others, and with no present intention of reselling
                             them.

_____        _____           If an individual, I am a citizen of the United
                             States of America and at least twenty-one years of
                             age.

_____        _____           If a partnership, corporation or trust, then I am
                             at least twenty-one years of age and empowered and
                             duly authorized under a governing document, trust
                             instrument, charter, certificate of incorporation,
                             by-law provision or the like to enter into this
                             Subscription Agreement and to perform the
                             transactions contemplated by the Prospectus,
                             including its exhibits.

_____        _____           I (other than if I am a Minnesota or Maine
                             resident) understand that if I am an Investor
                             General Partner, then I will have unlimited joint
                             and several liability for Partnership obligations
                             and liabilities including amounts in excess of my
                             subscription to the extent the obligations and
                             liabilities exceed the Partnership's insurance
                             proceeds, the Partnership's assets, and
                             indemnification by the Managing General Partner.
                             Also, the insurance may be inadequate to cover
                             these liabilities and there is no insurance
                             coverage for certain claims.

_____        _____           I (other than if I am a Minnesota or Maine
                             resident) understand that if I am a Limited
                             Partner, then I may only use my Partnership losses
                             to the extent of my net passive income from passive
                             activities in the year, with any excess losses
                             being deferred.

_____        _____           I (other than if I am a Minnesota or Maine
                             resident) understand that no state or federal
                             governmental authority has made any finding or
                             determination relating to the fairness for public
                             investment of the Units and no state or federal
                             governmental authority has recommended or endorsed
                             or will recommend or endorse the Units.

_____        _____           I (other than if I am a Minnesota or Maine
                             resident) understand that the Selling Agent or
                             registered representative is required to inform me
                             and the other potential investors of all pertinent
                             facts relating to the Units, including the
                             following: the risks involved in the offering,
                             INCLUDING the speculative nature of the investment
                             and the speculative nature of drilling for natural
                             gas and oil; the financial hazards involved in the
                             offering, including the risk of losing my entire
                             investment; the lack of liquidity of my investment;
                             the restrictions on transferability of my Units;
                             the background of the Managing General Partner and
                             the Operator; the tax consequences of my
                             investment; and the unlimited joint and several
                             liability of the Investor General Partners.

                                       3
To meet the suitability requirements for an investment in your state, please
check and initial either (a), (b), (c) or (d) depending on your state of
residence and whether you are buying limited partner units or investor general
partner units. Also, initial (e) if you are a fiduciary and you meet the
requirement.

INVESTOR'S   CO-INVESTOR'S
 INITIALS       INITIALS
----------   -------------

_____        _____           (a)  IF I PURCHASE LIMITED PARTNER UNITS AND I AM A
                                  RESIDENT OF:

                                  o    ALABAMA,

                                  o    ALASKA,

                                  o    ARIZONA,

                                  o    ARKANSAS,

                                  o    COLORADO,

                                  o    CONNECTICUT,

                                  o    DELAWARE,

                                  o    DISTRICT OF COLUMBIA,

                                  o    FLORIDA,

                                  o    GEORGIA,

                                  o    HAWAII,

                                  o    IDAHO,

                                  o    ILLINOIS,

                                  o    INDIANA,

                                  o    IOWA,

                                  o    KANSAS,

                                  o    KENTUCKY,

                                  o    LOUISIANA,

                                  o    MAINE,

                                  o    MARYLAND,

                                  o    MASSACHUSETTS,

                                  o    MINNESOTA,

                                  o    MISSISSIPPI,

                                  o    MISSOURI,

                                  o    MONTANA,

                                  o    NEBRASKA,

                                  o    NEVADA,

                                  o    NEW MEXICO

                                  o    NEW YORK,

                                  o    NORTH DAKOTA,

                                  o    OKLAHOMA,

                                  o    OREGON,

                                  o    PENNSYLVANIA,

                                  o    RHODE ISLAND,

                                  o    SOUTH CAROLINA,

                                  o    SOUTH DAKOTA,

                                  o    TENNESSEE,

                                  o    TEXAS,

                                  o    UTAH,

                                  o    VERMONT,

                                  o    VIRGINIA,

                                  o    WASHINGTON

                                  o    WEST VIRGINIA,

                                  o    WISCONSIN, OR

                                  o    WYOMING,

                                  then I must have either: a minimum net worth
                                  of $225,000, exclusive of home, home
                                  furnishings, and automobiles, or a minimum net
                                  worth of $60,000, exclusive of home, home
                                  furnishings, and automobiles, and had during
                                  the last tax year or estimate that I will have
                                  during the current tax year "taxable income"
                                  as defined in Section 63 of the Internal
                                  Revenue Code of at least $60,000, without
                                  regard to an investment in the partnership. In
                                  addition, if I am a resident of PENNSYLVANIA,
                                  then I must not make an investment in a
                                  partnership which is in excess of 10% of my
                                  net worth, exclusive of home, home furnishings
                                  and automobiles. Finally, if I am a resident
                                  of KANSAS, it is recommended by the Office of
                                  the Kansas Securities Commissioner that I
                                  should limit my investment in the partnership
                                  and substantially similar programs to no more
                                  than 10% of my net worth, excluding home,
                                  furnishings and automobiles.

_____        _____           (b)  IF I PURCHASE LIMITED PARTNER UNITS AND I AM A
                                  RESIDENT OF:

                                  o    CALIFORNIA,

                                  o    MICHIGAN,

                                  o    NEW HAMPSHIRE,

                                  o    NEW JERSEY,

                                  o    NORTH CAROLINA, OR

                                  o    OHIO,

                                  THEN I REPRESENT THAT I AM AWARE OF AND MEET
                                  THAT STATE'S QUALIFICATIONS AND SUITABILITY
                                  STANDARDS SET FORTH IN EXHIBIT (B) TO THE
                                  PROSPECTUS.

                                       4
INVESTOR'S   CO-INVESTOR'S
 INITIALS       INITIALS
----------   -------------

_____        _____           (c)  IF I PURCHASE INVESTOR GENERAL PARTNER UNITS
                                  AND I AM A RESIDENT OF:

                                  o    ALASKA,

                                  o    COLORADO,

                                  o    CONNECTICUT,

                                  o    DELAWARE,

                                  o    DISTRICT OF COLUMBIA,

                                  o    FLORIDA,

                                  o    GEORGIA,

                                  o    HAWAII,

                                  o    IDAHO,

                                  o    ILLINOIS,

                                  o    LOUISIANA,

                                  o    MARYLAND,

                                  o    MONTANA,

                                  o    NEBRASKA,

                                  o    NEVADA,

                                  o    NEW YORK,

                                  o    NORTH DAKOTA,

                                  o    RHODE ISLAND,

                                  o    SOUTH CAROLINA,

                                  o    UTAH,

                                  o    VIRGINIA,

                                  o    WEST VIRGINIA,

                                  o    WISCONSIN, OR

                                  o    WYOMING,

                                  then I must have either: a net worth of at
                                  least $225,000, exclusive of home, furnishings
                                  and automobiles, or a net worth, exclusive of
                                  home, furnishings and automobiles, of at least
                                  $60,000, and had during the last tax year, or
                                  estimate that I will have during the current
                                  tax year, "taxable income" as defined in
                                  Section 63 of the Code of at least $60,000,
                                  without regard to an investment in the
                                  Partnership.

_____        _____           (d)  IF I PURCHASE INVESTOR GENERAL PARTNER UNITS
                                  AND I AM A RESIDENT OF:

                                  o    ALABAMA,

                                  o    ARIZONA,

                                  o    ARKANSAS,

                                  o    CALIFORNIA,

                                  o    INDIANA,

                                  o    IOWA,

                                  o    KANSAS,

                                  o    KENTUCKY,

                                  o    MAINE,

                                  o    MASSACHUSETTS,

                                  o    MICHIGAN,

                                  o    MINNESOTA,

                                  o    MISSISSIPPI,

                                  o    MISSOURI,

                                  o    NEW HAMPSHIRE,

                                  o    NEW JERSEY,

                                  o    NEW MEXICO,

                                  o    NORTH CAROLINA,

                                  o    OHIO,

                                  o    OKLAHOMA,

                                  o    OREGON,

                                  o    PENNSYLVANIA,

                                  o    SOUTH DAKOTA,

                                  o    TENNESSEE,

                                  o    TEXAS,

                                  o    VERMONT OR

                                  o    WASHINGTON,

                                  THEN I REPRESENT THAT I AM AWARE OF AND MEET
                                  THAT STATE'S QUALIFICATIONS AND SUITABILITY
                                  STANDARDS SET FORTH IN EXHIBIT (B) TO THE
                                  PROSPECTUS.

_____        _____           (e)  If I am a fiduciary, then I am purchasing for
                                  a person or entity having the appropriate
                                  income and/or net worth specified in (a), (b),
                                  (c) or (d) above.

THE ABOVE REPRESENTATIONS DO NOT CONSTITUTE A WAIVER OF ANY RIGHTS THAT I MAY
HAVE UNDER THE ACTS ADMINISTERED BY THE SEC OR BY ANY STATE REGULATORY AGENCY
ADMINISTERING STATUTES BEARING ON THE SALE OF SECURITIES.

Pennsylvania Income Tax Election
Unless you elect to opt out by checking the box below, the Partnership will file
an annual Pennsylvania income tax return on your behalf and withhold and pay
Pennsylvania income taxes from your share of its distributions.

     / /   I elect to opt out of the Partnership filing and paying Pennsylvania
           income taxes on my behalf because I will have Pennsylvania income
           from sources other than the Partnereship.

                                       5
INSTRUCTIONS TO INVESTOR

You are required to execute your own Subscription Agreement and the Managing
General Partner will not accept any Subscription Agreement that has been
executed by someone other than you unless the person has been given your legal
power of attorney to sign on your behalf, and you meet all of the conditions in
the Prospectus and this Subscription Agreement. In the case of sales to
fiduciary accounts, the minimum standards set forth in the Prospectus and this
Subscription Agreement must be met by the beneficiary, the fiduciary account, or
by the donor or grantor who directly or indirectly supplies the funds to
purchase the Partnership Units if the donor or grantor is the fiduciary.

Your execution of the Subscription Agreement constitutes your binding offer to
buy Units in the Partnership. Once you subscribe you may withdraw your
subscription only by providing the Managing General Partner with written notice
of your withdrawal before your subscription is accepted by the Managing General
Partner. The Managing General Partner has the discretion to refuse to accept
your subscription without liability to you. Subscriptions will be accepted or
rejected by the Partnership within 30 days of their receipt. If your
subscription is rejected, then all of your funds will be returned to you
immediately. If your subscription is accepted before the first closing, then you
will be admitted as a Participant not later than 15 days after the release from
escrow of the investors' funds to the Partnership. If your subscription is
accepted after the first closing, then you will be admitted into the Partnership
not later than the last day of the calendar month in which your subscription was
accepted by the Partnership.

The Managing General Partner will not complete a sale of Units to you and send
you a confirmation of purchase until at least five business days after the date
you receive a final Prospectus.

NOTICE TO CALIFORNIA RESIDENTS: This offering deviates in certain respects from
various requirements of Title 10 of the California Administrative Code. These
deviations include, but are not limited to the following: the definition of
Prospect in the Prospectus, unlike Rule 260.140.127.2(b) and Rule
260.140.121(1), does not require enlarging or contracting the size of the area
on the basis of geological data in all cases. If I am a resident of California,
I acknowledge the receipt of California Rule 260.141.11 set forth in Exhibit (B)
to the Prospectus.

                                       6
SECTION D

                        TO BE COMPLETED BY ALL INVESTORS

     TAXPAYER IDENTIFICATION NUMBER CERTIFICATION - CHECK THE FIRST BOX BELOW,
     UNLESS YOU ARE A FOREIGN INVESTOR OR YOU ARE INVESTING AS A U.S. GRANTOR
     TRUST.

     NOTE: IF THERE IS A CHANGE IN CIRCUMSTANCES WHICH MAKES ANY OF THE
     INFORMATION PROVIDED BY YOU IN YOUR CERTIFICATION BELOW INCORRECT, THEN YOU
     ARE UNDER A CONTINUING OBLIGATION SO LONG AS YOU OWN UNITS IN THE
     PARTNERSHIP TO NOTIFY THE PARTNERSHIP AND FURNISH THE PARTNERSHIP A NEW
     CERTIFICATE WITHIN THIRTY (30) DAYS OF THE CHANGE.

     [_]  UNDER PENALTIES OF PERJURY, I CERTIFY THAT:

          (1)  THE NUMBER PROVIDED IN MY SUBSCRIPTION AGREEMENT IS MY CORRECT
               "TIN" (I.E., SOCIAL SECURITY NUMBER OR EMPLOYER IDENTIFICATION
               NUMBER);

          (2)  I AM NOT SUBJECT TO BACKUP WITHHOLDING BECAUSE (a) I AM EXEMPT
               FROM BACKUP WITHHOLDING UNDER Section 3406(g)(1) OF THE INTERNAL
               REVENUE CODE AND THE RELATED REGULATIONS, OR (B) I HAVE NOT BEEN
               NOTIFIED BY THE INTERNAL REVENUE SERVICE (IRS) THAT I AM SUBJECT
               TO BACKUP WITHHOLDING AS A RESULT OF FAILURE TO REPORT ALL
               INTEREST OR DIVIDENDS, OR (C) THE IRS HAS NOTIFIED ME THAT I AM
               NO LONGER SUBJECT TO BACKUP WITHHOLDING; AND

          (3)  I AM A U.S. PERSON (WHICH INCLUDES U.S. CITIZENS, RESIDENT
               ALIENS, ENTITIES OR ASSOCIATIONS FORMED IN THE U.S. OR UNDER U.S.
               LAW, AND U.S. ESTATES AND TRUSTS.)

     (NOTE: YOU MUST CROSS OUT ITEM 2 ABOVE IF YOU HAVE BEEN NOTIFIED BY THE IRS
     THAT YOU ARE CURRENTLY SUBJECT TO BACKUP WITHHOLDING BECAUSE YOU HAVE
     FAILED TO REPORT ALL INTEREST AND DIVIDENDS ON YOUR TAX RETURN.)

          [_]  FOREIGN PARTNER. I AM AT LEAST 21 YEARS OF AGE, AND I HAVE
               PROVIDED THE PARTNERSHIP WITH THE APPROPRIATE FORM W-8
               CERTIFICATION OR, IF A JOINT ACCOUNT, EACH JOINT ACCOUNT OWNER
               HAS PROVIDED THE PARTNERSHIP THE APPROPRIATE FORM W-8
               CERTIFICATION, AND IF ANY ONE OF THE JOINT ACCOUNT OWNERS HAS NOT
               ESTABLISHED FOREIGN STATUS, THAT JOINT ACCOUNT OWNER HAS PROVIDED
               THE PARTNERSHIP WITH A CERTIFIED TIN.

          [_]  U.S. GRANTOR TRUSTS. UNDER PENALTIES OF PERJURY, I CERTIFY THAT:

               (1)  THE TRUST DESIGNATED AS THE INVESTOR ON THE SUBSCRIPTION
                    AGREEMENT IS A UNITED STATES GRANTOR TRUST WHICH I CAN AMEND
                    OR REVOKE DURING MY LIFETIME;

               (2)  UNDER SUBPART E OF SUBCHAPTER J OF THE INTERNAL REVENUE CODE
                    (CHECK ONLY ONE OF THE BOXES BELOW):

                    [_]  (A) 100% OF THE TRUST IS TREATED AS OWNED BY ME;

                    [_]  (B) THE TRUST IS TREATED AS OWNED IN EQUAL SHARES BY ME
                             AND MY SPOUSE; OR

                    [_]  (C) ____% OF THE TRUST IS TREATED AS OWNED BY
                             ________________________, AND THE REMAINDER IS
                             TREATED AS OWNED _____% BY ME AND _____% BY MY
                             SPOUSE); AND

               (3)  EACH GRANTOR OR OTHER OWNER OF ANY PORTION OF THE TRUST HAS
                    PROVIDED THE PARTNERSHIP WITH THE APPROPRIATE FORM W-8 OR
                    FORM W-9 CERTIFICATION.

