8-K

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: August 21, 2006

(Date of earliest event reported)

PG&E CORPORATION

(Exact Name of Registrant as specified in Charter)

California	1-12609	94-3234914
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

One Market, Spear Tower, Suite 2400, San Francisco, California 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 8.01 - Other Events

On August 21, 2006, Pacific Gas and Electric Company (Utility), together with the California Public Utilities Commission’s (CPUC) Division of Ratepayer Advocates, various irrigation districts, the Western Manufactured Housing Communities Association, the Disability Rights Advocates, the California Farm Bureau Federation, Southern California Edison, Southern California Gas Company, San Diego Gas and Electric Company, and the Coalition of California Utility Employees, filed a motion with the CPUC seeking approval of a settlement agreement reached among the parties to resolve all of the issues raised by these parties and all revenue requirement related issues raised by other parties in the Utility’s 2007 General Rate Case (GRC) proceeding pending at the CPUC. In the GRC, the Utility’s requested revenue requirement to become effective January 1, 2007, was based on the costs the Utility forecast it would incur in 2007 to own, operate, and maintain its electric generating, electric distribution, gas distribution, and common and general plant, to perform the transactions necessary to procure electricity for its bundled-service electric customers and to procure gas for its residential and small commercial customers, and to provide customer services to its electric and gas customers.

Time period:  The settlement agreement proposes to set the Utility’s revenue requirements for a four-year period, 2007-2010, rather than for a typical three-year period. Under this proposal, the Utility’s next GRC would be effective January 1, 2011. As further discussed below, the settlement agreement includes a provision for attrition adjustments to be made to authorized revenues in 2008, 2009 and 2010.

Revenue requirements: The settlement agreement proposes that the Utility’s electric and gas service revenue requirements effective January 1, 2007, be set at $2.870 billion for electric distribution, $1.047 billion for gas distribution and $1.010 billion for electric generation operations, for a total of $4.927 billion. This compares to the Utility’s request of $2.991 billion for electric distribution, $1.062 billion for gas distribution, and $1.056 billion for electric generation, for a total of $5.109 billion. The revenue requirement amounts set forth in the settlement agreement reflect an increase of $222.0 million (or 8.4%) in the Utility’s electric distribution revenues, an increase of $20.5 million (or 2%) in gas distribution revenues, and a decrease of $29.8 million (or 2.8%) in generation operation revenues, for an overall increase of $212.7 million (or 4.5%), over the 2006 authorized amounts. This compares to the Utility’s requested increase of $342.8 million (or 12.9%) for electric distribution operations, $35.5 million (or 3.5%) for gas distribution operations, and $16.3 million (or 1.6%) for electric generation operations, for an overall requested increase of $394.5 million (or 8.4%), over 2006 authorized amounts. Under the settlement agreement, the Utility’s revenue requirements are $181 million less than the amount requested. Of this amount, approximately $95 million relates to depreciation expense, approximately $29 million relates to return and taxes associated with rate base, approximately $21 million relates to operating and maintenance expenses and customer service expenses, and approximately $36 million relates to administrative and general expenses, payroll taxes, and other miscellaneous expenses. The following table compares the amounts (in millions of dollars) requested by the Utility and the amounts proposed in the settlement agreement:

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	Amounts requested by the Utility			Amounts included in the settlement agreement			Difference between amounts requested and included in the settlement agreement			Amount of increase/decrease over 2006 authorized amounts
Operation & Maintenance	$	1,093.7		$	1,079.2		$	(14.4	)	$	112.1
Customer Services		437.7			431.1			(6.6	)		6.9
Administrative & General and Other Adjustments		741.5			708.7			(32.8	)		55.2
Payroll Tax, Franchise & Uncollectibles		138.0			134.6			(3.4	)		17.1
Depreciation, Return, & Taxes		2,828.9			2,705.1			(123.8	)		49.9
Subtotal		5,239.8			5,058.8			(181.0	)		241.3
Less: Other Operating Revenue and FERC Allocation		(131.0	)		(131.7	)		(0.9	)		(28.5	)
Total CPUC Billed Revenue		5,108.8			4,927.0			(181.8	)		212.7

    Differences in totals are due to rounding.

