10-14-03 Form 8-K

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: October 14, 2003


Commission File Number	Exact Name of Registrant as specified in its charter	State or other Jurisdiction of Incorporation	IRS Employer Identification Number
_____________	_____________	_____________	_____________
1-12609 1-2348	PG&E Corporation Pacific Gas and Electric Company	California California	94-3234914 94-0742640

Pacific Gas and Electric Company 77 Beale Street, P. O. Box 770000 San Francisco, California 94177		PG&E Corporation One Market, Spear Tower, Suite 2400 San Francisco, California 94105

(Address of principal executive offices) (Zip Code)

Pacific Gas and Electric Company (415) 973-7000		PG&E Corporation (415) 267-7000

(Registrant's telephone number, including area code)

Inapplicable

(Former Name or Former Address, if Changed Since Last Report)

Item 5. Other Events

As previously disclosed, in January 2002, the California Attorney General (AG) filed a complaint in the San Francisco Superior Court against PG&E Corporation and its directors, as well as against the directors of Pacific Gas and Electric Company (Utility), based on allegations of unlawful, unfair or fraudulent business acts or practices in violation of California Business and Professions Code Section 17200 (Section 17200). Among other allegations, the AG alleged that past transfers of money from the Utility to PG&E Corporation, and allegedly from PG&E Corporation to other affiliates of PG&E Corporation, violated various conditions established by the California Public Utilities Commission (CPUC) in decisions approving the holding company formation. The AG also challenged PG&E Corporation’s alleged failure to infuse the Utility with cash. Similar complaints were filed in February 2002 against PG&E Corporation by the City and County of San Francisco in San Francisco Superior Court, and against PG&E Corporation, its directors, and the Utility’s directors by Cynthia Behr, a private plaintiff, in Santa Clara Superior Court. The AG and the City and County of San Francisco requested restitution of assets allegedly wrongfully transferred to PG&E Corporation from the Utility, civil penalties, and injunctive relief, among other remedies. The three cases were later designated as complex proceedings and coordinated in the San Francisco Superior Court, where they are pending currently.

The defendants removed all three lawsuits to the Bankruptcy Court. The plaintiffs asked the Bankruptcy Court to send the lawsuits back to the state courts. In June 2002, among other actions, the Bankruptcy Court sent back to the state courts only the Section 17200 portions of the complaints that were focused on the allegedly improper payments from the Utility to PG&E Corporation and PG&E Corporation’s alleged failure to infuse monies into the Utility as needed.

On October 8, 2003, the U.S. District Court for the Northern District of California (District Court) reversed, in part, the Bankruptcy Court’s June 2002 decision and ordered the plaintiffs’ restitution claims sent back to the Bankruptcy Court. The District Court found that these claims, estimated by the plaintiffs at approximately $5 billion, are the property of the Utility’s estate and are therefore properly within the Bankruptcy Court’s jurisdiction. Under the new plan of reorganization proposed by the Utility, PG&E Corporation, and the Official Committee of Unsecured Creditors dated July 31, 2003 (Settlement Plan) and submitted to the Bankruptcy Court for confirmation, the Utility would release these claims. The District Court also affirmed, in part, the Bankruptcy Court’s June 2002 decision and found that the plaintiffs’ civil penalty and injunctive relief claims under Section 17200 could be resolved in San Francisco Superior Court.

Under Section 17200, the AG and the City and County of San Francisco are entitled to seek civil penalties of $2,500 against each defendant for each violation of Section 17200. The AG’s complaint asserted that the total civil penalties would be not less than $500 million. PG&E Corporation believes that the applicable calculation methodology for civil penalties, if any violations were found, would not result in a material adverse effect on its financial condition or results of operations.

A status conference in San Francisco Superior Court for all three cases has been scheduled for October 21, 2003. No proceedings have yet been scheduled in Bankruptcy Court for the restitution claims.

Item 9. Regulation FD Disclosure

The information reported in this section of this Current Report on Form 8-K, included Exhibit 1, is being furnished, not filed, pursuant to Item 9 of Form 8-K.