     NOTE: IF YOU CHECK THE BOX IN (2)(c), YOU MUST INSERT THE INFORMATION
     CALLED FOR BY THE BLANKS.

     THE INTERNAL REVENUE SERVICE DOES NOT REQUIRE YOUR CONSENT TO ANY PROVISION
     OF THIS DOCUMENT OTHER THAN THE CERTIFICATIONS REQUIRED TO AVOID BACKUP
     WITHHOLDING.

                                        7
ATLAS AMERICA SERIES 27-2006 L.P.
                     DISTRIBUTIONS NOT TO ADDRESS OF RECORD

      PLEASE COMPLETE THIS FORM TO REQUEST ELECTRONIC OR ALTERNATE MAILING
                                  DISTRIBUTION

INVESTOR INFORMATION:

NAME _________________________________________ SOCIAL SECURITY NO.: ____________

================================================================================

                 ALTERNATE ADDRESS -- ELECTRONIC DEPOSIT OPTION
                    (ACH TRANSACTIONS ONLY, NOT FOR WIRE USE)

NAME OF FINANCIAL INSTITUTION: _________________________________________________

ABA NUMBER: _____________________________ ACCOUNT NUMBER: ______________________

NAME ON ACCOUNT ________________________________________________________________

TYPE OF ACCOUNT:           [_]   CHECKING/BROKER             [_]  SAVINGS

================================================================================

   ALTERNATE MAILING INSTRUCTIONS FOR DISTRIBUTIONS TO FINANCIAL INSTITUTIONS
                              (NEED ACCOUNT NUMBER)

PAYEE (NAME FOR CHECK TO BE MADE OUT TO): ______________________________________

________________________________________________________________________________

STREET OR POST OFFICE BOX NUMBER: ______________________________________________
CITY, STATE, ZIP CODE __________________________________________________________
FOR THE BENEFIT OF (NAME): _____________________________________________________
ACCOUNT NUMBER: ________________________________________________________________

================================================================================

            ALTERNATE MAILING ADDRESS OTHER THAN TO ADDRESS OF RECORD

    NO ACCOUNT NUMBER (P.O. BOX // ALTERNATE ADDRESS // DO NOT USE ADDRESS OF
                                     RECORD)

NAME: __________________________________________________________________________

ADDRESS: _______________________________________________________________________

CITY, STATE, ZIP CODE: _________________________________________________________

================================================================================

INVESTOR'S SIGNATURE: __________________________________________________________
PRINT INVESTOR'S NAME: _________________________________________________________

================================================================================

OFFICE USE ONLY:
   DATE RECEIVED: ______ DATE ENTERED: ______ INITIALS _____ ATLAS ID. NO. _____

ATLAS RESOURCES, LLC, MGP, 311 Rouser Road, Moon Township, PA 15108, PHONE:
1-800-251-0171 FAX: 412-262-7430

                                        8
EXHIBIT (II)

                                     FORM OF

                        DRILLING AND OPERATING AGREEMENT

                                       FOR

                      ATLAS AMERICA PUBLIC #16-2007(A) L.P.

                     [ATLAS AMERICA PUBLIC #16-2007(B) L.P.]
INDEX

SECTION                                                                     PAGE
                                                                            ----

1.   Assignment of Well Locations; Representations and Indemnification
     Associated with the Assignment of the Lease; Designation of
     Additional Well Locations; Outside Activities Are Not Restricted....     1
2.   Drilling of Wells; Timing; Depth; Interest of Developer; Right to
     Substitute Well Locations...........................................     2
3.   Operator - Responsibilities in General; Covenants; Term.............     3
4.   Operator's Charges for Drilling and Completing Wells; Payment;
     Completion Determination; Dry Hole Determination; Excess Funds and
     Cost Overruns - Intangible Drilling Costs; Excess Funds and Cost
     Overruns - Tangible Costs...........................................     5
5.   Title Examination of Well Locations; Developer's Acceptance and
     Liability; Additional Well Locations................................     8
6.   Operations Subsequent to Completion of the Wells; Fee Adjustments;
     Extraordinary Costs; Pipelines; Price Determinations; Plugging and
     Abandonment.........................................................     8
7.   Billing and Payment Procedure with Respect to Operation of Wells;
     Disbursements; Separate Account for Sale Proceeds; Records and
     Reports; Additional Information.....................................    10
8.   Operator's Lien; Right to Collect From Oil or Gas Purchaser.........    12
9.   Successors and Assigns; Transfers; Appointment of Agent.............    12
10.  Operator's Insurance; Subcontractors' Insurance; Operator's
     Liability...........................................................    14
11.  Internal Revenue Code Election; Relationship of Parties; Right to
     Take Production in Kind.............................................    14
12.  Effect of Force Majeure; Definition of Force Majeure; Limitation....    15
13.  Term................................................................    16
14.  Governing Law; Invalidity...........................................    16
15.  Integration; Written Amendment......................................    16
16.  Waiver of Default or Breach.........................................    16
17.  Notices.............................................................    16
18.  Interpretation......................................................    17
19.  Counterparts........................................................    17
     Signature Page......................................................    17

     Exhibit A                 Description of Leases and Initial Well Locations
     Exhibits A-l through A-_  Maps of Initial Well Locations
     Exhibit B                 Form of Assignment
     Exhibit C                 Form of Addendum
DRILLING AND OPERATING AGREEMENT

THIS AGREEMENT made this ______ day of _______________, 200____, by and between
ATLAS RESOURCES, LLC, a Pennsylvania limited liability company (hereinafter
referred to as "Atlas" or "Operator"),

                                       and

ATLAS AMERICA PUBLIC #16-2007(A) L.P. [Atlas America Public #16-2007(B) L.P.], a
Delaware limited partnership, (hereinafter referred to as the "Developer").

                                WITNESSETH THAT:

WHEREAS, the Operator, by virtue of the Oil and Gas Leases (the "Leases")
described on Exhibit A attached to and made a part of this Agreement, has
certain rights to develop the ____________ (______) initial well locations (the
"Initial Well Locations") identified on the maps attached to and made a part of
this Agreement as Exhibits A-l through A-______;

WHEREAS, the Developer, subject to the terms and conditions of this Agreement,
desires to acquire certain of the Operator's rights to develop the Initial Well
Locations and to provide for the development on the terms and conditions set
forth in this Agreement of additional well locations ("Additional Well
Locations") that the parties may from time to time designate; and

WHEREAS, the Operator is in the oil and gas exploration and development
business, and the Developer desires that Operator, as its independent
contractor, perform certain services in connection with its efforts to develop
the aforesaid Initial and Additional Well Locations (collectively the "Well
Locations") and to operate the wells completed on the Well Locations, on the
terms and conditions set forth in this Agreement;

NOW THEREFORE, in consideration of the mutual covenants herein contained and
subject to the terms and conditions hereinafter set forth, the parties hereto,
intending to be legally bound, hereby agree as follows:

1.   ASSIGNMENT OF WELL LOCATIONS; REPRESENTATIONS AND INDEMNIFICATION
     ASSOCIATED WITH THE ASSIGNMENT OF THE LEASE; DESIGNATION OF ADDITIONAL WELL
     LOCATIONS; OUTSIDE ACTIVITIES ARE NOT RESTRICTED.

     (a)  ASSIGNMENT OF WELL LOCATIONS. The Operator shall execute an assignment
          of an undivided percentage of Working Interest in the Well Location
          acreage for each well to the Developer as shown on Exhibit A attached
          hereto, which assignment shall be limited to a depth from the surface
          to the deepest depth penetrated at the cessation of drilling
          operations.

          The assignment shall be substantially in the form of Exhibit B
          attached to and made a part of this Agreement. The amount of acreage
          included in each Initial Well Location and the configuration of the
          Initial Well Location are indicated on the maps attached to this
          Agreement as Exhibits A-l through A-______. The amount of acreage
          included in each Additional Well Location and the configuration of the
          Additional Well Location shall be indicated on the maps to be attached
          as exhibits to the applicable addendum to this Agreement as provided
          in sub-section (c) below.

     (b)  REPRESENTATIONS AND INDEMNIFICATION ASSOCIATED WITH THE ASSIGNMENT OF
          THE LEASE. The Operator represents and warrants to the Developer that:

          (i)  the Operator is the lawful owner of the Lease and rights and
               interest under the Lease and of the personal property on the
               Lease or used in connection with the Lease;

          (ii) the Operator has good right and authority to sell and convey the
               rights, interest, and property;

          (iii) the rights, interest, and property are free and clear from all
               liens and encumbrances; and

          (iv) all rentals and royalties due and payable under the Lease have
               been duly paid.

                                       1
These representations and warranties shall also be included in each
          recorded assignment of the acreage included in each Initial Well
          Location and Additional Well Location designated pursuant to
          sub-section (c) below, substantially in the form of Exhibit B attached
          to and made a part of this Agreement.

          The Operator agrees to indemnify, protect and hold the Developer and
          its successors and assigns harmless from and against all costs
          (including but not limited to reasonable attorneys' fees),
          liabilities, claims, penalties, losses, suits, actions, causes of
          action, judgments or decrees resulting from the breach of any of the
          above representations and warranties. It is understood and agreed
          that, except as specifically set forth above, the Operator makes no
          warranty or representation, express or implied, as to its title or the
          title of the lessors in and to the lands or oil and gas interests
          covered by said Leases.

     (c)  DESIGNATION OF ADDITIONAL WELL LOCATIONS. If the parties hereto desire
          to designate Additional Well Locations to be developed in accordance
          with the terms and conditions of this Agreement, then the parties
          shall execute an addendum substantially in the form of Exhibit C
          attached to and made a part of this Agreement specifying:

          (i)  the undivided percentage of Working Interest and the Oil and Gas
               Leases to be included as Leases under this Agreement;

          (ii) the amount and configuration of acreage included in each
               Additional Well Location on maps attached as exhibits to the
               addendum; and

          (iii) their agreement that the Additional Well Locations shall be
               developed in accordance with the terms and conditions of this
               Agreement.

     (d)  OUTSIDE ACTIVITIES ARE NOT RESTRICTED. It is understood and agreed
          that the assignment of rights under the Leases and the oil and gas
          development activities contemplated by this Agreement relate only to
          the Initial Well Locations and the Additional Well Locations. Nothing
          contained in this Agreement shall be interpreted to restrict in any
          manner the right of each of the parties to conduct without the
          participation of the other party any additional activities relating to
          exploration, development, drilling, production, or delivery of oil and
          gas on lands adjacent to or in the immediate vicinity of the Well
          Locations or elsewhere.

2.   DRILLING OF WELLS; TIMING; DEPTH; INTEREST OF DEVELOPER; RIGHT TO
     SUBSTITUTE WELL LOCATIONS.

     (a)  DRILLING OF WELLS. Operator, as Developer's independent contractor,
          agrees to drill, complete (or plug) and operate ____________ (_____)
          oil and gas wells on the ____________ (______) Initial Well Locations
          in accordance with the terms and conditions of this Agreement.
          Developer, as a minimum commitment, agrees to participate in and pay
          the Operator's charges for drilling and completing (or plugging) the
          wells and any extra costs pursuant to Section 4 in proportion to the
          share of the Working Interest owned by the Developer in the wells with
          respect to all initial wells. It is understood and agreed that,
          subject to sub-section (e) below, Developer does not reserve the right
          to decline participation in the drilling of any of the initial wells
          to be drilled under this Agreement.

     (b)  TIMING. Operator shall begin drilling the first well within thirty
          (30) days after the date of this Agreement, and shall begin drilling
          each of the other initial wells for which payment is made pursuant to
          Section 4(b) before the close of the 90th day after the close of the
          calendar year in which this Agreement is entered into by Operator and
          the Developer. Subject to the foregoing time limits, Operator shall
          determine the timing of and the order of drilling the Initial Well
          Locations.

     (c)  DEPTH. All of the wells to be drilled under this Agreement shall be:

          (i)  drilled and completed (or plugged) in accordance with the
               generally accepted and customary oil and gas field practices and
               techniques then prevailing in the geographical area of the Well
               Locations; and

                                       2
(ii) drilled to a depth sufficient to test thoroughly the objective
               formation or the deepest assigned depth, whichever is less.

     (d)  INTEREST OF DEVELOPER. Except as otherwise provided in this Agreement,
          all costs, expenses, and liabilities incurred in connection with the
          drilling and other operations and activities contemplated by this
          Agreement shall be borne and paid, and all wells, gathering lines of
          up to approximately 2,500 feet on each Well Location in connection
          with a natural gas well, equipment, materials, and facilities
          acquired, constructed or installed under this Agreement shall be
          owned, by the Developer in proportion to the share of the Working
          Interest owned by the Developer in the wells. Subject to the payment
          of lessor's royalties and other royalties and overriding royalties, if
          any, production of oil and gas from the wells to be drilled under this
          Agreement shall be owned by the Developer in proportion to the share
          of the Working Interest owned by the Developer in the wells.

     (e)  RIGHT TO SUBSTITUTE WELL LOCATIONS. Notwithstanding the provisions of
          sub-section (a) above, if the Operator or Developer determines in good
          faith, with respect to any Well Location, before operations begin
          under this Agreement on the Well Location, that it would not be in the
          best interest of the parties to drill a well on the Well Location,
          then the party making the determination shall notify the other party
          of its determination and the basis for its determination and, unless
          otherwise instructed by Developer, the well shall not be drilled. This
          determination may be based on:

          (i)   the production or failure of production of any other wells that
                may have been recently drilled in the immediate area of the Well
                Location;

          (ii)  newly discovered title defects; or

          (iii) any other evidence with respect to the Well Location as may have
                been obtained.

          If the well is not drilled, then Operator shall promptly propose a new
          well location (including all information for the Well Location as
          Developer may reasonably request) to be substituted for the original
          Well Location. Developer shall then have seven (7) business days to
          either reject or accept the proposed new well location. If the new
          well location is rejected, then Operator shall promptly propose
          another substitute well location pursuant to the provisions of this
          sub-section.

          Once the Developer accepts a substitute well location or does not
          reject it within the seven (7) day period, this Agreement shall
          terminate as to the original Well Location and the substitute well
          location shall become subject to the terms and conditions of this
          Agreement.

3.   OPERATOR - RESPONSIBILITIES IN GENERAL; COVENANTS; TERM.

     (a)  OPERATOR - RESPONSIBILITIES IN GENERAL. Atlas shall be the Operator of
          the wells and Well Locations subject to this Agreement and, as the
          Developer's independent contractor, shall, in addition to its other
          obligations under this Agreement do the following:

          (i)   arrange for drilling and completing (or plugging) the wells and,
                if a gas well, installing the necessary gas gathering line
                systems and connection facilities;

          (ii)  make the technical decisions required in drilling, testing,
                completing (or plugging), and operating the wells;

          (iii) manage and conduct all field operations in connection with the
                drilling, testing, completing (or plugging), equipping,
                operating, and producing the wells;

          (iv)  maintain all wells, equipment, gathering lines if a gas well,
                and facilities in good working order during their useful lives;
                and

                                       3
(v)  perform the necessary administrative and accounting functions.

          In performing the work contemplated by this Agreement, Operator is an
          independent contractor with authority to control and direct the
          performance of the details of the work.

