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<title>Form 8-K 12/21/04</title>
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<p align="center"><b>UNITED STATES</b></p>
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<p align="center"><b>SECURITIES AND EXCHANGE COMMISSION</b></p>
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<p align="center"><b>Washington, D.C.&nbsp; 20549</b></p>
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<p><b>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;</b></p>
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<p align="center"><b>FORM 8-K</b></p>
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<p align="center"><b>CURRENT REPORT</b></p>
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<p align="center"><b>Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934</b></p>
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<p><b>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;</b></p>
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<p align="center"><b>Date of Report: December 21, 2004</b></p>

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<b>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;</b></p>
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<p align="center"><b>PG&amp;E CORPORATION</b></p>
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<p align="center"><b>(Exact Name of Registrant as specified in
Charter)</b></p>
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<p align="center"><b><u>California</u></b></p>
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<td colspan="2" valign="top">
<p align="center"><b><u>1-2609</u></b></p>
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<td colspan="2" valign="top">
<p align="center"><b><u>94-323914</u></b></p>
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<p align="center">(State or other jurisdiction of
incorporation)</p>
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<td colspan="2" valign="top">
<p align="center"><br>
 (Commission File Number)</p>
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<p align="center">(IRS Employer<br>
 Identification No.)</p>
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<p align="center"><b><u>One Market, Spear Tower, Suite 2400, San
Francisco, CA</u></b></p>
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<td colspan="3" valign="top">
<p align="center"><b><u>94105</u></b></p>
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<p align="center">(Address of principal executive offices)</p>
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<p align="center">(Zip code)</p>
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<p align="center"><b><u>415-267-7000</u></b></p>
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<p align="center"><b>(Registrant&rsquo;s Telephone Number,
Including Area Code)</b></p>
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<p align="center"><b><u>N/A</u></b></p>
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<p align="center"><b>(Former Name or Former Address, if Changed
Since Last Report)</b></p>
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<p align="center"><b>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;</b></p>
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<p align="center"><b>PACIFIC GAS AND ELECTRIC COMPANY</b></p>
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<p align="center"><b>(Exact Name of Registrant as specified in
Charter)</b></p>
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<p align="center"><b><u>California</u></b></p>
</td>
<td colspan="2" valign="top">
<p align="center"><b><u>1-2348</u></b></p>
</td>
<td colspan="2" valign="top">
<p align="center"><b><u>94-0742640</u></b></p>
</td>
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<p align="center">(State or other jurisdiction of
incorporation)</p>
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<td colspan="2" valign="top">
<p align="center"><br>
 (Commission File Number)</p>
</td>
<td colspan="2" valign="top">
<p align="center">(IRS Employer<br>
 Identification No.)</p>
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<p align="center">&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;</p>
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<td colspan="2" valign="top"></td>
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<p align="center"><b><u>77 Beale Street, P. O. Box 770000, San
Francisco, California</u></b></p>
</td>
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<p align="center"><b><u>94177</u></b></p>
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<td colspan="4" valign="top">
<p align="center">(Address of principal executive offices)</p>
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<p align="center">(Zip code)</p>
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<p align="center"><b><u>(415) 973-7000</u></b></p>
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<p align="center"><b>(Registrant&rsquo;s Telephone Number,
Including Area Code)</b></p>
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<p align="center"><b><u>N/A</u></b></p>
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<td colspan="5" valign="top">
<p align="center"><b>(Former Name or Former Address, if Changed
Since Last Report)</b></p>
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<p><br>
 &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Check
the appropriate box below if the Form 8-K filing is intended to
simultaneously satisfy the filing obligation of the registrant
under any of the following provisions (see General Instruction A.2.
below):</p>
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<p>[&nbsp;]</p>
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<p>&nbsp;&nbsp;&nbsp;</p>
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<p>Written communications pursuant to Rule 425 under the Securities
Act (17 CFR 230.425)</p>
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<p>[&nbsp;]</p>
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<p>Soliciting Material pursuant to Rule 14a-12 under the Exchange
Act (17 CFR 240.14a-12)</p>
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<p>[&nbsp;]</p>
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<p>Pre-commencement communications pursuant to Rule 14d-2(b) under
the Exchange Act<br>
 (17 CFR 240.14d-2(b)</p>
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<p>[&nbsp;]</p>
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<p>Pre-commencement communications pursuant to Rule 13e-4(c) under
the Exchange Act<br>
 (17 CFR 240.13e-4(c))</p>
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<p><b>Item 1.01 &ndash; Entry into a Material Definitive
Agreement</b></p>

<p>A.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Amendments to Non-Qualified
Deferred Compensation Plans</p>

<p>On December 15, 2004, the respective Board of Directors of
PG&amp;E Corporation and Pacific Gas and Electric Company (Utility)
took action with respect to the deferred compensation plans
described below to comply with requirements of the American Jobs
Creation Act signed into law on October 22, 2004 (Act).&nbsp; The
Act generally applies only to amounts deferred in 2005 or
later.&nbsp; It is expected that the U.S. Department of Treasury
will publish guidance by December 22, 2004 on a number of issues
and will issue transition rules before the end of the year to
allow, for a limited period, plans to be amended (a) to permit
cancellation of an existing deferral election applicable to
post-2004 deferrals and (b) to conform with the new guidance for
post-2004 deferrals.&nbsp; The Boards of Directors of PG&amp;E
Corporation and the Utility have delegated to the Chief Executive
Officer of PG&amp;E Corporation and to the Chairman of the Board of
the Utility the authority, within certain parameters, to make such
additional amendments to the deferred compensation plans as may be
necessary to conform to the new rules.</p>

<p><u>PG&amp;E Corporation Supplemental Retirement Savings Plan
(SRSP).&nbsp;</u> The SRSP has been the principal deferred
compensation plan for key employees of PG&amp;E Corporation and the
Utility.&nbsp; As several of the provisions of the SRSP would
not&nbsp; comply with the Act, existing accounts under the SRSP
will be frozen effective December 31, 2004.&nbsp; The rules of the
existing SRSP, including rules with regard to distribution
elections, will generally continue to govern amounts deferred
before January 1, 2005.&nbsp;&nbsp;&nbsp;</p>