Capital Additions: The settlement agreement provides for 2007 net capital additions of $696.3 million for electric distribution, $207.7 million for gas distribution, and $195.0 million for generation operations. The settlement agreement includes 2007 depreciation expenses for electric and gas distribution, and electric generation of $596.8 million, $209.4 million, and $135.4 million, respectively. The parties agreed that the Utility’s estimated 2007 annual average rate base associated with the portions of the utility business reviewed in the GRC is $12.6 billion after deducting the weighted average nuclear fuel inventory of $221.9 million. The parties agreed that, beginning January 1, 2007, the carrying costs related to the nuclear fuel inventory would be recovered through rates as an electricity procurement cost at the short-term interest rate instead of being included in the Utility’s rate base.

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The Utility projects that the amount of revenue requirements provided in the settlement agreement would enable the Utility to make needed improvements in its electric and gas distribution system infrastructure and in its existing electric generation business as planned over the 2007-2010 time period. In addition to these GRC-related capital expenditures, the Utility expects to incur capital expenditures relating to its advanced metering infrastructure, electric and gas transmission upgrades, the replacement of steam generators at the Diablo Canyon nuclear power plant (Diablo Canyon), the repowering of the Humboldt Bay fossil-fueled power plant and the acquisition and development of the 530 megawatt Contra Costa Unit 8 power plant. Total capital expenditures are forecasted to average $2.5 billion annually over the 2007-2010 time period. The forecasted capital expenditures do not include potential additional investments in new generation resources which remain subject to CPUC approval.

Attrition and Estimated Cost Savings: The settlement agreement provides for an attrition adjustment to authorized revenues of $125 million in each of 2008 and 2009. In addition, the Utility would receive a one-time additional amount of $35 million in 2009 for a planned second refueling at Diablo Canyon. The attrition adjustment to authorized revenues for 2010 would be $125 million, less the one-time additional amount of $35 million from 2009, for a net increase of $90 million in 2010. On a comparable basis, the Utility had requested attrition increases of approximately $143 million for 2008 and approximately $180 million for 2009, net of estimated cost savings of $41 million in 2008 and $97 million in 2009 that the Utility estimates would result from the implementation of various initiatives to improve the Utility’s business processes and systems. (The 2009 requested attrition increase of approximately $180 million discussed above equals the approximately $141 million previously disclosed plus the $41 million reduction provided in 2008). Due to uncertainty about savings to be realized from these initiatives, the Utility had proposed a mechanism to share earnings, or shortfalls in earnings, with customers. The settlement agreement does not adopt the Utility’s proposed mechanism. Instead, customers will receive the benefit of cost savings in 2008, 2009 and 2010 associated with the attrition adjustments discussed above. If the actual cost savings exceed these amounts, such benefits would accrue to shareholders. Conversely, if these cost savings are not realized, earnings available for shareholders would be reduced.

Pension Contribution: The settlement agreement includes a pension-related revenue requirement for 2010 of $98.2 million, which equates to a net contribution of $153.4 million for 2010, consistent with the CPUC’s June 15, 2006 decision authorizing the Utility to make annual pension contributions for the years 2007-2009. The Utility would continue to recover the revenue requirement for the portion of the pension contribution authorized for 2010 that is allocable to the Utility’s GRC lines of business. Recovery of the pension-contribution revenue requirement for non-GRC lines of business would be authorized, as appropriate, in other proceedings and venues.

Performance Mechanism: The settlement agreement would not alter the current incentive mechanism for reliability performance. Under the current mechanism, the Utility can be rewarded or penalized by up to $24 million on a pre-tax basis to the extent that the Utility’s actual performance exceeds or falls short of pre-set annual reliability targets. The Utility had proposed a mechanism that would have included rewards or penalties of up to $60 million (pre-tax) to the extent that performance on a combination of operating targets exceeded or fell short of pre-set annual targets.