Attached to this Current Report on Form 8-K as Exhibit 1 are revised financial projections relating to the Settlement Plan. Financial projections relating to the Settlement Plan were furnished to the Securities and Exchange Commission (SEC) on a Form 8-K on July 8, 2003. The financial projections furnished to the SEC on July 8, 2003 were included as Exhibit C to the Disclosure Statement dated July 31, 2003 and mailed to all persons entitled to vote on the Settlement Plan on August 15, 2003.

Among other revisions, the financial projections have been revised to reflect the following significant events:

The proposed settlement agreement submitted to the CPUC for approval in the Utility’s 2003 General Rate Case (GRC) on September 15, 2003. The settlement proposes lower depreciation rates than originally assumed, resulting in a higher rate base and lower cash flow over the forecast period.

The bill credit of $444 million to the Utility’s customers ordered by the CPUC on September 4, 2003, to pass through the California Department of Water Resources’ (DWR) reduction in its 2003 revenue requirement to customers. (The Utility's financial forecasts of the cash projected to be available at the effective date of the Settlement Plan are expected to largely offset the decrease due to the one-time bill credit.)

Projected net income under the July 2003 projections and the revised projections is about equal for the first two years (2004 and 2005), increasing to a positive difference under the revised projections of about $13 million in 2008 as a result of the lower depreciation rates agreed to as part of the GRC settlement. Likewise, the projected amount of cash flow available for dividends and share repurchases beginning in 2005 is projected to be between $30 million to $50 million less per year in the revised projections than in the July 2003 projections, accumulating to about $150 million over the 2005-2008 forecast period.

PG&E Corporation and the Utility believe that the forecast credit ratios based upon the updated projections are not materially different from the ratios contained in the projections furnished to the SEC in July 2003.

Cautionary Statement Regarding Forward Looking Statements

The projected financial information attached hereto as Exhibit 1 and the various assumptions underlying such projections constitute forward-looking statements which are necessarily subject to various risks and uncertainties that could cause actual results to differ materially from those contemplated by the forward looking statements and financial projections. Some of the factors that could cause results to differ materially include:

-	The outcome of the Utility’s Chapter 11 proceeding, including whether the proposed settlement agreement among the Utility, PG&E Corporation, and the staff of the CPUC becomes effective and whether the Settlement Plan is implemented;

-	The outcome of pending litigation and regulatory proceedings, including proceedings related to the true-up of the allocation of the DWR’s 2001-2002 revenue requirements among the three California investor-owned electric utilities, the timing and impact of the end of the retail electric rate freeze, the structure of post-rate freeze ratemaking, whether the Utility is required to refund previously collected revenues to ratepayers, and whether the proposed settlements in the Utility’s 2003 GRC proceeding are approved by the CPUC;

-	The Utility's ability to manage the net open position over time, which can be affected by whether various counterparties are able to meet their obligations under their power sale agreements with the Utility or with the DWR;

-	The level and volatility of wholesale electricity and natural gas prices and the Utility's ability to manage and respond to this volatility successfully;

-	The demand for and pricing of natural gas transportation and storage services;

-	Increased competition as a result of municipalization of the Utility's distribution assets, self-generation by customers, and other forms of competition that may result in stranded investment capital, loss of customer growth, and additional barriers to cost recovery;

-	The extent to which the cities and counties in the Utility’s service territory become community choice aggregators and the extent to which the Utility’s distribution customers can switch between purchasing electricity from the Utility or from alternate energy service providers as direct access customers;

-	The operation and decommissioning of the Utility’s Diablo Canyon nuclear power plant, which expose the Utility to potentially significant environmental and capital expenditure risks, and, to the extent the Utility is unable increase its spent fuel storage capacity by 2007 or find an alternative depository, the risk that the Utility may be required to close Diablo Canyon and purchase electricity from more expensive sources;

-	Future regulatory proceedings related to whether the Utility has complied with all applicable rules, tariffs, and orders, and the extent to which a finding of non-compliance could result in customer refunds, penalties, or other non-recoverable expense;

-	The effect of compliance with existing and future environmental laws, regulations, and policies;

-	How the CPUC administers the capital structure, stand-alone dividend, and first priority conditions of the holding company conditions.