<p>The Board of Directors of PG&amp;E Corporation adopted a new
SRSP to become effective as of January 1, 2005.&nbsp; The new SRSP
will allow key employees of PG&amp;E Corporation or the Utility to
defer between 5% to 50% of their salary, and all or a portion of
their bonus payments, perquisite allowances, and certain
performance-based payments under the PG&amp;E Corporation Long-Term
Incentive Program.&nbsp; Participant accounts also are credited
with amounts that cannot be provided through PG&amp;E
Corporation&rsquo;s tax-qualified defined contribution plan (the
PG&amp;E Corporation Retirement Savings Plan), due to legal
limitations associated with highly-compensated employees.&nbsp; The
new SRSP complies with the Act in that the new SRSP requires that
deferral elections generally must be made in the year prior to the
year that services were performed to earn the
compensation.&nbsp;</p>

<p>Amounts credited to participants&rsquo; accounts include gains
or losses attributable to the deemed investment in one or more
deemed investment options, including phantom shares of PG&amp;E
Corporation common stock.&nbsp; The amounts credited to a
participant&rsquo;s account under the SRSP represent an obligation
of PG&amp;E Corporation to make payments to the participant at some
time in the future.&nbsp; PG&amp;E Corporation&rsquo;s deferred
compensation obligations under the SRSP are unsecured general
obligations of PG&amp;E Corporation payable from its general assets
and rank equally with its other unsecured and unsubordinated
indebtedness from time to time outstanding.&nbsp;&nbsp;</p>

<p>Distributions from the new SRSP may generally occur only as
originally selected at the time of deferral at a date or dates
specified or in connection with separation from service.&nbsp; In
addition, distributions are permitted in the event of an
unforeseeable emergency (as defined in the Act).&nbsp; Changes in
distribution elections may only occur within the limits of the
Act.</p>

<p><u>Pacific Gas and Electric Company Supplemental Executive
Retirement Plan (SERP).</u>&nbsp; The Utility SERP is a
non-tax-qualified defined benefit pension plan that provides
officers and key employees of PG&amp;E Corporation and the Utility
with a pension benefit based on a combination of base pay and
annual incentive payments.&nbsp; The Utility SERP benefit is offset
by amounts received from the Utility&rsquo;s tax-qualified defined
benefit pension plan.&nbsp; The Utility SERP differs from the
Utility&rsquo;s tax-qualified defined benefit pension plan in that
it provides a pension based upon a percentage of final pay that
includes bonus payments.&nbsp; To comply with the Act, the Board of
Directors of the Utility has amended the Utility SERP to eliminate
all forms of distribution other than a life annuity option
consistent with the options provided under the tax-qualified
defined benefit pension plan.&nbsp; Distribution elections made
before January 1, 2005 are not affected.&nbsp; The Board of
Directors of PG&amp;E Corporation also has adopted a new SERP that
complies with the Actand has transferred the obligations for
current active employees who participate in the Utility SERP and
for future retirees to PG&amp;E Corporation from the
Utility.&nbsp;</p>

<p><u>PG&amp;E Corporation Officer Severance Policy
(Policy).&nbsp;</u> The Policy provides for a severance benefit for
certain officers of PG&amp;E Corporation and its subsidiaries,
including the Utility, whose employment is severed &ldquo;not for
cause.&rdquo;&nbsp; The benefit is a multiple of base and target
annual incentive, as well as continued vesting of equity awards for
a specified period of time.&nbsp; The Board of Directors of
PG&amp;E Corporation has amended the Policy to provide that, with
respect to terminated officers who are not retirement eligible (age
55), their severance benefit, if sufficient, will be automatically
converted to provide for an immediately payable pension annuity
with the remainder, if any, of the severance benefit paid in a lump
sum.&nbsp; If the severance benefit is insufficient to convert into
an immediately payable pension, or the terminated officer is at
least 55 years old, the entire severance benefit will be paid in a
lump sum.</p>

<p><u>PG&amp;E Corporation Deferred Compensation Plan for
Non-Employee Directors.&nbsp;</u> This plan permits non-employee
directors of PG&amp;E Corporation and the Utility to defer all or a
portion of their retainers and meeting fees.&nbsp; Amounts credited
to participants&rsquo; accounts include gains or losses
attributable to the deemed investment in one or more deemed
investment options, including phantom shares of PG&amp;E
Corporation common stock.&nbsp; The amounts credited to a
participant&rsquo;s account represent an obligation of PG&amp;E
Corporation to make payments to the participant at some time in the
future.&nbsp; PG&amp;E Corporation&rsquo;s deferred compensation
obligations are unsecured general obligations of PG&amp;E
Corporation payable from its general assets and rank equally with
its other unsecured and unsubordinated indebtedness from time to
time outstanding.&nbsp; The Board of Directors has amended this
plan to permit hardship distributions and changes in existing
distribution elections, consistent with the provisions of the
Act.&nbsp;&nbsp; These features also are consistent with the
features included in the new SRSP.&nbsp;</p>

<p>B. &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Approval of 2005 Short Term
Incentive Plan</p>

<p>On December 15, 2004, the Nominating, Compensation and
Governance Committee (Committee) of the PG&amp;E Corporation Board
of Directors approved the structure of the 2005 Short-Term
Incentive Plan (STIP) under which officers of PG&amp;E Corporation
and the Utility are provided an opportunity to receive annual
incentive cash payments.&nbsp; For PG&amp;E Corporation executive
officers, the STIP award will be based entirely on the achievement
of financial objectives, as measured by earnings from
operations.&nbsp; The executive officers of the Utility will have
an opportunity to receive annual cash incentives based on three
criteria:&nbsp; the achievement of financial objectives as measured
by PG&amp;E Corporation&rsquo;s earnings from operations (weighted
25%), the Utility&rsquo;s contribution to PG&amp;E
Corporation&rsquo;s earnings from operations (weighted 50%), and
the success of key strategic initiatives (weighted 25%).&nbsp;
Recommendations as to the specific performance scales for each STIP
award component will be presented for the Committee&rsquo;s action
at its February 2005 meeting.&nbsp; The Committee will continue to
retain full discretion as to the determination of final officer
STIP awards.</p>

<p><b>Item 8.01 Other Events</b></p>

<p>A. &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Final Decision in Cost of
Capital Proceeding</p>