     (b)  COVENANTS. Operator covenants and agrees that under this Agreement:

          (i)   it shall perform and carry on (or cause to be performed and
                carried on) its duties and obligations in a good, prudent,
                diligent, and workmanlike manner using technically sound,
                acceptable oil and gas field practices then prevailing in the
                geographical area of the Well Locations;

          (ii)  all drilling and other operations conducted by, for and under
                the control of Operator shall conform in all respects to
                federal, state and local laws, statutes, ordinances,
                regulations, and requirements;

          (iii) unless otherwise agreed in writing by the Developer, all work
                performed pursuant to a written estimate shall conform to the
                technical specifications set forth in the written estimate and
                all equipment and materials installed or incorporated in the
                wells and facilities shall be new or used and of good quality;

          (iv)  in the course of conducting operations, it shall comply with all
                terms and conditions, other than any minimum drilling
                commitments, of the Leases (and any related assignments,
                amendments, subleases, modifications and supplements);

          (v)   it shall keep the Well Locations and all wells, equipment and
                facilities located on the Well Locations free and clear of all
                labor, materials and other types of liens or encumbrances
                arising out of operations;

          (vi)  it shall file all reports and obtain all permits and bonds
                required to be filed with or obtained from any governmental
                authority or agency in connection with the drilling or other
                operations and activities; and

          (vii) it will provide competent and experienced personnel to supervise
                drilling, completing (or plugging), and operating the wells and
                use the services of competent and experienced service companies
                to provide any third party services necessary or appropriate in
                order to perform its duties.

     (c)  TERM. Atlas shall serve as Operator under this Agreement until the
          earliest of:

          (i)   the termination of this Agreement pursuant to Section 13;

          (ii)  the termination of Atlas as Operator by the Developer at any
                time in the Developer's discretion, with or without cause on
                sixty (60) days' advance written notice to the Operator; or

          (iii) the resignation of Atlas as Operator under this Agreement which
                may occur on ninety (90) days' written notice to the Developer
                at any time after five (5) years from the date of this
                Agreement, it being expressly understood and agreed that Atlas
                shall have no right to resign as Operator before the expiration
                of the five-year period.

          Any successor Operator shall be selected by the Developer. Nothing
          contained in this sub-section shall relieve or release Atlas or the
          Developer from any liability or obligation under this Agreement that
          accrued or occurred before Atlas' removal or resignation as Operator
          under this Agreement. On any change in Operator under this provision,
          the then present Operator shall deliver to the successor Operator
          possession of all records, equipment, materials and appurtenances used
          or obtained for use in connection with operations under this Agreement
          and owned by the Developer.

                                       4
4.   OPERATOR'S CHARGES FOR DRILLING AND COMPLETING WELLS; PAYMENT; COMPLETION
     DETERMINATION; DRY HOLE DETERMINATION; EXCESS FUNDS AND COST
     OVERRUNS-INTANGIBLE DRILLING COSTS; EXCESS FUNDS AND COST OVERRUNS-TANGIBLE
     COSTS.

     (a)  OPERATOR'S CHARGES FOR DRILLING AND COMPLETING WELLS. Each oil and gas
          well that is drilled and completed under this Agreement shall be
          drilled and completed for an amount equal to the sum of the following
          items: (i) the Cost of permits, supplies, materials, equipment, and
          all other items used in the drilling and completion of a well provided
          by third-parties, or if the foregoing items are provided by Affiliates
          of the Developer's Managing General Partner, then those items shall be
          charged at competitive rates; (ii) fees for third-party services;
          (iii) fees for services provided by the Developer's Managing General
          Partner's Affiliates, which shall be charged at competitive rates;
          (iv) an administration and oversight fee of $15,000 per well, which
          shall be charged to the Developer's investors as part of each well's
          Intangible Drilling Costs, as that term is defined below and the
          portion of Tangible Costs, as that term is defined below, paid by the
          Developer's investors; and (v) a mark-up in an amount equal to 15% of
          the sum of (i), (ii), (iii) and (iv), above, for the Developer's
          Managing General Partner's services as general drilling contractor as
          Operator under this Agreement. "Cost" shall mean the price paid by
          Operator in an arm's-length transaction.

          The estimated price for drilling and completing each of the wells
          shall be set forth in an Authority for Expenditure ("AFE") that shall
          be attached to this Agreement as an Exhibit, and shall cover all
          ordinary costs which may be incurred in drilling and completing (or
          plugging) each well. This includes without limitation, site
          preparation, permits and bonds, roadways, surface damages, power at
          the site, water, Operator's compensation as set forth above,
          rights-of-way, drilling rigs, equipment and materials, costs of title
          examinations, logging, cementing, fracturing, casing, meters (other
          than utility purchase meters), connection facilities, salt water
          collection tanks, separators, siphon string, rabbit, tubing, an
          average of 2,500 feet of gathering line per well in connection with
          each gas well, and geological, geophysical and engineering services.

     (b)  PAYMENT. The Developer shall pay to Operator, in proportion to the
          share of the Working Interest owned by the Developer in the wells, one
          hundred percent (100%) of the estimated Intangible Drilling Costs and
          Tangible Costs, as those terms are defined below, for drilling and
          completing all initial wells on execution of this Agreement.
          Notwithstanding the foregoing, Atlas' payments for its share of the
          estimated Tangible Costs, as that term is defined below, of drilling
          and completing all initial wells as the Managing General Partner of
          the Developer shall be paid within five (5) business days of notice
          from Operator that the costs have been incurred. The Developer's
          payment shall be nonrefundable in all events in order to enable
          Operator to do the following:

          (i)   commence site preparation for the initial wells;

          (ii)  obtain suitable subcontractors for drilling and completing or
                plugging the initial wells at currently prevailing prices; and

          (iii) insure the availability of equipment and materials.

          For purposes of this Agreement, "Intangible Drilling Costs" shall mean
          those expenditures associated with property acquisition and the
          drilling and completion of oil and gas wells that under present law
          are generally accepted as fully deductible currently for federal
          income tax purposes. This includes:

          (i)  all expenditures made with respect to any well before the
               establishment of production in commercial quantities for wages,
               fuel, repairs, hauling, supplies and other costs and expenses
               incident to and necessary for the drilling of the well and the
               preparation of the well for the production of oil or gas, that
               are currently deductible pursuant to Section 263(c) of the
               Internal Revenue Code of 1986, as amended (the "Code"), and
               Treasury Reg. Section 1.612-4, which are generally termed
               "intangible drilling and development costs";

                                       5
(ii)  the expense of plugging and abandoning any well before a
                completion attempt; and

          (iii) the costs (other than Tangible Costs and Lease acquisition
                costs) to re-enter and deepen an existing well, complete the
                well to deeper formations or reservoirs, or plug and abandon the
                well if it is nonproductive from the targeted deeper formations
                or reservoirs.

          "Tangible Costs" shall mean those costs associated with property
          acquisition and the drilling and completion of oil and gas wells that
          are generally accepted as capital expenditures pursuant to the
          provisions of the Code. This includes:

          (i)   all costs of equipment, parts and items of hardware used in
                drilling and completing (or plugging) a well;

          (ii)  the costs (other than Intangible Drilling Costs and Lease
                acquisition costs) to re-enter and deepen an existing well,
                complete the well to deeper formations or reservoirs, or plug
                and abandon the well if it is nonproductive from the targeted
                deeper formations or reservoirs; and

          (iii) those items necessary to deliver acceptable oil and gas
                production to purchasers to the extent installed downstream from
                the wellhead of any well, which are required to be capitalized
                under the Code and its regulations.

          With respect to each additional well drilled on the Additional Well
          Locations, if any, the Developer shall pay to Operator, in proportion
          to the share of the Working Interest owned by the Developer in the
          wells, one hundred percent (100%) of the estimated Intangible Drilling
          Costs and Tangible Costs for drilling and completing the well on
          execution of the applicable addendum pursuant to Section l(c) above.
          Notwithstanding the foregoing, Atlas' payments for its share of the
          estimated Tangible Costs of drilling and completing all additional
          wells as the Managing General Partner of the Developer shall be paid
          within five (5) business days of notice from Operator that the costs
          have been incurred. The Developer's payment shall be nonrefundable in
          all events in order to enable Operator to do the following:

          (i)   commence site preparation for the additional wells;

          (ii)  obtain suitable subcontractors for drilling and completing the
                additional wells at currently prevailing prices; and

          (iii) insure the availability of equipment and materials.

          Developer shall pay, in proportion to the share of the Working
          Interest owned by the Developer in the wells, any extra costs incurred
          for each well pursuant to sub-section (a) above within ten (10)
          business days of its receipt of Operator's statement for the extra
          costs.

     (c)  COMPLETION DETERMINATION. Operator shall determine whether or not to
          run the production casing for an attempted completion or to plug and
          abandon any well drilled under this Agreement. However, a well shall
          be completed only if Operator has made a good faith determination that
          there is a reasonable possibility of obtaining commercial quantities
          of oil and/or gas.

     (d)  DRY HOLE DETERMINATION. If Operator determines at any time during the
          drilling or attempted completion of any well drilled under this
          Agreement, in accordance with the generally accepted and customary oil
          and gas field practices and techniques then prevailing in the
          geographic area of the Well Location that the well should not be
          completed, then it shall promptly and properly plug and abandon the
          well.

     (e)  EXCESS FUNDS AND COST OVERRUNS-INTANGIBLE DRILLING COSTS. Any
          estimated Intangible Drilling Costs (which are the Intangible Drilling
          Costs set forth on the AFE) prepaid by Developer with respect to any
          well that exceed Operator's price specified in sub-section (a) above
          for the Intangible Drilling Costs of the

                                       6
well shall be retained by Operator and shall be applied, in proportion
          to the share of the Working Interest owned by the Developer in the
          wells, to:

          (i)  the Intangible Drilling Costs of an additional well or wells to
               be drilled on the Additional Well Locations; or

          (ii) any cost overruns owed by the Developer to Operator for
               Intangible Drilling Costs on one or more of the other wells on
               the Well Locations.

          Conversely, if Operator's price specified in sub-section (a) above for
          the Intangible Drilling Costs of any well exceeds the estimated
          Intangible Drilling Costs (which are the Intangible Drilling Costs set
          forth on the AFE) prepaid by Developer for the well, then:

          (i)  Developer shall pay the additional price to Operator within ten
               (10) business days after notice from Operator that the additional
               amount is due and owing; or

          (ii) Developer and Operator may agree to delete or reduce Developer's
               Working Interest in one or more wells to be drilled under this
               Agreement that have not yet been spudded to provide funds to pay
               the additional amounts owed by Developer to Operator. If doing so
               results in any excess prepaid Intangible Drilling Costs, then
               these funds shall be applied, in proportion to the share of the
               Working Interest owned by the Developer in the wells, to:

               (a)  the Intangible Drilling Costs of an additional well or wells
                    to be drilled on the Additional Well Locations; or

               (b)  any cost overruns owed by the Developer to Operator for
                    Intangible Drilling Costs of one or more of the other wells
                    on the Well Locations.

          The Exhibits to this Agreement with respect to the affected wells
          shall be amended as appropriate.

     (f)  EXCESS FUNDS AND COST OVERRUNS - TANGIBLE COSTS. Any estimated
          Tangible Costs (which are the Tangible Costs set forth on the AFE)
          prepaid by Developer with respect to any well that exceed Operator's
          price specified in sub-section (a) above for the Tangible Costs of the
          well shall be retained by Operator and shall be applied, in proportion
          to the share of the Working Interest owned by the Developer in the
          wells, to:

          (i)  the Developer's Participants' share of the Tangible Costs for an
               additional well or wells to be drilled on the Additional Well
               Locations; or

          (ii) any cost overruns owed by the Developer to Operator for the
               Developer's Participants' share of the Tangible Costs of one or
               more of the other wells on the Well Locations.

          Conversely, if Operator's price specified in sub-section (a) above for
          the Developer's Participants' share of Tangible Costs of any well
          exceeds the estimated Tangible Costs (which are the Tangible Costs set
          forth on the AFE) prepaid by Developer for the Developer's
          Participants' share of the Tangible Costs for the well, then:

          (i)   Developer shall pay the additional price to Operator within ten
                (10) business days after notice from Operator that the
                additional price is due and owing; or

          (ii)  Developer and Operator may agree to delete or reduce Developer's
                Working Interest in one or more wells to be drilled under this
                Agreement that have not yet been spudded to provide funds to pay
                the additional amounts owed by Developer to Operator. If doing
                so results in any excess prepaid Tangible Costs, then these
                funds shall be applied, in proportion to the share of the
                Working Interest owed by the Developer in the wells, to:

                                       7
(a)  the Developer's Participants' share of the Tangible Costs of
                    an additional well or wells to be drilled on the Additional
                    Well Locations; or

               (b)  any cost overruns owed by the Developer to Operator for the
                    Developer's Participants' share of the Tangible Costs of one
                    or more of the other wells on the Well Locations.

          (iii) The Developer's Participants' share of the Tangible Costs of all
                of the wells drilled under this Agreement and any additional
                wells to be drilled on the Additional Well Locations under any
                Addendum to this Agreement shall be ten percent (10%) of the
                total price prepaid by Developer to Operator pursuant to Section
                4(b) of this Agreement or any Addendum hereto. The Developer's
                Participants' share of the Tangible Costs of any one well
                drilled under this Agreement shall be determined subject to the
                preceding sentence, taking into account the Developer's share of
                all of the Tangible Costs of all of the wells to be drilled
                under this Agreement and any Addendum hereto.

          The Exhibits to this Agreement with respect to the affected wells
          shall be amended as appropriate.

5.   TITLE EXAMINATION OF WELL LOCATIONS, DEVELOPER'S ACCEPTANCE AND LIABILITY;
     ADDITIONAL WELL LOCATIONS.

     (a)  TITLE EXAMINATION OF WELL LOCATIONS, DEVELOPER'S ACCEPTANCE AND
          LIABILITY. The Developer acknowledges that Operator has furnished
          Developer with the title opinions identified on Exhibit A, and other
          documents and information that Developer or its counsel has requested
          in order to determine the adequacy of the title to the Initial Well
          Locations and leased premises subject to this Agreement. The Developer
          accepts the title to the Initial Well Locations and leased premises
          and acknowledges and agrees that, except for any loss, expense, cost,
          or liability caused by the breach of any of the warranties and
          representations made by the Operator in Section l(b), any loss,
          expense, cost or liability whatsoever caused by or related to any
          defect or failure of the title shall be the sole responsibility of and
          shall be borne entirely by the Developer.

     (b)  ADDITIONAL WELL LOCATIONS. Before beginning drilling of any well on
          any Additional Well Location, Operator shall conduct, or cause to be
          conducted, a title examination of the Additional Well Location, in
          order to obtain appropriate abstracts, opinions and certificates and
          other information necessary to determine the adequacy of title to both
          the applicable Lease and the fee title of the lessor to the premises
          covered by the Lease. The results of the title examination and such
          other information as is necessary to determine the adequacy of title
          for drilling purposes shall be submitted to the Developer for its
          review and acceptance. No drilling on the Additional Well Locations
          shall begin until the title has been accepted in writing by the
          Developer. After any title has been accepted by the Developer, any
          loss, expense, cost, or liability whatsoever, caused by or related to
          any defect or failure of the title shall be the sole responsibility of
          and shall be borne entirely by the Developer, unless such loss,
          expense, cost, or liability was caused by the breach of any of the
          warranties and representations made by the Operator in Section l(b).

6.   OPERATIONS SUBSEQUENT TO COMPLETION OF THE WELLS; FEE ADJUSTMENTS;
     EXTRAORDINARY COSTS; PIPELINES; PRICE DETERMINATIONS; PLUGGING AND
     ABANDONMENT.