Schedule: Although the revised GRC schedule provides for a final decision by February 2007, the administrative law judge who issued the revised schedule invited the Utility to file a motion requesting that any revenue requirement change be effective on January 1, 2007, subject to refund. The Utility filed this motion on August 11, 2006.

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PG&E Corporation and the Utility are unable to predict whether the CPUC will approve the settlement agreement.

Item 7.01 - Regulation FD Disclosure

The information included in Exhibit 99 is incorporated by reference in response to this Item 7.01, and is deemed to be furnished, not filed, pursuant to Item 7.01 of Form 8-K.

Attached to this report are presentation slides to be used by PG&E Corporation’s Investor Relations Department and members of senior management in discussions with investors and members of the financial community. These slides describe the proposed settlement agreement. These slides contain forward-looking statements regarding management’s guidance for PG&E Corporation’s 2006 and 2007 earnings per share from operations, as well as forecasted capital expenditures, rate base growth, and targeted average annual growth rate for earnings per share from operations over the 2006-2010 time period. These statements are based on current expectations and various assumptions which management believes are reasonable, including that the settlement agreement reached among parties in the Utility’s GRC proceeding is approved by the CPUC and that the Utility earns its authorized rate of return on equity of 11.35% on forecasted rate base amounts. These statements and assumptions are necessarily subject to various risks and uncertainties, the realization or resolution of which are outside of management's control. Actual results may differ materially. Factors that could cause actual results to differ materially include:

·   Unanticipated changes in operating expenses or capital expenditures, which may affect the Utility’s ability to earn its authorized rate of return;

·   How the Utility manages its responsibility to procure electric capacity and energy for its customers;

·   The adequacy and price of natural gas supplies, and the ability of the Utility to manage and respond to the volatility of the natural gas market for its customers;

·   The operation of the Utility’s Diablo Canyon nuclear power plant, which could cause the Utility to incur potentially significant environmental costs and capital expenditures, and the extent to which the Utility is able to timely increase its spent nuclear fuel storage capacity at Diablo Canyon;

·   Whether the Utility is able to recognize the benefits expected to result from its efforts to improve customer service through implementation of specific initiatives to streamline business processes and deploy new technology;

·   The outcome of proceedings pending at the Federal Energy Regulatory Commission (FERC) and the CPUC, including the Utility’s 2007 GRC and the Utility’s application for approval of new long-term generation resource commitments;

·   How the CPUC administers the capital structure, stand-alone dividend, and first priority conditions of the CPUC’s decisions permitting the establishment of holding companies for the California investor-owned electric utilities, and the outcome of the CPUC's new rulemaking proceeding concerning the relationship between the California investor-owned energy utilities and their holding companies and non-regulated affiliates;

·   The impact of the recently adopted Energy Policy Act of 2005 and future legislative or regulatory actions or policies affecting the energy industry;

·   Increased municipalization and other forms of bypass in the Utility’s service territory; and

·   Other factors discussed in PG&E Corporation's SEC reports.

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Item 9.01 Financial Statements and Exhibits

Exhibits

The following exhibit is being furnished, and is not deemed to be filed:

Exhibit 99   PG&E Corporation investor presentation slides dated August 21, 2006  

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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 hereunto duly authorized.

	PG&E CORPORATION
Dated: August 21, 2006	By:	/s/ G. Robert Powell
		G. ROBERT POWELL Vice President and Controller

	PACIFIC GAS AND ELECTRIC COMPANY
Dated: August 21, 2006	By:	/s/ G. Robert Powell
		G. ROBERT POWELL Vice President and Controller

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EXHIBIT INDEX

No.	Description of Exhibit
Exhibit 99	PG&E Corporation investor presentation slides dated August 21, 2006