<p>On December 16, 2004, the California Public Utilities Commission
(CPUC) issued a final decision approving a return on common equity
(ROE) for the Utility of 11.22% for 2004 and 2005,which is
consistent with the December 19, 2003 settlement agreement entered
into between the CPUC, the Utility and PG&amp;E Corporation to
resolve the Utility&rsquo;s Chapter 11 proceeding (Settlement
Agreement).&nbsp; The Settlement Agreement provides that, from
January 1, 2004 until certain credit ratings are achieved, the
Utility&rsquo;s authorized ROE will be no less than 11.22% per
year.&nbsp; The Settlement Agreement also provides that the
authorized equity ratio of the Utility&rsquo;s capital structure
for ratemaking purposes will not be less than 52%, except that for
2004 and 2005 it may not be less than 48.6%.&nbsp; The decision
authorizes the following cost of capital for 2004 and 2005:</p>

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<td colspan="3" valign="top">
<p align="center">
<b><u>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2004&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;</u></b></p>
</td>
<td valign="top"></td>
<td colspan="3" valign="top">
<p align="center">
<b><u>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2005&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;</u></b></p>
</td>
</tr>

<tr>
<td valign="top"></td>
<td valign="top"></td>
<td valign="top">
<p align="center"><b>Capital</b></p>
</td>
<td valign="top">
<p align="center"><b>Weighted</b></p>
</td>
<td valign="top"></td>
<td valign="top"></td>
<td valign="top">
<p align="center"><b>Capital</b></p>
</td>
<td valign="top">
<p align="center"><b>Weighted</b></p>
</td>
</tr>

<tr>
<td valign="top"></td>
<td valign="top">
<p align="center"><b><u>Cost</u></b></p>
</td>
<td valign="top">
<p align="center"><b><u>Structure</u></b></p>
</td>
<td valign="top">
<p align="center"><b><u>Cost</u></b></p>
</td>
<td valign="top"></td>
<td valign="top">
<p align="center"><b><u>Cost</u></b></p>
</td>
<td valign="top">
<p align="center"><b><u>Structure</u></b></p>
</td>
<td valign="top">
<p align="center"><b><u>Cost</u></b></p>
</td>
</tr>

<tr>
<td valign="top" style="background-color: #C0C0C0">
<p>Long-term debt</p>
</td>
<td valign="top" style="background-color: #C0C0C0">
<p align="center">5.90%</p>
</td>
<td valign="top" style="background-color: #C0C0C0">
<p align="center">48.2%</p>
</td>
<td valign="top" style="background-color: #C0C0C0">
<p align="center">&nbsp;2.84%</p>
</td>
<td valign="top" style="background-color: #C0C0C0"></td>
<td valign="top" style="background-color: #C0C0C0">
<p align="center">6.10%</p>
</td>
<td valign="top" style="background-color: #C0C0C0">
<p align="center">45.5%</p>
</td>
<td valign="top" style="background-color: #C0C0C0">
<p align="center">2.78%</p>
</td>
</tr>

<tr>
<td valign="top">
<p>Preferred stock</p>
</td>
<td valign="top">
<p align="center">6.76%</p>
</td>
<td valign="top">
<p align="center">&nbsp;2.8%</p>
</td>
<td valign="top">
<p align="center">0.19%</p>
</td>
<td valign="top"></td>
<td valign="top">
<p align="center">6.42%</p>
</td>
<td valign="top">
<p align="center">&nbsp;2.5%</p>
</td>
<td valign="top">
<p align="center">0.16%</p>
</td>
</tr>

<tr>
<td valign="top" style="background-color: #C0C0C0">
<p>Common equity</p>
</td>
<td valign="top" style="background-color: #C0C0C0">
<p align="center">11.22%&nbsp;&nbsp;</p>
</td>
<td valign="top" style="background-color: #C0C0C0">
<p align="center">49.0%</p>
</td>
<td valign="top" style="background-color: #C0C0C0">
<p align="center">5.50%</p>
</td>
<td valign="top" style="background-color: #C0C0C0"></td>
<td valign="top" style="background-color: #C0C0C0">
<p align="center">11.22%&nbsp;</p>
</td>
<td valign="top" style="background-color: #C0C0C0">
<p align="center">52.0%</p>
</td>
<td valign="top" style="background-color: #C0C0C0">
<p align="center">5.83%</p>
</td>
</tr>

<tr>
<td valign="top">
<p>Return on rate base</p>
</td>
<td valign="top"></td>
<td valign="top"></td>
<td valign="top">
<p align="center">8.53%</p>
</td>
<td valign="top"></td>
<td valign="top"></td>
<td valign="top"></td>
<td valign="top">
<p align="center">8.77%</p>
</td>
</tr>
</table>
</div>

<p>As a result of the decision, the Utility&rsquo;s annual revenue
requirement for 2004 has decreased by approximately $109 million
compared to the currently authorized revenue requirement, as a
result of interest savings associated with the Utility&rsquo;s
Chapter 11 exit financing.&nbsp; This decision will not have an
impact on the Utility&rsquo;s financial results for 2004 because
the Utility has previously recorded a reserve against operating
revenues for the difference between its currently authorized rate
of return on rate base of 9.24% and the lower rate of return on
rate base of 8.53% that has now been approved.</p>

<p>The decision also recognizes the importance of assessing and
mitigating the debt equivalence impacts on the Utility&rsquo;s and
the two other California investor-owned electric utilities&rsquo;
(IOUs) credit ratings associated with the long-term financial
obligations under power purchase agreements (PPAs) that the IOUs
will be required to enter into to meet electricity resource
adequacy requirements.&nbsp; Although the decision does not adopt a
formal debt equivalence policy, the CPUC recommends that the IOUs
submit detailed information in their future cost of capital
applications so that the CPUC can assess the debt equivalence
impacts.&nbsp; Additionally, the decision states that the IOUs
should also make recommendations for improving and maintaining
their credit ratings.</p>

<p>B.&nbsp;&nbsp;Final Decision on Long-Term Electricity Resource
Plans</p>

<p>On December 16, 2004, the CPUC issued a final decision which
approved, with certain modifications, each IOU&rsquo;s long-term
electricity procurement plan (LTPP) in order to authorize each IOU
to plan for and procure the resources necessary to provide reliable
service to their customers for the ten-year period 2005-2014.&nbsp;
The decision recognizes that each IOU will have capacity needs over
the ten-year period, especially in 2011 when most of the
electricity purchase contracts entered into by the California
Department of Water Resources (DWR) and allocated to the
IOUs&rsquo; customers expire.&nbsp; The decision states that a
major issue in the proceeding is the extent to which the IOUs will
be compensated for investments or purchases that they must make in
order to meet their obligation to provide reliable service to their
customers, noting that the implementation of community choice
aggregation, departing municipal load, and the potential for
allowing new direct access all create a great degree of uncertainty
as to the amount of load the existing IOUs will be responsible for
serving in the future.&nbsp; The decision includes the following
key points:</p>