     (a)  OPERATIONS SUBSEQUENT TO COMPLETION OF THE WELLS. Beginning with the
          month in which a well drilled under this Agreement begins to produce,
          Operator shall be entitled to an operating fee of $362 per month for
          each well being operated under this Agreement, which operating fee
          shall be proportionately reduced, on a well-by-well basis to the
          extent the Developer owns less than 100% of the Working Interest in a
          well. This fee shall be in lieu of any direct charges by Operator for
          its services or the provision by Operator of its equipment for normal
          superintendence and maintenance of the wells and related pipelines and
          facilities.

          The operating fees shall cover all normal, regularly recurring
          operating expenses for the production, delivery and sale of natural
          gas, including without limitation:

                                       8
(i)   well tending, routine maintenance and adjustment;

          (ii)  reading meters, recording production, pumping, maintaining
                appropriate books and records;

          (iii) preparing reports to the Developer and government agencies; and

          (iv)  collecting and disbursing revenues.

          The operating fees shall not cover costs and expenses related to the
          following:

          (i)   the production and sale of oil;

          (ii)  the collection and disposal of salt water or other liquids
                produced by the wells;

          (iii) the rebuilding of access roads; and

          (iv)  the purchase of equipment, materials or third party services;

          which, subject to the provisions of sub-section (c) of this Section 6,
          shall be invoiced by Operator to the Developer on a monthly basis, and
          shall be paid by the Developer within ten (10) business days after
          notice from Operator that the additional amounts are due and owing in
          proportion to the share of the Working Interest owned by the Developer
          in the wells.

          Any well that is temporarily abandoned or shut-in continuously for an
          entire calendar month shall not be considered a producing well for
          purposes of determining the number of wells in the month subject to
          the operating fee.

     (b)  FEE ADJUSTMENTS. The monthly operating fee set forth in sub-section
          (a) above may be adjusted by Operator annually, as of the first day of
          January (the "Adjustment Date") of each year, beginning January 1,
          2008. This adjustment, if any, shall not exceed the percentage
          increase in the average weekly earnings of "Crude Petroleum, Natural
          Gas, and Natural Gas Liquids" workers, as published by the U.S.
          Department of Labor, Bureau of Labor Statistics, and shown in
          Employment and Earnings Publication, Monthly Establishment Data, Hours
          and Earning Statistical Table C-2, Index Average Weekly Earnings of
          "Crude Petroleum, Natural Gas, and Natural Gas Liquids" workers, SIC
          Code #131-2, or any successor index thereto, since January l, 2006, in
          the case of the first adjustment, and since the previous Adjustment
          Date, in the case of each subsequent adjustment.

          In addition, the monthly operating fee set forth in sub-section (a)
          above for any given well or wells being operated under this Agreement
          may be increased beyond the annual adjustment described in the prior
          paragraph without advance notice to the Developer, from time-to-time
          to the competitive rate in the area where the well(s) are situated, as
          determined by the Operator in its sole discretion.

     (c)  EXTRAORDINARY COSTS. Without the prior written consent of the
          Developer, pursuant to a written estimate submitted by Operator,
          Operator shall not undertake any single project or incur any
          extraordinary cost with respect to any well being produced under this
          Agreement that is reasonably estimated to result in an expenditure of
          more than $5,000, unless the project or extraordinary cost is
          necessary for the following:

          (i)  to safeguard persons or property; or

          (ii) to protect the well or related facilities in the event of a
               sudden emergency.

          In no event, however, shall the Developer be required to pay for any
          project or extraordinary cost arising from the negligence or
          misconduct of Operator, its agents, servants, employees,
          subcontractors, licensees, or invitees.

                                       9
All extraordinary costs incurred and the cost of projects undertaken
          under this section with respect to a well being produced under this
          Agreement shall be billed to the Developer at the invoice cost of
          third-party services performed or materials purchased together with a
          reasonable charge by Operator for any services performed directly by
          it, in proportion to the share of the Working Interest owned by the
          Developer in the wells. Operator shall have the right to require the
          Developer to pay in advance all or a portion of the estimated costs of
          a project undertaken under this section, before undertaking the
          project, in proportion to the share of the Working Interest owned by
          the Developer in the well or wells.

     (d)  PIPELINES. Developer shall have no interest in the pipeline gathering
          system, which gathering system shall remain the sole property of
          Operator or its Affiliates and shall be maintained at their sole cost
          and expense.

     (e)  PRICE DETERMINATIONS. Notwithstanding anything in this Agreement to
          the contrary, the Developer shall pay all costs in proportion to the
          share of the Working Interest owned by the Developer in the wells with
          respect to obtaining price determinations under and otherwise
          complying with the Natural Gas Policy Act of 1978 and the implementing
          state regulations. This responsibility shall include, without
          limitation, preparing, filing, and executing all applications,
          affidavits, interim collection notices, reports and other documents
          necessary or appropriate to obtain price certification, to effect
          sales of natural gas, or otherwise to comply with the Act and the
          implementing state regulations.

          Operator agrees to furnish the information and render the assistance
          as the Developer may reasonably request in order to comply with the
          Act and the implementing state regulations without charge for services
          performed by its employees.

     (f)  PLUGGING AND ABANDONMENT. The Developer shall have the right to direct
          Operator to plug and abandon any well that has been completed under
          this Agreement as a producer. In addition, Operator shall not plug and
          abandon any well that has been drilled and completed as a producer
          under this Agreement before obtaining the written consent of the
          Developer. However, if the Operator determines that any well drilled
          and completed under this Agreement as a producer shall be plugged and
          abandoned in accordance with the generally accepted and customary oil
          and gas field practices and techniques then prevailing in the
          geographic area of the well location, and makes a written request to
          the Developer for authority to plug and abandon the well and the
          Developer fails to respond in writing to the request within forty-five
          (45) days following the date of the request, then the Developer shall
          be deemed to have consented to the plugging and abandonment of the
          well.

          All costs and expenses related to plugging and abandoning wells that
          have been drilled and completed under this Agreement as producing
          wells shall be borne and paid by the Developer in proportion to the
          share of the Working Interest owned by the Developer in the wells.
          Also, at any time after one (1) year from the date each well drilled
          and completed under this Agreement is placed into production, Operator
          shall have the right to deduct each month from the proceeds of the
          sale of the production from the well up to $200, in proportion to the
          share of the Working Interest owned by the Developer in the well, for
          the purpose of establishing a fund to cover the Operator's estimate of
          the Developer's share of the costs of eventually plugging and
          abandoning the well. All of these funds shall be deposited by Operator
          in a separate interest bearing escrow account for the account of the
          Developer, and the total amount so retained and deposited shall not
          exceed Operator's reasonable estimate of Developer's share of the
          costs of eventually plugging and abandoning the well.

7.   BILLING AND PAYMENT PROCEDURE WITH RESPECT TO OPERATION OF WELLS;
     DISBURSEMENTS; SEPARATE ACCOUNT FOR SALE PROCEEDS; RECORDS AND REPORTS;
     ADDITIONAL INFORMATION.

     (a)  BILLING AND PAYMENT PROCEDURE WITH RESPECT TO OPERATION OF WELLS.
          Operator shall promptly and timely pay and discharge on behalf of the
          Developer, in proportion to the share of the Working Interest owned by
          the Developer in the wells, the following:

                                       10
(i)  all expenses and liabilities payable and incurred by reason of
               its operation of the wells in accordance with this Agreement,
               such as severance taxes, royalties, overriding royalties,
               operating fees, and pipeline gathering charges; and

          (ii) any third-party invoices received by Operator with respect to the
               Developer's share of the costs and expenses incurred in
               connection with the operation of the wells.

          Operator, however, shall not be required to pay and discharge any of
          the above costs and expenses that are being contested in good faith by
          Operator.

          Operator shall:

          (i)  deduct the foregoing costs and expenses from the Developer's
               share of the proceeds of the oil and/or gas sold from the wells;
               and

          (ii) keep an accurate record of the Developer's account, showing
               expenses incurred and charges and credits made and received with
               respect to each well.

          If the Developer's share of the proceeds of the oil and/or gas sold
          from the wells is insufficient to pay the costs and expenses, then
          Operator shall promptly and timely pay and discharge the costs and
          expenses described above, in proportion to the share of the Working
          Interest owned by the Developer in the wells, and prepare and submit
          an invoice to the Developer each month for those costs and expenses.
          The invoice shall be accompanied by the form of statement specified in
          sub-section (b) below, and shall be paid by the Developer within ten
          (10) business days of its receipt.

     (b)  DISBURSEMENTS. Operator shall disburse to the Developer, on a monthly
          basis, the Developer's share of the proceeds received from the sale of
          oil and/or gas sold from the wells operated under this Agreement,
          less:

          (i)  the amounts charged to the Developer under sub-section (a); and

          (ii) the amount, if any, withheld by Operator for future plugging
               costs pursuant to sub-section (f) of Section 6.

          Each disbursement made and/or invoice submitted to the Developer
          pursuant to sub-section (a) above shall be accompanied by a statement
          from the Operator itemizing with respect to each well:

          (i)   the total production of oil and/or gas since the date of the
                last disbursement or invoice billing period, as the case may be,
                and the Developer's share of the production;

          (ii)  the total proceeds received from any sale of the production, and
                the Developer's share of the proceeds;

          (iii) the costs and expenses deducted from the proceeds and/or being
                billed to the Developer pursuant to sub-section (a) above;

          (iv)  the amount withheld for future plugging costs; and

          (v)   any other information as Developer may reasonably request,
                including without limitation copies of all third-party invoices
                listed on the statement for the period.

     (c)  SEPARATE ACCOUNT FOR SALE PROCEEDS. Operator agrees to deposit all
          proceeds from the sale of oil and/or gas sold from the wells operated
          under this Agreement in a separate checking account maintained by
          Operator. This account shall be used solely for the purpose of
          collecting and disbursing funds constituting proceeds from the sale of
          production under this Agreement.

                                       11
(d)  RECORDS AND REPORTS. In addition to the statements required under
          sub-section (b) above, Operator, within seventy-five (75) days after
          the completion of each well drilled, shall furnish the Developer with
          a detailed statement itemizing with respect to the well the total
          costs and charges under Section 4(a) and the Developer's share of the
          costs and charges, and any other information as is necessary to enable
          the Developer:

          (i)  to allocate any extra costs incurred with respect to the well
               between Tangible Costs and Intangible Drilling Costs; and

          (ii) to determine the amount of the investment tax credit or marginal
               well production tax credit, if applicable.

     (e)  ADDITIONAL INFORMATION. Operator shall promptly furnish the Developer
          with any additional information as it may reasonably request,
          including without limitation geological, technical, and financial
          information, in the form as may reasonably be requested, pertaining to
          any phase of the operations and activities governed by this Agreement.
          The Developer and its authorized employees, agents and consultants,
          including independent accountants shall, at Developer's sole cost and
          expense:

          (i)  on at least ten (10) days' written notice to Operator have access
               during normal business hours to all of Operator's records
               pertaining to operations under this Agreement, including without
               limitation, the right to audit the books of account of Operator
               relating to all receipts, costs, charges, expenses and
               disbursements and information regarding the separate account
               required under sub-section (c); and

          (ii) have access, at its sole risk, to any wells drilled by Operator
               under this Agreement at all times to inspect and observe any
               machinery, equipment and operations.

8.   OPERATOR'S LIEN; RIGHT TO COLLECT FROM OIL OR GAS PURCHASER.

     (a)  OPERATOR'S LIEN. To secure the payment of all sums due from Developer
          to Operator under this Agreement, the Developer grants Operator a
          first and preferred lien on and security interest in the following:

          (i)   the Developer's interest in the Leases covered by this
                Agreement;

          (ii)  the Developer's interest in oil and gas produced under this
                Agreement and its share of the proceeds from the sale of the oil
                and gas; and

          (iii) the Developer's interest in materials and equipment under this
                Agreement.

     (b)  RIGHT TO COLLECT FROM OIL OR GAS PURCHASER. If the Developer fails to
          timely pay any amount owing under this Agreement by it to the
          Operator, then Operator, without prejudice to other existing remedies,
          may collect and retain from any purchaser or purchasers of oil or gas
          the Developer's share of the proceeds from the sale of the oil and gas
          until the amount owed by the Developer, plus twelve percent (12%)
          interest on a per annum basis, and any additional costs (including
          without limitation actual attorneys' fees and costs) resulting from
          the delinquency, has been paid. Each purchaser of oil or gas shall be
          entitled to rely on Operator's written statement concerning the amount
          of any default.

9.   SUCCESSORS AND ASSIGNS; TRANSFERS; APPOINTMENT OF AGENT.

     (a)  SUCCESSORS AND ASSIGNS. This Agreement shall be binding on and inure
          to the benefit of the undersigned parties and their respective
          successors and permitted assigns. However, without the prior written
          consent of the Developer, the Operator may not assign, transfer,
          pledge, mortgage, hypothecate, sell or otherwise

                                       12
dispose of any of its interest in this Agreement, or any of its rights
          or obligations under this Agreement. Notwithstanding, this consent
          shall not be required in connection with:

          (i)   the assignment of work to be performed for Operator to
                subcontractors, it being understood and agreed, however, that
                any assignment to Operator's subcontractors shall not in any
                manner relieve or release Operator from any of its obligations
                and responsibilities under this Agreement;

          (ii)  any lien, assignment, security interest, pledge or mortgage
                arising under Operator's present or future financing
                arrangements; or

          (iii) the liquidation, merger, consolidation, or other corporate
                reorganization or sale of substantially all of the assets of
                Operator.

          Further, in order to maintain uniformity of ownership in the wells,
          production, equipment, and leasehold interests covered by this
          Agreement, and notwithstanding any other provision of this Agreement
          to the contrary, the Developer shall not, without the prior written
          consent of Operator, sell, assign, transfer, encumber, mortgage or
          otherwise dispose of any of its interest in the wells, production,
          equipment or leasehold interests covered by this Agreement unless the
          disposition encompasses either:

          (i)  the entire interest of the Developer in all wells, production,
               equipment and leasehold interests subject to this Agreement; or

          (ii) an equal undivided interest in all such wells, production,
               equipment, and leasehold interests.

     (b)  TRANSFERS. Subject to the provisions of sub-section (a) above, any
          sale, encumbrance, transfer or other disposition made by the Developer
          of its interests in the wells, production, equipment, and/or leasehold
          interests covered by this Agreement shall be made:

          (i)   expressly subject to this Agreement;

          (ii)  without prejudice to the rights of the Operator; and

          (iii) in accordance with and subject to the provisions of the Leases
                covering the Well Locations.

     (c)  APPOINTMENT OF AGENT. If at any time the interest of the Developer is
          divided among or owned by co-owners, Operator may, in its discretion,
          require the co-owners to appoint a single trustee or agent with full
          authority to do the following:

          (i)   receive notices, reports and distributions of the proceeds from
                production;

          (ii)  approve expenditures;

          (iii) receive billings for and approve and pay all costs, expenses and
                liabilities incurred under this Agreement;

          (iv)  exercise any rights granted to the co-owners under this
                Agreement;

          (v)   grant any approvals or authorizations required or contemplated
                by this Agreement;

          (vi)  sign, execute, certify, acknowledge, file and/or record any
                agreements, contracts, instruments, reports, or documents
                whatsoever in connection with this Agreement or the activities
                contemplated by this Agreement; and

          (vii) deal generally with, and with power to bind, the co-owners with
                respect to all activities and operations contemplated by this
                Agreement.

                                       13
However, all the co-owners shall continue to have the right to enter
          into and execute all contracts or agreements for their respective
          shares of the oil and gas produced from the wells drilled under this
          Agreement in accordance with sub-section (c) of Section 11.