EX-99

Exhibit 99

Proposed GRC Settlement, August 21, 2006

This summary contains forward-looking statements regarding management’s guidance for PG&E Corporation’s 2006 and 2007 earnings per share from

operations, capital expenditures, Pacific Gas and Electric Company’s (Utility) rate base and rate base growth, and targeted average annual growth
rate for earnings per share from operations, over the 2006-2010 period. These statements are based on current expectations and various assumptions
which management believes are reasonable, including that substantial capital investments are made in Utility business over the 2006-2010 period and
that the Utility earns an authorized return on equity of 11.35%.  These statements and assumptions are necessarily subject to various risks and
uncertainties the realization or resolution of which are outside of management's control. Actual results may differ materially. Factors that could cause
actual results to differ materially include:

•

If the proposed General Rate Case Settlement is not approved;

•

Unanticipated changes in operating expenses or capital expenditures, which may affect the Utility’s ability to earn its authorized rate of return;

•

How the Utility manages its responsibility to procure electric capacity and energy for its customers;

•

The adequacy and price of natural gas supplies, and the ability of the Utility to manage and respond to the volatility of the natural gas market for its

customers;

•

The operation of the Utility’s Diablo Canyon nuclear power plant, which could cause the Utility to incur potentially significant environmental costs and

capital expenditures, and the extent to which the Utility is able to timely increase its spent nuclear fuel storage capacity at Diablo Canyon;

•

Whether the Utility is able to recognize the anticipated cost benefits and savings to result from its efforts to improve customer service through

implementation of specific initiatives to streamline business processes and deploy new technology;

•

The outcome of proceedings pending at the Federal Energy Regulatory Commission and the California Public Utilities Commission (CPUC),

including the CPUC’s pending investigation into the Utility’s billing and collection practices;

•

How the CPUC administers the capital structure, stand-alone dividend, and first priority conditions of the CPUC’s decisions permitting the

establishment of holding companies for the California investor-owned electric utilities, and the outcome of the CPUC's new rulemaking proceeding
concerning the relationship between the California investor-owned energy utilities and their holding companies and non-regulated affiliates;

•

The impact of the recently adopted Energy Policy Act of 2005 and future legislative or regulatory actions or policies affecting the energy industry; ;

•

Increased municipalization and other forms of bypass in the Utility’s service territory; and

•

Other factors discussed in PG&E Corporation's and Pacific Gas and Electric Company’s SEC reports.

Cautionary Statement Regarding Forward-Looking

Information

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2007 GRC Settlement Summary

The proposed GRC Settlement extends the period until the next General Rate

Case to 2011, and if approved, is consistent with PG&E’s previous EPS guidance
for 2006 and 2007, and overall EPS growth rate of at least 7.5% from 2006-2010.

•

Settlement provides revenue certainty through 2010

–

$213 MM revenue increase vs. $395 MM requested in 2007

–

Attrition base revenue increases of $125 MM in 2008-2010, additive to prior year revenues, w/ an additional

$35 MM in 2009 for a double refueling outage at Diablo Canyon

•

  Transformation Savings

–

$41 MM in 2008, and $97 MM in 2009 are factored into the attrition settlement for the benefit of customers.

–

100% of risk and reward for additional transformation benefits accrue to shareholders through 2010

•

  Next Steps in the Schedule

–

9/20/2006:  Opening Briefs by opposing parties.

–

Jan. 2007:Proposed Decision

–

Feb. 2007:Final Decision (rates effective 1/1/07)

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Distribution Generation Electric Transmission Gas Transmission CC8 AMI Technology Common Plant

Capital expenditures average $2.5B* for years 2006-2010:

($BN)

  2.5            2.8 2.6          2.4                   2.2

*  This excludes  potential additional investment such as the Colusa plant under the RFO, and  additional electric and gas transmission projects

Capital Expenditure Outlook

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*  2006-2010 rate base is not adjusted for the impact of the carrying cost credit that primarily results from the second series of the

Energy Recovery Bonds.   Earnings will be reduced by an amount equal to the deferred tax balance associated with the regulatory
asset, multiplied by the utility's equity ratio and by its equity return.  The carrying cost credit declines to zero as the taxes are fully paid
through 2012.

Rate Base Growth

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