<ul type="disc">
<li>The decision finds that the Utility&rsquo;s strategy of adding
1,200 megawatts (MW) of reserve capacity and new peaking generation
in 2008 and an additional 1,000 MW of new peaking and dispatchable
generation in 2010 through requests for offers (RFOs) is reasonable
and compatible with the Utility&rsquo;s resource needs under its
medium preferred case scenario, does not crowd out policy-preferred
resources, and is a reasonable level of commitment given load
uncertainty.&nbsp; However, the decision notes that the
Utility&rsquo;s procurement commitments may need to be increased or
expedited for the Utility to meet the accelerated 2006 resource
adequacy obligations recently approved by the CPUC. <a name=
"_Toc88371728"></a><a name="_Toc88375747"></a><a name=
"_Toc88381443"></a></li>
</ul>

<ul type="disc">
<li>To meet the IOUs&rsquo; resource requirements, the IOUs are
required to solicit bids from providers of all potential sources of
new generation (e.g. conventional or renewable resources to be
provided under turnkey developments, buyouts, or power purchase
agreements (PPAs)) through a single, open, transparentand
competitiveRFO process, although an IOU can tailor a RFO to meet
specific resource needs.&nbsp; In particular, bids for long-term
generation resources (whether PPAs or Utility-owned) would be
evaluated side-by-side.&nbsp; In evaluating bids, the IOUs are
required to:</li>
<li>

<div type="square">
&nbsp;
<ul type="circle">
  <li>procure the maximum amount of renewable generation resources,
and be prepared to defend any selection of fossil-fuel generation
resources over renewable resources,</li>
  <li>employ the Least-Cost Best-Fit methodology when evaluating bids
for PPAs and utility-owned generation resources, taking into
account the qualitative and quantitative attributes (such as
performance risk, credit risk, price diversity, term, and
operational flexibility) associated with each bid, and</li>
  <li>employ a &ldquo;greenhouse gas adder&rdquo; to evaluate
fossil-fuel generation bids as a method to recognize the cost of
greenhouse gas emissions to develop a more accurate price
comparison between fossil-fuel, renewable and demand-side bids (the
greenhouse gas adder would be used for analytical purposes only and
would not be paid to a generator).&nbsp;<br>
  </li>
</ul>
</div>

</li>
<li>When evaluating PPA bids, the IOU is required to employ Standard
&amp; Poor&rsquo;s (S&amp;P&rsquo;s) method of assessing the debt
equivalence impacts on the IOU&rsquo;s credit ratings, but instead
of using 30% of the present value of the fixed capacity payments
due under a PPA as the debt equivalent as S&amp;P&rsquo;s method
does, the factor would be reduced to 20%.&nbsp; As described above
in the description of the final decision in the cost of capital
proceedings, the CPUC will consider the debt equivalence impact of
PPAs on the IOUs' credit ratingsin their future cost of capital
proceedings.<br>
</li>
<li>IOUs are prohibited from recovering initial capital costs in
excess of their final bid price for utility-owned generation
resources.&nbsp; If final project costs are less than the final bid
price, the savings would be shared with ratepayers and any cost
overruns would be absorbed by the IOUs.&nbsp; Costs of future plant
additions and annual operating and maintenance costs and similar
costs incurred by an IOU would be eligible for cost-of service
ratemaking treatment.</li>
</ul>

<ul type="disc">
<li>Affiliates of the IOUs are permitted to participate in the
bidding process for long-term generation resources, subject to
certain guidelines and safeguards, including a requirement that the
IOUs use an independent third party evaluator in resource
solicitations where there are bids that involve affiliates or
IOU-built or IOU-turnkey development projects.&nbsp; The
independent evaluator will not be able to make binding decisions on
behalf of the IOUs.&nbsp;</li>
</ul>

<ul type="disc">
<li>IOUs are permitted to recover their net stranded costs of all
new fossil-fuel and renewable generation resources from all
customers, including departing customers, for a period of 10 years
or the life of the PPA, whichever is less, provided that the CPUC
will allow the IOUs an opportunity to justify a longer recovery
period on a case-by-case basis.&nbsp; The 10-year recovery limit
will not apply to stranded costs that may be incurred under
renewable energy contracts entered into by an IOU to achieve its
target under the Renewables Portfolio Standard, but, unless a
longer recovery period is justified by the IOU, the ten-year
recovery period limit will apply to PPAs for renewable energy
entered into as a result of an open all-source RFO process.&nbsp;
IOUs are required to take appropriate steps to minimize potential
stranded costs by selling excess energy and capacity needs into the
marketplace and crediting the revenues from these sales against the
IOUs&rsquo; costs.</li>
</ul>

<ul type="disc">
<li>The mandatory rate adjustment mechanism under California
Assembly Bill 57 (AB 57), which otherwise would cease on January 1,
2006, has been extended to the length of a resource commitment or
10 years, whichever is longer.&nbsp; Under the mandatory rate
adjustment mechanism the CPUC is required to review the revenues
and costs associated with an IOU&rsquo;s electricity procurement
plan at least semi-annually and adjust retail electricity rates or
order refunds, as appropriate, when the forecast aggregate
over-collections or under-collections exceed 5% of the IOU&rsquo;s
prior year electricity procurement revenues, excluding amounts
collected for the DWR.&nbsp;</li>
</ul>

<ul type="disc">
<li>With respect to the IOUs&rsquo; contracting authority, the
decision permits the IOUs to enter into short-term, mid-term and
long-term contracts with starting delivery dates through 2014,
provided the IOUs submit necessary compliance filings and provided
that contracts with terms five years or longer are submitted to the
CPUC for pre-approval.&nbsp; The decision adopts a rolling 10-year
procurement period, noting that the LTPs cover a 10-year period and
will be updated and reviewed every 2 years.&nbsp; The decision
grants the Utility&rsquo;s petition for modification of its
existing short-term procurement plan to permit the IOUs to conduct
procurement using negotiated bilateral agreements for transactions
up to 3 calendar months, or one quarter, forward.&nbsp; The
decision notes that ultimately the CPUC will eliminate short-term
procurement plans and the IOUs will act in accordance with a single
CPUC-approved plan; but until then, the IOUs&rsquo; existing
short-term plans remain in effect and any updates or modifications
should be filed with an advice letter within 30 days after the
issuance of the decision.&nbsp; The decision requires the IOUs to
submit a compliance filing updating their procurement plans to
reflect the changes and modifications in the decision by March 25,
2005.</li>
</ul>