10.  OPERATOR'S INSURANCE; SUBCONTRACTORS' INSURANCE; OPERATOR'S LIABILITY.

     (a)  OPERATOR'S INSURANCE. Operator shall obtain and maintain at its own
          expense so long as it is Operator under this Agreement all required
          Workmen's Compensation Insurance and comprehensive general public
          liability insurance in amounts and coverage not less than $1,000,000
          per person per occurrence for personal injury or death and $1,000,000
          for property damage per occurrence, which shall include coverage for
          blow-outs, and total liability coverage of not less than $10,000,000.

          Subject to the above limits, the Operator's general public liability
          insurance shall be in all respects comparable to that generally
          maintained in the industry with respect to services of the type to be
          rendered and activities of the type to be conducted under this
          Agreement. Operator's general public liability insurance shall, if
          permitted by Operator's insurance carrier:

          (i)  name the Developer as an additional insured party; and

          (ii) provide that at least thirty (30) days' prior notice of
               cancellation and any other adverse material change in the policy
               shall be given to the Developer.

          However, the Developer shall reimburse Operator for the additional
          cost, if any, of including it as an additional insured party under the
          Operator's insurance.

          Current copies of all policies or certificates of the Operator's
          insurance coverage shall be delivered to the Developer on request. It
          is understood and agreed that Operator's insurance coverage may not
          adequately protect the interests of the Developer and that the
          Developer shall carry at its expense the excess or additional general
          public liability, property damage, and other insurance, if any, as the
          Developer deems appropriate.

     (b)  SUBCONTRACTORS' INSURANCE. Operator shall require all of its
          subcontractors to carry all required Workmen's Compensation Insurance
          and to maintain such other insurance, if any, as Operator in its
          discretion may require.

     (c)  OPERATOR'S LIABILITY. Operator's liability to the Developer as
          Operator under this Agreement shall be limited to, and Operator shall
          indemnify the Developer and hold it harmless from, claims, penalties,
          liabilities, obligations, charges, losses, costs, damages, or expenses
          (including but not limited to reasonable attorneys' fees) relating to,
          caused by or arising out of:

          (i)   the noncompliance with or violation by Operator, its employees,
                agents, or subcontractors of any local, state or federal law,
                statute, regulation, or ordinance;

          (ii)  the negligence or misconduct of Operator, its employees, agents
                or subcontractors; or

          (iii) the breach of or failure to comply with any provisions of this
                Agreement.

11.  INTERNAL REVENUE CODE ELECTION; RELATIONSHIP OF PARTIES; RIGHT TO TAKE
     PRODUCTION IN KIND.

     (a)  INTERNAL REVENUE CODE ELECTION. With respect to this Agreement, each
          of the parties elects under Section 761(a) of the Internal Revenue
          Code of 1986, as amended, to be excluded from the provisions of
          Subchapter K of Chapter 1 of Subtitle A of the Internal Revenue Code
          of 1986, as amended. If the income tax laws of the state or states in
          which the property covered by this Agreement is located contain, or
          may subsequently contain, a similar election, each of the parties
          agrees that the election shall be exercised.

                                       14
Beginning with the first taxable year of operations under this
          Agreement, each party agrees that the deemed election provided by
          Section 1.761-2(b)(2)(ii) of the Regulations under the Internal
          Revenue Code of 1986, as amended, will apply; and no party will file
          an application under Section 1.761-2 (b)(3)(i) of the Regulations to
          revoke the election. Each party agrees to execute the documents and
          make the filings with the appropriate governmental authorities as may
          be necessary to effect the election.

     (b)  RELATIONSHIP OF PARTIES. It is not the intention of the parties to
          create, nor shall this Agreement be construed as creating, a mining or
          other partnership or association or to render the parties liable as
          partners or joint venturers for any purpose. Operator shall be deemed
          to be an independent contractor and shall perform its obligations as
          set forth in this Agreement.

     (c)  RIGHT TO TAKE PRODUCTION IN KIND. Subject to the provisions of Section
          8 above, the Developer shall have the exclusive right to sell or
          dispose of its proportionate share of all oil and gas produced from
          the wells to be drilled under this Agreement, exclusive of production:

          (i)   that may be used in development and producing operations;

          (ii)  unavoidably lost; and

          (iii) used to fulfill any free gas obligations under the terms of the
                applicable Lease or Leases.

          Operator shall not have any right to sell or otherwise dispose of the
          oil and gas. The Developer shall have the exclusive right to execute
          all contracts relating to the sale or disposition of its proportionate
          share of the production from the wells drilled under this Agreement.

          Developer shall have no interest in any gas supply agreements of
          Operator, except the right to receive Developer's share of the
          proceeds received from the sale of any gas or oil from wells developed
          under this Agreement. The Developer agrees to designate Operator or
          Operator's designated bank agent as the Developer's collection agent
          in any contracts. On request, Operator shall assist Developer in
          arranging the sale or disposition of Developer's oil and gas under
          this Agreement and shall promptly provide the Developer with all
          relevant information that comes to Operator's attention regarding
          opportunities for selling production.

          If Developer fails to take in kind or separately dispose of its
          proportionate share of the oil and gas produced under this Agreement,
          then Operator shall have the right, subject to the revocation at will
          by the Developer, but not the obligation, to purchase the oil and gas
          or sell it to others at any time and from time to time, for the
          account of the Developer at the best price obtainable in the area for
          the production. Notwithstanding, Operator shall have no liability to
          Developer should Operator fail to market the production.

          Any such purchase or sale by Operator shall be subject always to the
          right of the Developer to exercise at any time its right to take
          in-kind, or separately dispose of, its share of oil and gas not
          previously delivered to a purchaser. Any purchase or sale by Operator
          of the Developer's share of oil and gas under this Agreement shall be
          only for reasonable periods of time as are consistent with the minimum
          needs of the oil and gas industry under the particular circumstances,
          but in no event for a period in excess of one (1) year.

12.  EFFECT OF FORCE MAJEURE; DEFINITION OF FORCE MAJEURE; LIMITATION.

     (a)  EFFECT OF FORCE MAJEURE. If Operator is rendered unable, wholly or in
          part, by force majeure (as defined below) to carry out any of its
          obligations under this Agreement, including but not limited to
          beginning the drilling of one or more wells by the applicable times
          set forth in Section 2(b), or any Addendum to this Agreement, the
          obligations of the Operator, so far as it is affected by the force
          majeure, shall be suspended during but no longer than, the continuance
          of the force majeure. The Operator shall give to the Developer prompt
          written notice of the force majeure with reasonably full particulars

                                       15
concerning it. Operator shall use all reasonable diligence to remove
          the force majeure as quickly as possible to the extent the same is
          within its reasonable control.

     (b)  DEFINITION OF FORCE MAJEURE. The term "force majeure" shall mean an
          act of God, strike, lockout, or other industrial disturbance, act of
          the public enemy, war, terrorist acts, blockade, public riot,
          lightning, fire, storm, flood, explosion, governmental restraint,
          unavailability of drilling rigs, equipment or materials, plant
          shut-downs, curtailments by oil and gas purchasers and any other
          causes whether of the kind specifically enumerated above or otherwise,
          which directly preclude Operator's performance under this Agreement
          and is not reasonably within the control of the Operator including,
          but not limited to, the inability of Operator to begin the drilling of
          the wells subject to this Agreement by the applicable times set forth
          in Section 2(b) or in any Addendum to this Agreement due to decisions
          of third-party operators to delay drilling the wells, poor weather
          conditions, inability to obtain drilling permits, access right to the
          drilling site or title problems.

     (c)  LIMITATION. The requirement that any force majeure shall be remedied
          with all reasonable dispatch shall not require the settlement of
          strikes, lockouts, or other labor difficulty affecting the Operator
          contrary to its wishes. The method of handling these difficulties
          shall be entirely within the discretion of the Operator.

13.  TERM.

     This Agreement shall become effective when executed by Operator and the
     Developer. Except as provided in sub-section (c) of Section 3, this
     Agreement shall continue and remain in full force and effect for the
     productive lives of each wells being operated under this Agreement.

14.  GOVERNING LAW; INVALIDITY.

     (a)  GOVERNING LAW. This Agreement shall be governed by, construed and
          interpreted in accordance with the laws of the Commonwealth of
          Pennsylvania, excluding its conflict of law provisions.

     (b)  INVALIDITY. The invalidity or unenforceability of any particular
          provision of this Agreement shall not affect the other provisions of
          this Agreement, and this Agreement shall be construed in all respects
          as if the invalid or unenforceable provision were omitted.

15.  INTEGRATION; WRITTEN AMENDMENT.

     (a)  INTEGRATION. This Agreement, including the Exhibits to this Agreement,
          constitutes and represents the entire understanding and agreement of
          the parties with respect to the subject matter of this Agreement and
          supersedes all prior negotiations, understandings, agreements, and
          representations relating to the subject matter of this Agreement.

     (b)  WRITTEN AMENDMENT. No change, waiver, modification, or amendment of
          this Agreement shall be binding or of any effect unless in writing
          duly signed by the party against which the change, waiver,
          modification, or amendment is sought to be enforced.

16.  WAIVER OF DEFAULT OR BREACH.

     No waiver by any party to any default of or breach by any other party under
     this Agreement shall operate as a waiver of any future default or breach,
     whether of like or different character or nature.

17.  NOTICES.

     Unless otherwise provided in this Agreement, all notices, statements,
     requests, or demands that are required or contemplated by this Agreement
     shall be in writing and shall be hand-delivered or sent by registered or
     certified mail, postage prepaid, to the following addresses until a party's
     address is changed by certified or registered letter so addressed to the
     other party:

                                       16
(i)  If to the Operator, to:
          Atlas Resources, LLC
          311 Rouser Road
          Moon Township, Pennsylvania 15108
          Attention: President

     (ii) If to Developer, to:
          Atlas America Public #16-2007(A) L.P.
          [Atlas America Public #16-2007(B) L.P.]
          c/o Atlas Resources, LLC
          311 Rouser Road
          Moon Township, Pennsylvania 15108

     Notices that are served by registered or certified mail on the parties in
     the manner provided above shall be deemed sufficiently served or given for
     all purposes under this Agreement at the time the notice is hand-delivered
     or mailed in any post office or branch post office regularly maintained by
     the United States Postal Service or any successor. All payments shall be
     hand-delivered or sent by United States mail, postage prepaid to the
     addresses set forth above until a party's address is changed by certified
     or registered letter so addressed to the other party.

18.  INTERPRETATION.

     The titles of the Sections in this Agreement are for convenience of
     reference only and shall not control or affect the meaning or construction
     of any of the terms and provisions of this Agreement. As used in this
     Agreement, the plural shall include the singular and the singular shall
     include the plural whenever appropriate.

19.  COUNTERPARTS.

     The parties may execute this Agreement in any number of separate
     counterparts, each of which, when executed and delivered by the parties,
     shall have the force and effect of an original; but all counterparts of
     this Agreement shall be deemed to constitute one and the same instrument.

     IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement as
of the day and year first above written.

                                  ATLAS RESOURCES, LLC

                                  By:
                                      ------------------------------------------
                                      Frank P. Carolas, Executive Vice President

                                   ATLAS AMERICA PUBLIC #16-2007(A) L.P.
                                   [ATLAS AMERICA PUBLIC #16-2007(B) L.P.]

                                  By its Managing General Partner:
                                  ATLAS RESOURCES, LLC

                                  By:
                                      ------------------------------------------
                                      Frank P. Carolas, Executive Vice President

                                       17
DESCRIPTION OF LEASES AND INITIAL WELL LOCATIONS
               [To be completed as information becomes available]

1.   WELL LOCATION

     (a)  Oil and Gas Lease from ______________________________________ dated
          _____________________ and recorded in Deed Book Volume __________,
          Page __________ in the Recorder's Office of County, ____________,
          covering approximately _________ acres in ____________________________
          Township, ___________________ County, ______________________.

     (b)  The portion of the leasehold estate constituting the
          ____________________________________________ No. __________ Well
          Location is described on the map attached hereto as Exhibit A-l.

     (c)  Title Opinion of _________________________________,
          ____________________________________, _______________________________,
          ________________________________________, dated ___________________,
          200___.

     (d)  The Developer's interest in the leasehold estate constituting this
          Well Location is an undivided % Working Interest to those oil and gas
          rights from the surface to the deepest depth penetrated at the
          cessation of drilling activities (which is ___________ feet), subject
          to the landowner's royalty interest and overriding royalty interests.

                                    Exhibit A
Well Name, Twp.
                                                                   County, State

ASSIGNMENT OF OIL AND GAS LEASE

STATE OF _______________________________

COUNTY OF ___________________________

KNOW ALL MEN BY THESE PRESENTS:

     THAT the undersigned_______________________________________________________
(hereinafter called "Assignor"), for and in consideration of One Dollar and
other valuable consideration ($1.00 ovc), the receipt whereof is hereby
acknowledged, does hereby sell, assign, transfer and set over unto______________
________________________________(hereinafter called "Assignee"), an undivided
 _____________________________ in, and to, the oil and
gas lease described as follows:

together with the rights incident thereto and the personal property thereto,
appurtenant thereto, or used, or obtained, in connection therewith.

     And for the same consideration, the assignor covenants with the said
assignee and his or its heirs, successors, or assigns that assignor is the
lawful owner of said lease and rights and interest thereunder and of the
personal property thereon or used in connection therewith; that the undersigned
has good right and authority to sell and convey the same; and that said rights,
interest and property are free and clear from all liens and encumbrances, and
that all rentals and royalties due and payable thereunder have been duly paid.

     In Witness Whereof, the undersigned owner ______ and assignor ______ ha___
signed and sealed this instrument the ______ day of _______________, 200___.

Signed and acknowledged in the
presence of                             ----------------------------------------

-------------------------------------   ----------------------------------------

-------------------------------------   ----------------------------------------

                                    Exhibit B
                                    (Page 1)
ACKNOWLEDGMENT BY INDIVIDUAL

STATE OF ___

                                     BEFORE ME, a Notary Public, in and for said

COUNTY OF _________________________

     County and State, on this day personally appeared who acknowledged to me
that ____ he ____ did sign the foregoing instrument and that the same is
_____________ free act and deed.

     In testimony whereof, I have hereunto set my hand and official seal, at
_____________________________, this ______ day of _______________, A.D., 200_.

                                               _________________________________
                                               Notary Public

                           CORPORATION ACKNOWLEDGMENT

STATE OF _________________________

                                     BEFORE ME, a Notary Public, in and for said

COUNTY OF ________________________

     County and State, on this day personally appeared known to me to be the
person and officer whose name is subscribed to the foregoing instrument and
acknowledged that the same was the act of the said
______________________________________________, a corporation, and that he
executed the same as the act of such corporation for the purposes and
consideration therein expressed, and in the capacity therein stated.

     In testimony whereof, I have hereunto set my hand and official seal, at
_____________________________, this ______ day of _______________, A.D., 200_.

                                               _________________________________
                                               Notary Public

This instrument was prepared by:

Atlas Resources, LLC
311 Rouser Road
P.O. Box 611
Moon Township, PA 15108

                                    Exhibit B
                                    (Page 2)
ADDENDUM NO. __________

                       TO DRILLING AND OPERATING AGREEMENT

                       DATED ___________________,  200_

THIS ADDENDUM NO. __________ made and entered into this ______ day of
________________, 200_, by and between ATLAS RESOURCES, LLC, a Pennsylvania
limited liability company (hereinafter referred to as "Operator"),

                                       and

ATLAS AMERICA PUBLIC #16-2007(A) L.P. [ATLAS AMERICA PUBLIC #16-2007(B) L.P.], a
Delaware limited partnership, (hereinafter referred to as the Developer).

                                WITNESSETH THAT:

WHEREAS, Operator and the Developer have entered into a Drilling and Operating
Agreement dated ___________________, 200_, (the "Agreement"), which relates to
the drilling and operating of ________________ (______)wells on the
________________ (______) Initial Well Locations identified on the maps attached
as Exhibits A-l through A-______ to the Agreement, and provides for the
development on the terms and conditions set forth in the Agreement of Additional
Well Locations as the parties may from time to time designate; and

WHEREAS, pursuant to Section l(c) of the Agreement, Operator and Developer
presently desire to designate ________________ Additional Well Locations
described below to be developed in accordance with the terms and conditions of
the Agreement.