<ul type="disc">
<li>The decision directs the IOUs to meet CPUC-mandated energy
efficiency goals over the 10-year&nbsp; period, but does not
authorize the $245 million incremental revenue requirement
requested by the Utility to fund energy efficiency programs for
2006 through 2008.&nbsp; Instead, the decision defers this issue
for consideration in the CPUC&rsquo;s energy efficiency rulemaking
proceeding.</li>
</ul>

<ul type="disc">
<li>The decision denies the Utility&rsquo;s request to clarify that
the maximum annual procurement disallowance established by the CPUC
for the Utility&rsquo;s administration of the DWR allocated
contracts and least-cost dispatch of its electricity resources of
two times the Utility&rsquo;s administration costs of managing
procurement activities, be extended to the Utility&rsquo;s
administration of all utility dispatch, including allocated DWR
contracts and administrative and dispatch costs related to
utility-owned generation and other PPAs.</li>
</ul>

<p>C.&nbsp;&nbsp;Final Decision in the Utility&rsquo;s Gas Accord
III</p>

<p>Also, on December 16, 2004, the CPUC issued a final decision
approving the Gas Accord III Settlement Agreement which: resolves
all issues in this proceeding; sets the Utility&rsquo;s gas
transmission and storage rates and market structure for a
three-year term, commencing January 1, 2005; and provides a gas
transmission and storage revenue requirement of $428.5 million for
2005 (as compared to an authorized revenue requirement of $ 427.8
million for 2004), $436.6 million for 2006, and $444.9 million for
2007.&nbsp;</p>

<p>D.&nbsp;&nbsp;Annual Electric Rate True-Up</p>

<p>Also, on December 16, 2004, the CPUC approved the
Utility&rsquo;s first annual electric rate true-up to adjust rates
for over- and undercollections in the Utility&rsquo;s major
electricity balancing accounts (including the Utility&rsquo;s
electricity procurement cost balancing account), establish the 2005
revenue requirement to amortize the regulatory asset established
under the Settlement Agreement, and consolidate other CPUC and
Federal Energy Regulatory Commission (FERC)authorized electric
revenue requirement changes that are also effective on January 1,
2005, including the changes authorized in the cost of capital
proceeding.&nbsp; It is expected that these rate changes will
result in an increase in 2005 electric revenues of approximately
$300 million.&nbsp; Additional rate changes will be made in the
future to reflect the issuance of energy recovery bonds to
refinance the regulatory asset established under the Settlement
Agreement, as well as to reflect the outcome of other regulatory
proceedings.</p>

<br clear="all">


<div align="center">
<hr size="2" width="624" align="center">
</div>

<table border="0" cellspacing="0" cellpadding="0" width="624">
<tr>
<td valign="top">
<p align="center">&nbsp; SIGNATURE</p>
</td>
</tr>

<tr>
<td valign="top">
<p>&nbsp;</p>
</td>
</tr>

<tr>
<td valign="top">
<p>Pursuant to the requirements of the Securities Exchange Act of
1934, the registrants have duly caused this report to be signed on
their behalf by the undersigned thereunto duly authorized.</p>

<p>&nbsp;</p>
</td>
</tr>
</table>

<table border="0" cellspacing="0" cellpadding="0">
<tr>
<td valign="top">
<p>&nbsp;</p>
</td>
<td colspan="2" valign="top">
<p>PG&amp;E CORPORATION</p>
</td>
</tr>

<tr>
<td valign="top"></td>
<td valign="top"></td>
<td valign="top">
<p>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;</p>
</td>
</tr>

<tr>
<td valign="top">
<p>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;</p>
</td>
<td valign="top">
<p>By:&nbsp;&nbsp;</p>
</td>
<td valign="top">
<div style="width: 259; height: 21">
<p><u>CHRISTOPHER P. JOHNS&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;</u></p>
</div>
</td>
</tr>

<tr>
<td valign="top">
<p>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;</p>
</td>
<td valign="top"></td>
<td valign="top">
<p>Christopher P. Johns<br>
 Senior Vice President and Controller</p>

<p><br>
</p>
</td>
</tr>

<tr>
<td valign="top"></td>
<td colspan="2" valign="top">
<p>PACIFIC GAS AND ELECTRIC COMPANY</p>
</td>
</tr>

<tr>
<td valign="top">
<p>&nbsp;</p>
</td>
<td valign="top"></td>
<td valign="top">
<p>&nbsp;&nbsp;&nbsp;&nbsp;</p>
</td>
</tr>

<tr>
<td valign="top">
<p>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;</p>
</td>
<td valign="top">
<p>By:&nbsp;&nbsp;</p>
</td>
<td valign="top">
<div>
<p><u>DINYAR B. MISTRY&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;</u></p>
</div>
</td>
</tr>

<tr>
<td valign="top">
<p>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;</p>
</td>
<td valign="top"></td>
<td valign="top">
<p>Dinyar B. Mistry<br>
 Vice President and Controller<br>
</p>
</td>
</tr>
</table>

<p>Dated:&nbsp; December 21, 2004</p>
</div>
</body>
</html>
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{"company-data": {"conformed-name": "PACIFIC GAS & ELECTRIC CO", "cik": "0000075488", "assigned-sic": "4931", "irs-number": "940742640", "state-of-incorporation": "CA", "fiscal-year-end": "1231"}, "filing-values": {"form-type": "8-K", "act": "34", "file-number": "001-02348", "film-number": "041218299"}, "business-address": {"street1": "77 BEALE ST", "street2": "P O BOX 770000", "city": "SAN FRANCISCO", "state": "CA", "zip": "94177", "phone": "4152677000"}, "mail-address": {"street1": "77 BEALE STREET", "street2": "P O BOX 770000", "city": "SAN FRANCISCO", "state": "CA", "zip": "94177"}}
Form 8-K 12/21/04
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Date of Report: December 21, 2004
PG&E CORPORATION
(Exact Name of Registrant as specified in
Charter)
California
1-2609
94-323914
(State or other jurisdiction of
incorporation)
(Commission File Number)
(IRS Employer
Identification No.)
One Market, Spear Tower, Suite 2400, San
Francisco, CA
94105
(Address of principal executive offices)
(Zip code)
415-267-7000
(Registrant's Telephone Number,
Including Area Code)
N/A
(Former Name or Former Address, if Changed
Since Last Report)
PACIFIC GAS AND ELECTRIC COMPANY
(Exact Name of Registrant as specified in
Charter)
California
1-2348
94-0742640
(State or other jurisdiction of
incorporation)
(Commission File Number)
(IRS Employer
Identification No.)
77 Beale Street, P. O. Box 770000, San
Francisco, California
94177
(Address of principal executive offices)
(Zip code)
(415) 973-7000
(Registrant's Telephone Number,
Including Area Code)
N/A
(Former Name or Former Address, if Changed
Since Last Report)
Check
the appropriate box below if the Form 8-K filing is intended to
simultaneously satisfy the filing obligation of the registrant
under any of the following provisions (see General Instruction A.2.
below):
[ ]
Written communications pursuant to Rule 425 under the Securities
Act (17 CFR 230.425)
[ ]
Soliciting Material pursuant to Rule 14a-12 under the Exchange
Act (17 CFR 240.14a-12)
[ ]
Pre-commencement communications pursuant to Rule 14d-2(b) under
the Exchange Act
(17 CFR 240.14d-2(b)
[ ]
Pre-commencement communications pursuant to Rule 13e-4(c) under
the Exchange Act
(17 CFR 240.13e-4(c))
Item 1.01 – Entry into a Material Definitive
Agreement
A.     Amendments to Non-Qualified
Deferred Compensation Plans
On December 15, 2004, the respective Board of Directors of
PG&E Corporation and Pacific Gas and Electric Company (Utility)
took action with respect to the deferred compensation plans
described below to comply with requirements of the American Jobs
Creation Act signed into law on October 22, 2004 (Act).  The
Act generally applies only to amounts deferred in 2005 or
later.  It is expected that the U.S. Department of Treasury
will publish guidance by December 22, 2004 on a number of issues
and will issue transition rules before the end of the year to
allow, for a limited period, plans to be amended (a) to permit
cancellation of an existing deferral election applicable to
post-2004 deferrals and (b) to conform with the new guidance for
post-2004 deferrals.  The Boards of Directors of PG&E
Corporation and the Utility have delegated to the Chief Executive
Officer of PG&E Corporation and to the Chairman of the Board of
the Utility the authority, within certain parameters, to make such
additional amendments to the deferred compensation plans as may be
necessary to conform to the new rules.
PG&E Corporation Supplemental Retirement Savings Plan
(SRSP).
The SRSP has been the principal deferred
compensation plan for key employees of PG&E Corporation and the
Utility.  As several of the provisions of the SRSP would
not  comply with the Act, existing accounts under the SRSP
will be frozen effective December 31, 2004.  The rules of the
existing SRSP, including rules with regard to distribution
elections, will generally continue to govern amounts deferred
before January 1, 2005.
The Board of Directors of PG&E Corporation adopted a new
SRSP to become effective as of January 1, 2005.  The new SRSP
will allow key employees of PG&E Corporation or the Utility to
defer between 5% to 50% of their salary, and all or a portion of
their bonus payments, perquisite allowances, and certain
performance-based payments under the PG&E Corporation Long-Term
Incentive Program.  Participant accounts also are credited
with amounts that cannot be provided through PG&E
Corporation's tax-qualified defined contribution plan (the
PG&E Corporation Retirement Savings Plan), due to legal
limitations associated with highly-compensated employees.  The
new SRSP complies with the Act in that the new SRSP requires that
deferral elections generally must be made in the year prior to the
year that services were performed to earn the
compensation.
Amounts credited to participants' accounts include gains
or losses attributable to the deemed investment in one or more
deemed investment options, including phantom shares of PG&E
Corporation common stock.  The amounts credited to a
participant's account under the SRSP represent an obligation
of PG&E Corporation to make payments to the participant at some
time in the future.  PG&E Corporation's deferred
compensation obligations under the SRSP are unsecured general
obligations of PG&E Corporation payable from its general assets
and rank equally with its other unsecured and unsubordinated
indebtedness from time to time outstanding.
Distributions from the new SRSP may generally occur only as
originally selected at the time of deferral at a date or dates
specified or in connection with separation from service.  In
addition, distributions are permitted in the event of an
unforeseeable emergency (as defined in the Act).  Changes in
distribution elections may only occur within the limits of the
Act.
Pacific Gas and Electric Company Supplemental Executive
Retirement Plan (SERP).
The Utility SERP is a
non-tax-qualified defined benefit pension plan that provides
officers and key employees of PG&E Corporation and the Utility
with a pension benefit based on a combination of base pay and
annual incentive payments.  The Utility SERP benefit is offset
by amounts received from the Utility's tax-qualified defined
benefit pension plan.  The Utility SERP differs from the
Utility's tax-qualified defined benefit pension plan in that
it provides a pension based upon a percentage of final pay that
includes bonus payments.  To comply with the Act, the Board of
Directors of the Utility has amended the Utility SERP to eliminate
all forms of distribution other than a life annuity option
consistent with the options provided under the tax-qualified
defined benefit pension plan.  Distribution elections made
before January 1, 2005 are not affected.  The Board of
Directors of PG&E Corporation also has adopted a new SERP that
complies with the Actand has transferred the obligations for
current active employees who participate in the Utility SERP and
for future retirees to PG&E Corporation from the
Utility.
PG&E Corporation Officer Severance Policy
(Policy).
The Policy provides for a severance benefit for
certain officers of PG&E Corporation and its subsidiaries,
including the Utility, whose employment is severed "not for
cause."  The benefit is a multiple of base and target
annual incentive, as well as continued vesting of equity awards for
a specified period of time.  The Board of Directors of
PG&E Corporation has amended the Policy to provide that, with
respect to terminated officers who are not retirement eligible (age
55), their severance benefit, if sufficient, will be automatically
converted to provide for an immediately payable pension annuity