NOW, THEREFORE, in consideration of the mutual covenants contained in this
Addendum and intending to be legally bound, the parties agree as follows:

1. Pursuant to Section l(c) of the Agreement, the Developer hereby authorizes
Operator to drill, complete (or plug) and operate, on the terms and conditions
set forth in the Agreement and this Addendum No.__________, ________________
additional wells on the ________________ Additional Well Locations described on
Exhibit A to this Addendum and on the maps attached to this Addendum as Exhibits
A-______ through A-______.

2. Operator, as Developer's independent contractor, agrees to drill, complete
(or plug) and operate the additional wells on the Additional Well Locations in
accordance with the terms and conditions of the Agreement and further agrees to
begin drilling the first additional well within thirty (30) days after the date
of this Addendum and to begin drilling all of the additional wells before the
close of the 90th day after the close of the calendar year in which the
Agreement was entered into by Operator and the Developer, or, if this Addendum
is dated after that 90 day period, to begin drilling the first additional well
within thirty (30) days after the date of this Addendum and to drill and
complete (or plug) all of the remaining additional wells by the end of the
calendar year in which this Addendum is dated.

3. Developer acknowledges that:

     (a)  Operator has furnished Developer with the title opinions identified on
          Exhibit A to this Addendum; and

     (b)  such other documents and information which Developer or its counsel
          has requested in order to determine the adequacy of the title to the
          above Additional Well Locations.

The Developer accepts the title to the Additional Well Locations and leased
premises in accordance with the provisions of Section 5 of the Agreement.

4. The drilling and operation of the additional wells on the Additional Well
Locations shall be in accordance with and subject to the terms and conditions
set forth in the Agreement as supplemented by this Addendum No. __________ and
except as previously supplemented, all terms and conditions of the Agreement
shall remain in full force and effect as originally written.

                                    Exhibit C
                                    (Page 1)
5. This Addendum No. __________ shall be legally binding on, and shall inure to
the benefit of, the parties and their respective successors and permitted
assigns.

WITNESS the due execution of this Addendum on the day and year first above
written.

                                        ATLAS RESOURCES, LLC

                                        By
                                           -------------------------------------

                                        ATLAS AMERICA PUBLIC #16-2007(A) L.P.
                                        [ATLAS AMERICA PUBLIC #16-2007(B) L.P.]

                                        By its Managing General Partner:

                                        ATLAS RESOURCES, LLC

                                        By
                                           -------------------------------------

                                    Exhibit C
                                    (Page 2)
EXHIBIT (B)
                        SPECIAL SUITABILITY REQUIREMENTS
                          AND DISCLOSURES TO INVESTORS
SPECIAL SUITABILITY REQUIREMENTS AND DISCLOSURES TO INVESTORS

If you are a resident of one of the following states, then you must meet that
state's qualification and suitability standards as set forth below.

    SPECIAL SUITABILITY REQUIREMENTS IF YOU ARE BUYING LIMITED PARTNER UNITS.

I.   If you are a resident of CALIFORNIA or NEW JERSEY and you purchase limited
     partners units, then you must meet any one of the following special
     suitability requirements:

          o    a net worth of not less than $250,000, exclusive of home, home
               furnishings and automobiles, and expect to have gross income in
               the current year of $65,000 or more; or

          o    a net worth of not less than $500,000, exclusive of home, home
               furnishings and automobiles; or

          o    a net worth of not less than $1 million; or

          o    expected gross income in the current tax year of not less than
               $200,000.

II.  If you are a resident of MICHIGAN OR NORTH CAROLINA and you purchase
     limited partner units, then you must meet either one of the following
     special suitability requirements:

          o    a net worth of not less than $225,000, exclusive of home, home
               furnishings and automobiles; or

          o    a net worth of not less than $60,000, exclusive of home, home
               furnishings and automobiles, and estimated CURRENT year taxable
               income as defined in Section 63 of the Internal Revenue Code of
               $60,000 or more without regard to an investment in the
               partnership.

     In addition, if you are a resident of MICHIGAN, then you must not make an
     investment in the partnership in excess of 10% of your net worth, exclusive
     of home, home furnishings and automobiles.

III. If you are a resident of NEW HAMPSHIRE and you purchase limited partner
     units, then you must meet either one of the following special suitability
     requirements:

          o    a net worth of not less than $250,000, exclusive of home, home
               furnishings, and automobiles, or

          o    a net worth of not less than $125,000, exclusive of home, home
               furnishings, and automobiles, and $50,000 of taxable income.

IV.  If you are a resident of OHIO and you subscribe for limited partner units,
     then you must meet, without regard to your investment in a partnership,
     either of the following special suitability requirements:

          o    a net worth of not less than $330,000, exclusive of home, home
               furnishings, and automobiles; or

          o    a net worth of not less than $85,000, exclusive of home, home
               furnishings, and automobiles, and an annual gross income during
               the current tax year of at least $85,000.

     Additionally, if you are a resident of OHIO you must not make an investment
     in a partnership which would, after including your previous investments in
     prior Atlas Resources programs, if any, and any other similar natural gas
     and oil drilling programs, exceed 10% of your net worth, exclusive of home,
     home furnishings and automobiles.

           SPECIAL SUITABILITY REQUIREMENTS IF YOU ARE BUYING INVESTOR
                             GENERAL PARTNER UNITS.

I.   If you are a resident of CALIFORNIA or NEW JERSEY and you purchase investor
     general partner units, then you must meet any one of the following special
     suitability requirements:

                                       1
o    an individual or joint net worth with your spouse of not less
               than $250,000, exclusive of home, home furnishings and
               automobiles, and expect to have annual gross income in the
               current year of $120,000 or more; or

          o    an individual or joint net worth with your spouse of not less
               than $500,000, exclusive of home, home furnishings and
               automobiles; or

          o    an individual or joint net worth with your spouse of not less
               than $1 million; or

          o    a combined expected gross income in the current year of not less
               than $200,000.

II. If you are a resident of any of the following states:

          o    ALABAMA;

          o    ARKANSAS;

          o    INDIANA;

          o    MAINE;

          o    MASSACHUSETTS;

          o    MINNESOTA;

          o    NORTH CAROLINA;

          o    OKLAHOMA;

          o    PENNSYLVANIA;

          o    TENNESSEE;

          o    TEXAS; OR

          o    WASHINGTON.

and you purchase investor general partner units, then you must meet any one of
the following special suitability requirements:

          o    an individual or joint net worth with your spouse of $225,000 or
               more, without regard to the investment in the partnership,
               exclusive of home, home furnishings and automobiles, and A
               COMBINED GROSS INCOME OF $100,000 OR MORE FOR THE CURRENT YEAR
               AND FOR THE TWO PREVIOUS YEARS; or

          o    an individual or joint net worth with your spouse in excess of $1
               million, inclusive of home, home furnishings and automobiles; or

          o    an individual or joint net worth with your spouse in excess of
               $500,000, exclusive of home, home furnishings and automobiles; or

          o    a combined "gross income" as defined in Section 61 of the
               Internal Revenue Code of 1986, as amended, in excess of $200,000
               in the current year and the two previous years.

III. If you are a resident of any of the following states:

          o    ARIZONA;

          o    IOWA;

          o    KANSAS;

          o    KENTUCKY;

          o    MICHIGAN;

          o    MISSISSIPPI;

          o    MISSOURI;

          o    NEW MEXICO;

          o    OREGON;

          o    SOUTH DAKOTA; OR

          o    VERMONT;

     and you purchase investor general partner units, then you must meet any one
     of the following special suitability requirements:

          o    an individual or joint net worth with your spouse of $225,000 or
               more, without regard to the investment in the partnership,
               exclusive of home, home furnishings and automobiles, AND A
               COMBINED "TAXABLE INCOME" OF $60,000 OR MORE FOR THE PREVIOUS
               YEAR AND EXPECT TO HAVE A COMBINED "TAXABLE INCOME" OF $60,000 OR
               MORE FOR THE CURRENT YEAR AND FOR THE SUCCEEDING YEAR; or

                                       2
o    an individual or joint net worth with your spouse in excess of $1
               million, inclusive of home, home furnishings and automobiles; or

          o    an individual or joint net worth with your spouse in excess of
               $500,000, exclusive of home, home furnishings and automobiles; or

          o    a combined "gross income" as defined in Section 61 of the
               Internal Revenue Code of 1986, as amended, in excess of $200,000
               in the current year and the two previous years.

IV. In addition, if you are a resident of any of the following states:

          o    IOWA;

          o    MICHIGAN; OR

          o    PENNSYLVANIA;

     then you must not make an investment in the partnership in excess of 10% of
     your net worth, exclusive of home, furnishings and automobiles.

     Also, if you are a resident of KANSAS, it is recommended by the Office of
     the Kansas Securities Commissioner that you should limit your investment in
     the program and substantially similar programs to no more than 10% of your
     net worth, excluding home, furnishings and automobiles.

V.   If you are a resident of NEW HAMPSHIRE and you purchase investor general
     partner units, then you must meet either one of the following special
     suitability requirements:

          o    an individual or joint net worth with your spouse of not less
               than $250,000, exclusive of home, home furnishings, and
               automobiles, or

          o    an individual or joint net worth with your spouse of not less
               than $125,000, exclusive of home, home furnishings, and
               automobiles, and $50,000 of taxable income.

VI.  If you are a resident of OHIO and you subscribe for investor general
     partner units, then you must meet, without regard to your investment in a
     partnership, either of the following special suitability requirements:

          o    an individual or joint net worth with your spouse of not less
               than $750,000, exclusive of home, home furnishings, and
               automobiles; or

          o    an individual or joint net worth with your spouse of not less
               than $330,000, exclusive of home, home furnishings, and
               automobiles, and an annual gross income of at least $150,000 for
               the current year and the two previous years.

     Additionally, if you are a resident of OHIO you must not make an investment
     in a partnership which would, after including your previous investments in
     prior Atlas Resources programs, if any, and any other similar natural gas
     and oil drilling programs, exceed 10% of your net worth, exclusive of home,
     home furnishings and automobiles.

                   SPECIAL REPRESENTATIONS OF SUBSCRIBERS IN
               CALIFORNIA, IOWA, NORTH CAROLINA AND PENNSYLVANIA.

I. If a resident of CALIFORNIA, I am aware that:

               IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY,
               OR ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION
               THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER
               OF

                                       3
CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN
               THE COMMISSIONER'S RULES.

As a condition of qualification of the units for sale in the State of
California, the following rule is hereby delivered to each California purchaser.

CALIFORNIA ADMINISTRATIVE CODE, TITLE 10, CH. 3, RULE 260.141.11. RESTRICTION ON
TRANSFER.

     (a)  The issuer of any security upon which a restriction on transfer has
          been imposed pursuant to Section 260.141.10 or 260.534 shall cause a
          copy of this section to be delivered to each issuee or transferee of
          such security at the time the certificate evidencing the security is
          delivered to the issuee or transferee.

     (b)  It is unlawful for the holder of any such security to consummate a
          sale or transfer of such security, or any interest therein, without
          the prior written consent of the Commissioner (until this condition is
          removed pursuant to Section 260.141.12 of these rules), except:

          (i)    to the issuer;

          (ii)   pursuant to the order or process of any court;

          (iii)  to any person described in Subdivision (i) of Section 25102 of
                 the Code or Section 260.105.14 of these rules;

          (iv)   to the transferor's ancestors, descendants or spouse, or any
                 custodian or trustee for the account of the transferor or the
                 transferor's ancestors, descendants or spouse, or to a
                 transferee by a trustee or custodian for the account of the
                 transferee or the transferee's ancestors, descendants or
                 spouse;

          (v)    to holders of securities of the same class of the same issuer;

          (vi)   by way of gift or donation inter vivos or on death;

          (vii)  by or through a broker-dealer licensed under the Code (either
                 acting as such or as a finder) to a resident of a foreign
                 state, territory or country who is neither domiciled in this
                 state to the knowledge of the broker-dealer, nor actually
                 present in this state if the sale of such securities is not in
                 violation of any securities law of the foreign state, territory
                 or country concerned;

          (viii) to a broker-dealer licensed under the Code in a principal
                 transaction, or as an underwriter or member of an underwriting
                 syndicate or selling group;

          (ix)   if the interest sold or transferred is a pledge or other lien
                 given by the purchaser to the seller upon a sale of the
                 security for which the Commissioner's written consent is
                 obtained or under this rule not required;

          (x)    by way of a sale qualified under Sections 25111, 25112, 25113
                 or 25121 of the Code, of the securities to be transferred,
                 provided that no order under Section 25140 or Subdivision (a)
                 of Section 25143 is in effect with respect to such
                 qualification;

          (xi)   by a corporation to a wholly-owned subsidiary of such
                 corporation, or by a wholly-owned subsidiary of a corporation
                 to such corporation;

          (xii)  by way of an exchange qualified under Section 25111, 25112 or
                 25113 of the Code, provided that no order under Section 25140
                 or Subdivision (a) of Section 25143 is in effect with respect
                 to such qualification;

                                       4
(xiii) between residents of foreign states, territories or countries
                 who are neither domiciled nor actually present in this state;

          (xiv)  to the State Controller pursuant to the Unclaimed Property Law
                 or to the administrator of the unclaimed property law of
                 another state;

          (xv)   by the State Controller pursuant to the Unclaimed Property Law
                 or by the administrator of the unclaimed property law of
                 another state if, in either such case, such person (i)
                 discloses to potential purchasers at the sale that transfer of
                 the securities is restricted under this rule, (ii) delivers to
                 each purchaser a copy of this rule, and (iii) advises the
                 Commissioner of the name of each purchaser;

          (xvi)  by a trustee to a successor trustee when such transfer does not
                 involve a change in the beneficial ownership of the securities;

          (xvii) by way of an offer and sale of outstanding securities in an
                 issuer transaction that is subject to the qualification
                 requirement of Section 25110 of the Code but exempt from that
                 qualification requirement by subdivision (f) of Section 25102;

          provided that any such transfer is on the condition that any
          certificate evidencing the security issued to such transferee shall
          contain the legend required by this section.

     (c)  The certificates representing all such securities subject to such a
          restriction on transfer, whether upon initial issuance or upon any
          transfer thereof, shall bear on their face a legend, prominently
          stamped or printed thereon in capital letters of not less than
          10-point size, reading as follows:

          "IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY, OR
          ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFOR,
          WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER OF CORPORATIONS
          OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE COMMISSIONER'S
          RULES."

II. If a resident of IOWA or NORTH CAROLINA, I am aware that:

          IN MAKING AN INVESTMENT DECISION INVESTORS MUST RELY ON THEIR OWN
          EXAMINATION OF THE PERSON OR ENTITY CREATING THE SECURITIES AND THE
          TERMS OF THE OFFERING, INCLUDING THE MERITS AND RISKS INVOLVED. THESE
          SECURITIES HAVE NOT BEEN RECOMMENDED BY ANY FEDERAL OR STATE
          SECURITIES COMMISSION OR REGULATORY AUTHORITY. FURTHERMORE, THE
          FOREGOING AUTHORITIES HAVE NOT CONFIRMED THE ACCURACY OR DETERMINED
          THE ADEQUACY OF THIS DOCUMENT. ANY REPRESENTATION TO THE CONTRARY IS A
          CRIMINAL OFFENSE.

III. PENNSYLVANIA INVESTORS: Because the minimum closing amount is less than 10%
     of the maximum closing amount allowed to a partnership in this offering,
     you are cautioned to carefully evaluate the partnership's ability to fully
     accomplish its stated objectives and inquire as to the current dollar
     volume of partnership subscriptions.

                                       5
TABLE OF CONTENTS

                                                                            Page
                                                                            ----
Summary of the Offering..................................................      1
Risk Factors.............................................................      8
Additional Information...................................................     21
Forward Looking Statements and Associated Risks..........................     21
Investment Objectives....................................................     22
Actions to be Taken by Managing General Partner to Reduce Risks of
   Additional Payments by Investor General Partners......................     24
Capitalization and Source of Funds and Use of Proceeds...................     26
Compensation.............................................................     29
Terms of the Offering....................................................     37
Prior Activities.........................................................     44
Management...............................................................     55
Management's Discussion and Analysis of Financial Condition, Results
   of Operations, Liquidity and Capital Resources........................     63
Proposed Activities......................................................     65
Competition, Markets and Regulation......................................     80
Participation in Costs and Revenues......................................     84
Conflicts of Interest....................................................     91
Fiduciary Responsibility of the Managing General Partner.................    103
Federal Income Tax Consequences..........................................    104
Summary of Partnership Agreement.........................................    135
Summary of Drilling and Operating Agreement..............................    137
Reports to Investors.....................................................    138
Presentment Feature......................................................    139
Transferability of Units.................................................    141
Plan of Distribution.....................................................    142
Sales Material...........................................................    144
Legal Opinions...........................................................    145
Experts..................................................................    145
Litigation...............................................................    145
Financial Information Concerning the Managing General Partner and
   Atlas America Public #16-2007(A) L.P..................................    146
Index to Financial Statements............................................    146

EXHIBIT (A) - Form of Amended and Restated Certificate and Agreement of
     Limited Partnership for Atlas America Public #16-2007(A) L.P. [Form
     of Amended and Restated Certificate and Agreement of Limited
     Partnership for Atlas America Public #16-2007(B) L.P.]

EXHIBIT (I-A) - Form of Managing General Partner Signature Page

EXHIBIT (I-B) - Form of Subscription Agreement

EXHIBIT (II) - Form of Drilling and Operating Agreement for Atlas America
     Public #16-2007(A) L.P. [Atlas America Public #16-2007(B) L.P.]

EXHIBIT (B) - Special Suitability Requirements and Disclosures to
     Investors

No one has been authorized to give any information or make any representations
other than those contained in this prospectus in connection with this offering.
If given or made, you should not rely on such information or representations as
having been authorized by the managing general partner. The delivery of this
prospectus does not imply that its information is correct as of any time after
its date. This prospectus is not an offer to sell these securities in any state
to any person where the offer and sale is not permitted.

                                  ATLAS AMERICA

                             PUBLIC #16-2007 PROGRAM

                                   ----------

                                   PROSPECTUS

                                   ----------

Until December 31, 2007, all dealers that effect transactions in these
securities, whether or not participating in this offering, may be required to
deliver a prospectus. This is in addition to the dealers' obligation to deliver
a prospectus when acting as underwriters and with respect to their unsold
allotments or subscriptions.
PART II

                     INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

The expenses to be incurred in connection with the issuance and distribution of
the securities to be registered, other than underwriting discounts, commissions
and expense allowances, are estimated to be as follows:

Accounting Fees and Expenses ...................   $   40,000*
Legal Fees (including Blue Sky) and Expenses ...      360,000*
Printing .......................................      300,000*
SEC Registration Fee ...........................       21,400
Blue Sky Filing Fees (excluding legal fees) ....      165,265*
NASD Filing Fee ................................       20,500
Miscellaneous ..................................      566,837*
                                                   ----------
   Total .......................................   $1,474,002*
                                                   ==========

----------
*    Estimated

ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

Title 15, Section 8945 of the Pennsylvania Consolidated Statutes provides for
indemnification of members and managers by a limited liability company subject
to certain limitations.

Under Section 4.05 of the Amended and Restated Certificate and Agreement of
Limited Partnership, the Participants, within the limits of their Capital
Contributions, and the Partnership, generally agree to indemnify and exonerate
the Managing General Partner, the Operator and their Affiliates from claims of
liability to any third party arising out of operations of the Partnership
provided that:

     o    they determined in good faith that the course of conduct which caused
          the loss or liability was in the best interest of the Partnership;

     o    they were acting on behalf of or performing services for the
          Partnership; and

     o    the course of conduct was not the result of their negligence or
          misconduct.

Section 11 of the Dealer-Manager Agreement provides for the indemnification of
the Managing General Partner, the Partnership and control persons under
specified conditions by the Dealer-Manager and/or Selling Agent.

ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.

None by the Registrant.

Atlas Resources, LLC ("Atlas"), an Affiliate of the Registrant, has made sales
of unregistered and registered securities within the last three years. See the
section of the Prospectus captioned "Prior Activities" regarding the sale of
limited and general partner interests. In the opinion of Atlas, the foregoing
unregistered securities in each case have been and/or are being offered and sold
in compliance with exemptions from registration provided by the Securities Act
of 1933, as amended, including the exemptions provided by Section 4(2) of that
Act and certain rules and regulations promulgated thereunder. The securities in
each case have been and/or are being offered and sold to a limited number of
persons who had the sophistication to understand the merits and risks of the
investment and who had the financial ability to bear such risks. The units of
limited and general partner interests were sold to persons who were Accredited
Investors, as that term is defined in Regulation D (17 CFR 230.501(a)), or who
had, at the time of purchase, a net worth of at least $225,000 (exclusive of
home,

                                        1
furnishings and automobiles) of at least $125,000 and gross income of at least
$75,000, or otherwise satisfied Atlas that the investment was suitable.

ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

     (a)  Exhibits

          1(a)  Proposed form of Dealer-Manager Agreement with Anthem
                Securities, Inc.

          3(a)  Certificate of Organization of Atlas Resources, LLC

          3(b)  Operating Agreement of Atlas Resources, LLC

          4(a)  Certificate of Limited Partnership for Atlas America Public
                #16-2007(A) L.P.

          4(b)  Certificate of Limited Partnership for Atlas America Public
                #16-2007(B) L.P.

          4(c)  Form of Amended and Restated Certificate and Agreement of
                Limited Partnership for Atlas America Public #16-2007(A) L.P.
                [Form of Amended and Restated Certificate and Agreement of
                Limited Partnership for Atlas America Public #16-2007(B) L.P.]
                (See Exhibit (A) to Prospectus)

          5     Opinion of Kunzman & Bollinger, Inc. as to the legality of the
                Units

          8     Opinion of Kunzman & Bollinger, Inc. as to federal tax matters

          10(a) Escrow Agreement for Atlas America Public #16-2007(A) L.P.

          10(b) Form of Drilling and Operating Agreement for Atlas America
                Public #16-2007(A) L.P. [Atlas America Public #16-2007(B) L.P.]
                (See Exhibit (II) to the Form of Limited Partnership Agreement,
                Exhibit (A) to Prospectus)

          10(c) Gas Purchase Agreement dated March 31, 1999 between Northeast
                Ohio Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas
                Resources, Inc., and Resource Energy, Inc.

          10(d) Guaranty dated August 12, 2003 between First Energy Corp. and
                Atlas Resources, Inc. to Gas Purchase Agreement dated March 31,
                1999 between Northeast Ohio Gas Marketing, Inc., and Atlas
                Energy Group, Inc., Atlas Resources, Inc., and Resource Energy,
                Inc.

          10(e) Master Natural Gas Gathering Agreement dated February 2, 2000
                among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating
                Partnership, L.P., Atlas America, Inc., Resource Energy, Inc.,
                and Viking Resources Corporation

          10(f) Omnibus Agreement dated February 2, 2000 among Atlas America,
                Inc., Resource Energy, Inc., and Viking Resources Corporation,
                and Atlas Pipeline Operating Partnership, L.P., and Atlas
                Pipeline Partners, L.P.

          10(g) Natural Gas Gathering Agreement dated January 1, 2002 among
                Atlas Pipeline Partners, L.P., and Atlas Pipeline Operating
                Partnership, L.P. and Atlas Resources, Inc., and Atlas Energy
                Group, Inc. and Atlas Noble Corporation, and Resource Energy
                Inc., and Viking Resources Corporation

          10(h) Base Contract for Sale and Purchase of Natural Gas dated
                November 13, 2002 Between UGI Energy Services, Inc. and Viking
                Resources Corp.

          10(i) Guaranty dated June 1, 2004 between UGI Corporation and Viking
                Resources Corp.

                                        2
10(j) Guaranty as of December 7, 2004 between FirstEnergy Corp. and
                Atlas Resources, Inc.

          10(k) Confirmation of Gas Purchase and Sales Agreement dated November
                17, 2004 between Atlas Resources, Inc. et. al. and First Energy
                Solutions Corp. for the period from April 1, 2006 through March
                31, 2007 production/calendar periods

          10(l) Transaction Confirmation dated December 14, 2004 between Atlas
                America, Inc. and UGI Energy Services, Inc. d/b/a GASMARK

          10(m) Drilling and Operating Agreement Dated September 15, 2004 by and
                between Atlas America, Inc. and Knox Energy, LLC

          10(n) Guaranty dated January 1, 2005 between UGI Corporation and
                Viking Resources Corp.

          10(o) Escrow Agreement for Atlas America Public #16-2007(B) L.P.

          10(p) Amendment among Atlas Pipeline Partners, L.P. and Atlas Pipeline
                Operating Partnership, L.P., Atlas America, Inc., Resource
                Energy, Inc., Viking Resources Corporation, Atlas Noble Corp.,
                and Atlas Resources, Inc. to the Master Natural Gas Gathering
                Agreement dated February 2, 2000 and the Natural Gas Gathering
                Agreement dated January 1, 2002

          23(a) Consent of Independent Registered Public Accounting Firm

          23(b) Consent of Kunzman & Bollinger, Inc. (See Exhibits 5 and 8)

          23(c) Consent of Wright & Company, Inc.

          24    Power of Attorney

----------
     (b)  Financial Statement Schedules

     All financial statement schedules are omitted because the information is
not required, is not material or is otherwise included in the financial
statements or related notes thereto.

ITEM 17. UNDERTAKINGS.

The undersigned registrant hereby undertakes:

(a)  (1)  To file, during any period in which offers or sales are being made, a
          post-effective amendment to this registration statement:

          (i)   To include any prospectus required by section 10(a)(3) of the
                Securities Act of 1933;

          (ii)  To reflect in the prospectus any facts or events arising after
                the effective date of the registration statement (or the most
                recent post-effective amendment thereof) which, individually or
                in the aggregate, represent a fundamental change in the
                information set forth in the registration statement.
                Notwithstanding the foregoing, any increase or decrease in
                volume of securities offered (if the total dollar value of
                securities offered would not exceed that which was registered)
                and any deviation from the low or high end of the estimated
                maximum offering range may be reflected in the form of
                prospectus filed with the Commission pursuant to Rule 424(b)
                (Section 230.424(b) of this chapter) if, in the aggregate, the
                changes in volume and price represent no more than 20% change

                                        3
in the maximum aggregate offering price set forth in the
                "Calculation of Registration Fee" table in the effective
                registration statement.

          (iii) To include any material information with respect to the plan of
                distribution not previously disclosed in the registration
                statement or any material change to such information in the
                registration statement;

          Provided, however, That:

               (A)  Paragraphs (a)(1)(i) and (a)(1)(ii) of this section do not
                    apply if the registration statement is on Form S-8 (Section
                    239.16b of this chapter), and the information required to be
                    included in a post-effective amendment by those paragraphs
                    is contained in reports filed with or furnished to the
                    Commission by the registrant pursuant to section 13 or
                    section 15(d) of the Securities Exchange Act of 1934 (15
                    U.S.C. 78m or 78o(d)) that are incorporated by reference in
                    the registration statement; and

               (B)  Paragraphs (a)(1)(i), (a)(1)(ii) and (a)(1)(iii) of this
                    section do not apply if the registration statement is on
                    Form S-3 (Section 239.13 of this chapter) or Form F-3
                    (Section 239.33 of this chapter) and the information
                    required to be included in a post-effective amendment by
                    those paragraphs is contained in reports filed with or
                    furnished to the Commission by the registrant pursuant to
                    section 13 or section 15(d) of the Securities Exchange Act
                    of 1934 that are incorporated by reference in the
                    registration statement, or is contained in a form of
                    prospectus filed pursuant to Rule 424(b) (Section
                    230.424(b) of this chapter) that is part of the registration
                    statement.

               (C)  Provided further, however, that paragraphs (a)(1)(i) and
                    (a)(1)(ii) do not apply if the registration statement is for
                    an offering of asset-backed securities on Form S-1 (Section
                    239.11 of this chapter) or Form S-3 (Section 239.13 of this
                    chapter), and the information required to be included in a
                    post-effective amendment is provided pursuant to Item
                    1100(c) of Regulation AB (Section 229.1100(c)).

     (2)  That, for the purpose of determining any liability under the
          Securities Act of 1933, each such post-effective amendment shall be
          deemed to be a new registration statement relating to the securities
          offered therein, and the offering of such securities at that time
          shall be deemed to be the initial bona fide offering thereof.

     (3)  To remove from registration by means of a post-effective amendment any
          of the securities being registered which remain unsold at the
          termination of the offering.

     (4)  If the registrant is a foreign private issuer, to file a
          post-effective amendment to the registration statement to include any
          financial statements required by "Item 8.A. of Form 20-F (17 CFR
          249.220f)" at the start of any delayed offering or throughout a
          continuous offering. Financial statements and information otherwise
          required by Section 10(a)(3) of the Act need not be furnished,
          provided that the registrant includes in the prospectus, by means of a
          post-effective amendment, financial statements required pursuant to
          this paragraph (a)(4) and other information necessary to ensure that
          all other information in the prospectus is at least as current as the
          date of those financial statements. Notwithstanding the foregoing,
          with respect to registration statements on Form F-3 (Section 239.33
          of this chapter), a post-effective amendment need not be filed to
          include financial statements and information required by Section
          10(a)(3) of the Act or Section 210.3-19 of this chapter if such
          financial statements and information are contained in periodic reports
          filed with or furnished to the Commission by the registrant pursuant
          to section 13 or section 15(d) of the Securities Exchange Act of 1934
          that are incorporated by reference in the Form F-3.

     (5)  That, for the purpose of determining liability under the Securities
          Act of 1933 to any purchaser:

                                        4
(i)  If the registrant is relying on Rule 430B (Section 230.430B of
               this chapter):

               (A)  Each prospectus filed by the registrant pursuant to Rule
                    424(b)(3) (Section 230.424(b)(3) of this chapter) shall be
                    deemed to be part of the registration statement as of the
                    date the filed prospectus was deemed part of and included in
                    the registration statement; and

               (B)  Each prospectus required to be filed pursuant to Rule
                    424(b)(2), (b)(5), or (b)(7) (Section 230.424(b)(2),
                    (b)(5), or (b)(7) of this chapter) as part of a registration
                    statement in reliance on Rule 430B relating to an offering
                    made pursuant to Rule 415(a)(1)(i), (vii), or (x) (Section
                    230.415(a)(1)(i), (vii), or (x) of this chapter) for the
                    purpose of providing the information required by section
                    10(a) of the Securities Act of 1933 shall be deemed to be
                    part of and included in the registration statement as of the
                    earlier of the date such form of prospectus is first used
                    after effectiveness or the date of the first contract of
                    sale of securities in the offering described in the
                    prospectus. As provided in Rule 430B, for liability purposes
                    of the issuer and any person that is at that date an
                    underwriter, such date shall be deemed to be a new effective
                    date of the registration statement relating to the
                    securities in the registration statement to which that
                    prospectus relates, and the offering of such securities at
                    that time shall be deemed to be the initial bona fide
                    offering thereof. Provided, however, that no statement made
                    in a registration statement or prospectus that is part of
                    the registration statement or made in a document
                    incorporated or deemed incorporated by reference into the
                    registration statement or prospectus that is part of the
                    registration statement will, as to a purchaser with a time
                    of contract of sale prior to such effective date, supersede
                    or modify any statement that was made in the registration
                    statement or prospectus that was part of the registration
                    statement or made in any such document immediately prior to
                    such effective date; or

          (ii) If the registrant is subject to Rule 430C (Section 230.430C of
               this chapter), each prospectus filed pursuant to Rule 424(b) as
               part of a registration statement relating to an offering, other
               than registration statements relying on Rule 430B or other than
               prospectuses filed in reliance on Rule 430A (Section 230.430A of
               this chapter), shall be deemed to be part of and included in the
               registration statement as of the date it is first used after
               effectiveness. Provided, however, that no statement made in a
               registration statement or prospectus that is part of the
               registration statement or made in a document incorporated or
               deemed incorporated by reference into the registration statement
               or prospectus that is part of the registration statement will, as
               to a purchaser with a time of contract of sale prior to such
               first use, supersede or modify any statement that was made in the
               registration statement or prospectus that was part of the
               registration statement or made in any such document immediately
               prior to such date of first use.