with the remainder, if any, of the severance benefit paid in a lump
sum.  If the severance benefit is insufficient to convert into
an immediately payable pension, or the terminated officer is at
least 55 years old, the entire severance benefit will be paid in a
lump sum.
PG&E Corporation Deferred Compensation Plan for
Non-Employee Directors.
This plan permits non-employee
directors of PG&E Corporation and the Utility to defer all or a
portion of their retainers and meeting fees.  Amounts credited
to participants' accounts include gains or losses
attributable to the deemed investment in one or more deemed
investment options, including phantom shares of PG&E
Corporation common stock.  The amounts credited to a
participant's account represent an obligation of PG&E
Corporation to make payments to the participant at some time in the
future.  PG&E Corporation's deferred compensation
obligations are unsecured general obligations of PG&E
Corporation payable from its general assets and rank equally with
its other unsecured and unsubordinated indebtedness from time to
time outstanding.  The Board of Directors has amended this
plan to permit hardship distributions and changes in existing
distribution elections, consistent with the provisions of the
Act.   These features also are consistent with the
features included in the new SRSP.
B.      Approval of 2005 Short Term
Incentive Plan
On December 15, 2004, the Nominating, Compensation and
Governance Committee (Committee) of the PG&E Corporation Board
of Directors approved the structure of the 2005 Short-Term
Incentive Plan (STIP) under which officers of PG&E Corporation
and the Utility are provided an opportunity to receive annual
incentive cash payments.  For PG&E Corporation executive
officers, the STIP award will be based entirely on the achievement
of financial objectives, as measured by earnings from
operations.  The executive officers of the Utility will have
an opportunity to receive annual cash incentives based on three
criteria:  the achievement of financial objectives as measured
by PG&E Corporation's earnings from operations (weighted
25%), the Utility's contribution to PG&E
Corporation's earnings from operations (weighted 50%), and
the success of key strategic initiatives (weighted 25%). 
Recommendations as to the specific performance scales for each STIP
award component will be presented for the Committee's action
at its February 2005 meeting.  The Committee will continue to
retain full discretion as to the determination of final officer
STIP awards.
Item 8.01 Other Events
A.      Final Decision in Cost of
Capital Proceeding
On December 16, 2004, the California Public Utilities Commission
(CPUC) issued a final decision approving a return on common equity
(ROE) for the Utility of 11.22% for 2004 and 2005,which is
consistent with the December 19, 2003 settlement agreement entered
into between the CPUC, the Utility and PG&E Corporation to
resolve the Utility's Chapter 11 proceeding (Settlement
Agreement).  The Settlement Agreement provides that, from
January 1, 2004 until certain credit ratings are achieved, the
Utility's authorized ROE will be no less than 11.22% per
year.  The Settlement Agreement also provides that the
authorized equity ratio of the Utility's capital structure
for ratemaking purposes will not be less than 52%, except that for
2004 and 2005 it may not be less than 48.6%.  The decision
authorizes the following cost of capital for 2004 and 2005:
2004
2005
Capital
Weighted
Capital
Weighted
Cost
Structure
Cost
Cost
Structure
Cost
Long-term debt
5.90%
48.2%
2.84%
6.10%
45.5%
2.78%
Preferred stock
6.76%
2.8%
0.19%
6.42%
2.5%
0.16%
Common equity
11.22%
49.0%
5.50%
11.22%
52.0%
5.83%
Return on rate base
8.53%
8.77%
As a result of the decision, the Utility's annual revenue
requirement for 2004 has decreased by approximately $109 million
compared to the currently authorized revenue requirement, as a
result of interest savings associated with the Utility's
Chapter 11 exit financing.  This decision will not have an
impact on the Utility's financial results for 2004 because
the Utility has previously recorded a reserve against operating
revenues for the difference between its currently authorized rate
of return on rate base of 9.24% and the lower rate of return on
rate base of 8.53% that has now been approved.
The decision also recognizes the importance of assessing and
mitigating the debt equivalence impacts on the Utility's and
the two other California investor-owned electric utilities'
(IOUs) credit ratings associated with the long-term financial
obligations under power purchase agreements (PPAs) that the IOUs
will be required to enter into to meet electricity resource
adequacy requirements.  Although the decision does not adopt a
formal debt equivalence policy, the CPUC recommends that the IOUs
submit detailed information in their future cost of capital
applications so that the CPUC can assess the debt equivalence
impacts.  Additionally, the decision states that the IOUs
should also make recommendations for improving and maintaining
their credit ratings.
B.  Final Decision on Long-Term Electricity Resource
Plans
On December 16, 2004, the CPUC issued a final decision which
approved, with certain modifications, each IOU's long-term
electricity procurement plan (LTPP) in order to authorize each IOU
to plan for and procure the resources necessary to provide reliable
service to their customers for the ten-year period 2005-2014. 
The decision recognizes that each IOU will have capacity needs over
the ten-year period, especially in 2011 when most of the
electricity purchase contracts entered into by the California
Department of Water Resources (DWR) and allocated to the
IOUs' customers expire.  The decision states that a
major issue in the proceeding is the extent to which the IOUs will
be compensated for investments or purchases that they must make in
order to meet their obligation to provide reliable service to their
customers, noting that the implementation of community choice
aggregation, departing municipal load, and the potential for
allowing new direct access all create a great degree of uncertainty
as to the amount of load the existing IOUs will be responsible for
serving in the future.  The decision includes the following
key points:
The decision finds that the Utility's strategy of adding
1,200 megawatts (MW) of reserve capacity and new peaking generation
in 2008 and an additional 1,000 MW of new peaking and dispatchable
generation in 2010 through requests for offers (RFOs) is reasonable
and compatible with the Utility's resource needs under its
medium preferred case scenario, does not crowd out policy-preferred
resources, and is a reasonable level of commitment given load
uncertainty.  However, the decision notes that the
Utility's procurement commitments may need to be increased or
expedited for the Utility to meet the accelerated 2006 resource
adequacy obligations recently approved by the CPUC.
To meet the IOUs' resource requirements, the IOUs are
required to solicit bids from providers of all potential sources of
new generation (e.g. conventional or renewable resources to be
provided under turnkey developments, buyouts, or power purchase
agreements (PPAs)) through a single, open, transparentand
competitiveRFO process, although an IOU can tailor a RFO to meet
specific resource needs.  In particular, bids for long-term
generation resources (whether PPAs or Utility-owned) would be
evaluated side-by-side.  In evaluating bids, the IOUs are
required to:
procure the maximum amount of renewable generation resources,
and be prepared to defend any selection of fossil-fuel generation
resources over renewable resources,
employ the Least-Cost Best-Fit methodology when evaluating bids