     (6)  That, for the purpose of determining liability of the registrant under
          the Securities Act of 1933 to any purchaser in the initial
          distribution of the securities:

          The undersigned registrant hereby undertakes that in a primary
          offering of securities of the undersigned registrant pursuant to this
          registration statement, regardless of the underwriting method used to
          sell the securities to the purchaser, if the securities are offered or
          sold to such purchaser by means of any of the following
          communications, the undersigned registrant will be a seller to the
          purchaser and will be considered to offer or sell such securities to
          such purchaser:

          (i)   Any preliminary prospectus or prospectus of the undersigned
                registrant relating to the offering required to be filed
                pursuant to Rule 424 (Section 230.424 of this chapter);

          (ii)  Any free writing prospectus relating to the offering prepared by
                or on behalf of the undersigned registrant or used or referred
                to by the undersigned registrant;

                                        5
(iii) The portion of any other free writing prospectus relating to the
                offering containing material information about the undersigned
                registrant or its securities provided by or on behalf of the
                undersigned registrant; and

          (iv)  Any other communication that is an offer in the offering made by
                the undersigned registrant to the purchaser.

(b)  The undersigned registrant hereby undertakes that, for purposes of
     determining any liability under the Securities Act of 1933, each filing of
     the registrant's annual report pursuant to section 13(a) or section 15(d)
     of the Securities Exchange Act of 1934 (and, where applicable, each filing
     of an employee benefit plan's annual report pursuant to section 15(d) of
     the Securities Exchange Act of 1934) that is incorporated by reference in
     the registration statement shall be deemed to be a new registration
     statement relating to the securities offered therein, and the offering of
     such securities at that time shall be deemed to be the initial bona fide
     offering thereof.

(c)  The undersigned registrant hereby undertakes to supplement the prospectus,
     after the expiration of the subscription period, to set forth the results
     of the subscription offer, the transactions by the underwriters during the
     subscription period, the amount of unsubscribed securities to be purchased
     by the underwriters, and the terms of any subsequent reoffering thereof. If
     any public offering by the underwriters is to be made on terms differing
     from those set forth on the cover page of the prospectus, a post-effective
     amendment will be filed to set forth the terms of such offering.

(d)  The undersigned registrant hereby undertakes (1) to use its best efforts to
     distribute prior to the opening of bids, to prospective bidders,
     underwriters, and dealers, a reasonable number of copies of a prospectus
     which at that time meets the requirements of section 10(a) of the Act, and
     relating to the securities offered at competitive bidding, as contained in
     the registration statement, together with any supplements thereto, and (2)
     to file an amendment to the registration statement reflecting the results
     of bidding, the terms of the reoffering and related matters to the extent
     required by the applicable form, not later than the first use, authorized
     by the issuer after the opening of bids, of a prospectus relating to the
     securities offered at competitive bidding, unless no further public
     offering of such securities by the issuer and no reoffering of such
     securities by the purchasers is proposed to be made.

(e)  The undersigned registrant hereby undertakes to deliver or cause to be
     delivered with the prospectus, to each person to whom the prospectus is
     sent or given, the latest annual report to security holders that is
     incorporated by reference in the prospectus and furnished pursuant to and
     meeting the requirements of Rule 14a-3 or Rule 14c-3 under the Securities
     Exchange Act of 1934; and, where interim financial information required to
     be presented by Article 3 of Regulation S-X are not set forth in the
     prospectus, to deliver, or cause to be delivered to each person to whom the
     prospectus is sent or given, the latest quarterly report that is
     specifically incorporated by reference in the prospectus to provide such
     interim financial information.

(f)  The undersigned registrant hereby undertakes to provide to the underwriter
     at the closing specified in the underwriting agreements certificates in
     such denominations and registered in such names as required by the
     underwriter to permit prompt delivery to each purchaser.

(g)  (1)  The undersigned registrant hereby undertakes as follows: that prior to
          any public reoffering of the securities registered hereunder through
          use of a prospectus which is a part of this registration statement, by
          any person or party who is deemed to be an underwriter within the
          meaning of Rule 145(c), the issuer undertakes that such reoffering
          prospectus will contain the information called for by the applicable
          registration form with respect to reofferings by persons who may be
          deemed underwriters, in addition to the information called for by the
          other Items of the applicable form.

     (2)  The undersigned registrant hereby undertakes that every prospectus (i)
          that is filed pursuant to paragraph (h) (1) immediately preceding, or
          (ii) that purports to meet the requirements of section 10(a)(3) of the
          Act and is used in connection with an offering of securities subject
          to Rule 415 (Section 230.415 of this chapter), will be filed as a
          part of an amendment to the registration statement and will not be
          used until such amendment is effective, and that, for purposes of
          determining any liability under the Securities Act of 1933, each such

                                        6
post-effective amendment shall be deemed to be a new registration
          statement relating to the securities offered therein, and the offering
          of such securities at that time shall be deemed to be the initial bona
          fide offering thereof.

(h)  Insofar as indemnification for liabilities arising under the Securities Act
     of 1933 may be permitted to directors, officers and controlling persons of
     the registrant pursuant to the foregoing provisions, or otherwise, the
     registrant has been advised that in the opinion of the Securities and
     Exchange Commission such indemnification is against public policy as
     expressed in the Act and is, therefore, unenforceable. In the event that a
     claim for indemnification against such liabilities (other than the payment
     by the registrant of expenses incurred or paid by a director, officer or
     controlling person of the registrant in the successful defense of any
     action, suit or proceeding) is asserted by such director, officer or
     controlling person in connection with the securities being registered, the
     registrant will, unless in the opinion of its counsel the matter has been
     settled by controlling precedent, submit to a court of appropriate
     jurisdiction the question whether such indemnification by it is against
     public policy as expressed in the Act and will be governed by the final
     adjudication of such issue.

(i)  The undersigned registrant hereby undertakes that:

     (1)  For purposes of determining any liability under the Securities Act of
          1933, the information omitted from the form of prospectus filed as
          part of this registration statement in reliance upon Rule 430A and
          contained in a form of prospectus filed by the registrant pursuant to
          Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be
          deemed to be part of this registration statement as of the time it was
          declared effective.

     (2)  For the purpose of determining any liability under the Securities Act
          of 1933, each post-effective amendment that contains a form of
          prospectus shall be deemed to be a new registration statement relating
          to the securities offered therein, and the offering of such securities
          at that time shall be deemed to be the initial bona fide offering
          thereof.

(j)  The undersigned registrant hereby undertakes to file an application for the
     purpose of determining the eligibility of the trustee to act under
     subsection (a) of section 310 of the Trust Indenture Act ("Act") in
     accordance with the rules and regulations prescribed by the Commission
     under section 305(b)(2) of the Act.

(k)  The undersigned registrant hereby undertakes that, for purposes of
     determining any liability under the Securities Act of 1933, each filing of
     the annual report pursuant to section 13(a) or section 15(d) of the
     Securities Exchange Act of 1934 of a third party that is incorporated by
     reference in the registration statement in accordance with Item 1100(c)(1)
     of Regulation AB (17 CFR 229.1100(c)(1)) shall be deemed to be a new
     registration statement relating to the securities offered therein, and the
     offering of such securities at that time shall be deemed to be the initial
     bona fide offering thereof.

(l)  The undersigned registrant hereby undertakes that, except as otherwise
     provided by Item 1105 of Regulation AB (17 CFR 229.1105), information
     provided in response to that Item pursuant to Rule 312 of Regulation S-T
     (17 CFR 232.312) through the specified Internet address in the prospectus
     is deemed to be a part of the prospectus included in the registration
     statement. In addition, the undersigned registrant hereby undertakes to
     provide to any person without charge, upon request, a copy of the
     information provided in response to Item 1105 of Regulation AB pursuant to
     Rule 312 of Regulation S-T through the specified Internet address as of the
     date of the prospectus included in the registration statement if a
     subsequent update or change is made to the information.

                                        7
SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the
Registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in Moon Township,
Pennsylvania on October 18, 2006.

                                           ATLAS AMERICA PUBLIC #16-2007 PROGRAM
                                           (Registrant)

                                           By: Atlas Resources, LLC,
                                               Managing General Partner

Jack L. Hollander, pursuant                By: /s/ Jack L. Hollander
to the Registration Statement, has             ---------------------------------
been granted Power of Attorney and is          Jack L. Hollander, Senior Vice
signing on behalf of the names shown           President - Direct Participation
below, in the capacities indicated.            Programs

In accordance with the requirements of the Securities Act of 1933, this
Registration Statement has been signed by the following persons in the
capacities and on the dates indicated.
SIGNATURE                                               Title                                              DATE
---------                                               -----                                              ----
Freddie M. Kotek     President, Chief Executive Officer and Chairman of the Board of Directors     October 18, 2006
Frank P. Carolas     Executive Vice President - Land and Geology and a Director                    October 18, 2006
Jeffrey C. Simmons   Executive Vice President - Operations and a Director                          October 18, 2006
Nancy J. McGurk      Senior Vice President, Chief Financial Officer and Chief Accounting Officer   October 18, 2006
As filed with the Securities and Exchange Commission on October 18, 2006

                                              Registration Number 333-__________

================================================================================

                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                   ----------

                                    EXHIBITS
                                       TO
                                    FORM S-1
                             REGISTRATION STATEMENT
                                      Under
                           THE SECURITIES ACT OF 1933

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                      ATLAS AMERICA PUBLIC #16-2007 PROGRAM
             (Exact name of Registrant as Specified in its Charter)

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    JACK L. HOLLANDER, SENIOR VICE PRESIDENT - DIRECT PARTICIPATION PROGRAMS
                              ATLAS RESOURCES, LLC
               311 ROUSER ROAD, MOON TOWNSHIP, PENNSYLVANIA 15108
                                 (412) 262-2830
           (Name, Address and Telephone Number of Agent for Service)

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                                   Copies to:

WALLACE W. KUNZMAN, JR., ESQ.                  JACK L. HOLLANDER
KUNZMAN & BOLLINGER, INC.                      ATLAS RESOURCES, LLC
5100 N. BROOKLINE, SUITE 600                   311 ROUSER ROAD
OKLAHOMA CITY, OKLAHOMA 73112                  MOON TOWNSHIP, PENNSYLVANIA 15108

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EXHIBIT INDEX

Exhibit No.                               Description
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1(a)          Proposed form of Dealer-Manager Agreement with Anthem Securities,
              Inc.

3(a)          Certificate of Organization of Atlas Resources, LLC

3(b)          Operating Agreement of Atlas Resources, LLC

4(a)          Certificate of Limited Partnership for Atlas America Public
              #16-2007(A) L.P.

4(b)          Certificate of Limited Partnership for Atlas America Public
              #16-2007(B) L.P.

4(d)          Form of Amended and Restated Certificate and Agreement of Limited
              Partnership for Atlas America Public #16-2007(A) L.P. [Form of
              Amended and Restated Certificate and Agreement of Limited
              Partnership for Atlas America Public #16-2007(B) L.P.] (See
              Exhibit (A) to Prospectus)

5             Opinion of Kunzman & Bollinger, Inc. as to the legality of the
              Units

8             Opinion of Kunzman & Bollinger, Inc. as to federal tax matters

10(a)         Escrow Agreement for Atlas America Public #16-2007(A) L.P.

10(b)         Form of Drilling and Operating Agreement for Atlas America Public
              #16-2007(A) L.P. [Atlas America Public #16-2007(B) L.P.] (See
              Exhibit (II) to the Form of Limited Partnership Agreement, Exhibit
              (A) to Prospectus)

10(c)         Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio
              Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas
              Resources, Inc., and Resource Energy, Inc.

10(d)         Guaranty dated August 12, 2003 between First Energy Corp. and
              Atlas Resources, Inc. to Gas Purchase Agreement dated March 31,
              1999 between Northeast Ohio Gas Marketing, Inc., and Atlas Energy
              Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc.

10(e)         Master Natural Gas Gathering Agreement dated February 2, 2000
              among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating
              Partnership, L.P., Atlas America, Inc., Resource Energy, Inc., and
              Viking Resources Corporation

10(f)         Omnibus Agreement dated February 2, 2000 among Atlas America,
              Inc., Resource Energy, Inc., and Viking Resources Corporation, and
              Atlas Pipeline Operating Partnership, L.P., and Atlas Pipeline
              Partners, L.P.

10(g)         Natural Gas Gathering Agreement dated January 1, 2002 among Atlas
              Pipeline Partners, L.P., and Atlas Pipeline Operating Partnership,
              L.P. and Atlas Resources, Inc., and Atlas Energy Group, Inc. and
              Atlas Noble Corporation, and Resource Energy Inc., and Viking
              Resources Corporation

10(h)         Base Contract for Sale and Purchase of Natural Gas dated November
              13, 2002 Between UGI Energy Services, Inc. and Viking Resources
              Corp.

10(i)         Guaranty dated June 1, 2004 between UGI Corporation and Viking
              Resources Corp.

10(j)         Guaranty as of December 7, 2004 between FirstEnergy Corp. and
              Atlas Resources, Inc.

10(k)         Confirmation of Gas Purchase and Sales Agreement dated November
              17, 2004 between Atlas Resources, Inc. et. al. and First Energy
              Solutions Corp. for the period from April 1, 2006 through March
              31, 2007 production/calendar periods

10(l)         Transaction Confirmation dated December 14, 2004 between Atlas
              America, Inc. and UGI Energy Services, Inc. d/b/a GASMARK

10(m)         Drilling and Operating Agreement Dated September 15, 2004 by and
              between Atlas America, Inc. and Knox Energy, LLC

10(n)         Guaranty dated January 1, 2005 between UGI Corporation and Viking
              Resources Corp.

10(o)         Escrow Agreement for Atlas America Public #16-2007(B) L.P.

                                       i
Exhibit No.                               Description
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10(p)         Amendment among Atlas Pipeline Partners, L.P. and Atlas Pipeline
              Operating Partnership, L.P., Atlas America, Inc., Resource Energy,
              Inc., Viking Resources Corporation, Atlas Noble Corp., and Atlas
              Resources, Inc. to the Master Natural Gas Gathering Agreement
              dated February 2, 2000 and the Natural Gas Gathering Agreement
              dated January 1, 2002

23(a)         Consent of Independent Registered Public Accounting Firm

23(b)         Consent of Kunzman & Bollinger, Inc. (See Exhibits 5 and 8)

23(c)         Consent of Wright & Company, Inc.

23(d)         Consent of United Energy Development Consultants, Inc.

24            Power of Attorney

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