for PPAs and utility-owned generation resources, taking into
account the qualitative and quantitative attributes (such as
performance risk, credit risk, price diversity, term, and
operational flexibility) associated with each bid, and
employ a "greenhouse gas adder" to evaluate
fossil-fuel generation bids as a method to recognize the cost of
greenhouse gas emissions to develop a more accurate price
comparison between fossil-fuel, renewable and demand-side bids (the
greenhouse gas adder would be used for analytical purposes only and
would not be paid to a generator).
When evaluating PPA bids, the IOU is required to employ Standard
& Poor's (S&P's) method of assessing the debt
equivalence impacts on the IOU's credit ratings, but instead
of using 30% of the present value of the fixed capacity payments
due under a PPA as the debt equivalent as S&P's method
does, the factor would be reduced to 20%.  As described above
in the description of the final decision in the cost of capital
proceedings, the CPUC will consider the debt equivalence impact of
PPAs on the IOUs' credit ratingsin their future cost of capital
proceedings.
IOUs are prohibited from recovering initial capital costs in
excess of their final bid price for utility-owned generation
resources.  If final project costs are less than the final bid
price, the savings would be shared with ratepayers and any cost
overruns would be absorbed by the IOUs.  Costs of future plant
additions and annual operating and maintenance costs and similar
costs incurred by an IOU would be eligible for cost-of service
ratemaking treatment.
Affiliates of the IOUs are permitted to participate in the
bidding process for long-term generation resources, subject to
certain guidelines and safeguards, including a requirement that the
IOUs use an independent third party evaluator in resource
solicitations where there are bids that involve affiliates or
IOU-built or IOU-turnkey development projects.  The
independent evaluator will not be able to make binding decisions on
behalf of the IOUs.
IOUs are permitted to recover their net stranded costs of all
new fossil-fuel and renewable generation resources from all
customers, including departing customers, for a period of 10 years
or the life of the PPA, whichever is less, provided that the CPUC
will allow the IOUs an opportunity to justify a longer recovery
period on a case-by-case basis.  The 10-year recovery limit
will not apply to stranded costs that may be incurred under
renewable energy contracts entered into by an IOU to achieve its
target under the Renewables Portfolio Standard, but, unless a
longer recovery period is justified by the IOU, the ten-year
recovery period limit will apply to PPAs for renewable energy
entered into as a result of an open all-source RFO process. 
IOUs are required to take appropriate steps to minimize potential
stranded costs by selling excess energy and capacity needs into the
marketplace and crediting the revenues from these sales against the
IOUs' costs.
The mandatory rate adjustment mechanism under California
Assembly Bill 57 (AB 57), which otherwise would cease on January 1,
2006, has been extended to the length of a resource commitment or
10 years, whichever is longer.  Under the mandatory rate
adjustment mechanism the CPUC is required to review the revenues
and costs associated with an IOU's electricity procurement
plan at least semi-annually and adjust retail electricity rates or
order refunds, as appropriate, when the forecast aggregate
over-collections or under-collections exceed 5% of the IOU's
prior year electricity procurement revenues, excluding amounts
collected for the DWR.
With respect to the IOUs' contracting authority, the
decision permits the IOUs to enter into short-term, mid-term and
long-term contracts with starting delivery dates through 2014,
provided the IOUs submit necessary compliance filings and provided
that contracts with terms five years or longer are submitted to the
CPUC for pre-approval.  The decision adopts a rolling 10-year
procurement period, noting that the LTPs cover a 10-year period and
will be updated and reviewed every 2 years.  The decision
grants the Utility's petition for modification of its
existing short-term procurement plan to permit the IOUs to conduct
procurement using negotiated bilateral agreements for transactions
up to 3 calendar months, or one quarter, forward.  The
decision notes that ultimately the CPUC will eliminate short-term
procurement plans and the IOUs will act in accordance with a single
CPUC-approved plan; but until then, the IOUs' existing
short-term plans remain in effect and any updates or modifications
should be filed with an advice letter within 30 days after the
issuance of the decision.  The decision requires the IOUs to
submit a compliance filing updating their procurement plans to
reflect the changes and modifications in the decision by March 25,
2005.
The decision directs the IOUs to meet CPUC-mandated energy
efficiency goals over the 10-year  period, but does not
authorize the $245 million incremental revenue requirement
requested by the Utility to fund energy efficiency programs for
2006 through 2008.  Instead, the decision defers this issue
for consideration in the CPUC's energy efficiency rulemaking
proceeding.
The decision denies the Utility's request to clarify that
the maximum annual procurement disallowance established by the CPUC
for the Utility's administration of the DWR allocated
contracts and least-cost dispatch of its electricity resources of
two times the Utility's administration costs of managing
procurement activities, be extended to the Utility's
administration of all utility dispatch, including allocated DWR
contracts and administrative and dispatch costs related to
utility-owned generation and other PPAs.
C.  Final Decision in the Utility's Gas Accord
III
Also, on December 16, 2004, the CPUC issued a final decision
approving the Gas Accord III Settlement Agreement which: resolves
all issues in this proceeding; sets the Utility's gas
transmission and storage rates and market structure for a
three-year term, commencing January 1, 2005; and provides a gas
transmission and storage revenue requirement of $428.5 million for
2005 (as compared to an authorized revenue requirement of $ 427.8
million for 2004), $436.6 million for 2006, and $444.9 million for
2007.
D.  Annual Electric Rate True-Up
Also, on December 16, 2004, the CPUC approved the
Utility's first annual electric rate true-up to adjust rates
for over- and undercollections in the Utility's major
electricity balancing accounts (including the Utility's
electricity procurement cost balancing account), establish the 2005
revenue requirement to amortize the regulatory asset established
under the Settlement Agreement, and consolidate other CPUC and
Federal Energy Regulatory Commission (FERC)authorized electric
revenue requirement changes that are also effective on January 1,
2005, including the changes authorized in the cost of capital
proceeding.  It is expected that these rate changes will
result in an increase in 2005 electric revenues of approximately
$300 million.  Additional rate changes will be made in the
future to reflect the issuance of energy recovery bonds to
refinance the regulatory asset established under the Settlement
Agreement, as well as to reflect the outcome of other regulatory
proceedings.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrants have duly caused this report to be signed on
their behalf by the undersigned thereunto duly authorized.
PG&E CORPORATION
By:
CHRISTOPHER P. JOHNS
Christopher P. Johns
Senior Vice President and Controller
PACIFIC GAS AND ELECTRIC COMPANY
By:
DINYAR B. MISTRY
Dinyar B. Mistry
Vice President and Controller
Dated:  December 21, 2004