-	Unanticipated population growth or decline, changes in market demand and general economic and financial market conditions, including unanticipated changes in interest or inflation rates;

-	Unanticipated changes in operating expenses and capital expenditures;

-	Applicable governmental policies and legislative or regulatory actions;

-	Weather, storms, earthquakes, fires, other natural disasters, explosions, accidents, mechanical breakdowns, and other events or perils that affect demand, result in power outages, reduce generating output or cause damage to the Utility’s assets or operations or those of third parties on which the Utility relies;

-	Acts of terrorism;

-	Actions of rating agencies and

-	New accounting pronouncements, including significant changes in accounting policies material to the Utility.

In particular, the financial projections, attached as Exhibit 1, have been prepared based upon certain assumptions that PG&E Corporation and the Utility believe to be reasonable under the circumstances, taking into account the purpose for which they were prepared. However, the financial projections were not prepared with a view toward compliance with the published guidelines of the SEC or the American Institute of Certified Public Accountants regarding projections or forecasts. In addition, the financial projections have not been examined or compiled by the independent accountants of the Utility or PG&E Corporation. Neither the Utility nor PG&E Corporation makes any representation as to the accuracy of the projections or the ability of the reorganized Utility to achieve the projected results. Many of the assumptions on which the projections are based are subject to significant uncertainties. Some assumptions may not materialize and unanticipated events and circumstances may affect the actual financial results. Therefore, the actual results achieved may vary from the projected results and the variations may be material.

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:	LINDA Y.H. CHENG _________________________________________
		LINDA Y.H. CHENG Corporate Secretary

Dated:	October 14, 2003

Exhibit Index

Exhibit 1

Revised financial projections relating to the Settlement Plan

Exhibit 1

EXHIBIT C TO THE DISCLOSURE STATEMENT

Assumptions – Nature and Limitations of Projections

The financial projections included in the Disclosure Statement depend upon the successful implementation of the Plan of Reorganization for the Reorganized Debtor, and the validity of the other assumptions contained therein. These projections reflect numerous assumptions, including confirmation and consummation of the Plan in accordance with its terms, continued access by the Reorganized Debtor to capital markets, the continued availability of the working capital facilities contemplated by the Disclosure Statement, the anticipated future performance of the Reorganized Debtor, certain assumptions with respect to its competitors, general business and economic conditions and other matters, many of which are beyond the control of the Reorganized Debtor. In addition, the risk factors outlined in the Disclosure Statement and unanticipated events and circumstances occurring subsequent to the preparation of the projections may affect the actual financial results of the Reorganized Debtor. Although the Proponents believe that the projections are reasonably attainable, variations between the actual financial results and those projected may occur and may be material.

Significant Assumptions Regarding Plan Consummation

The Debtor is assuming that the Plan shall be confirmed by the Bankruptcy Court for the purposes of these projections. The assumption of Plan confirmation incorporates the following significant assumptions:

1.	the holders of claims in Classes 3a, 3b, 4a, 4c, 4e, 5, 6, and 7 shall have voted to accept the Plan by the requisite statutory majority or majorities as provided in section 1126(c) of the Bankruptcy Code or, if any such class does not accept the Plan, the Bankruptcy Court shall confirm the Plan under section 1129(b) of the Bankruptcy Code;
2.	no material adverse effect on the business, assets, operations, property, or condition (financial or otherwise) of the Debtor or any of its subsidiaries (other than inactive subsidiaries) shall have occurred and be continuing;
3.	no material unanticipated claims shall have been filed or asserted in the Chapter 11 Case;
4.	all necessary regulatory and governmental approvals shall have been received within the contemplated timeline;
5.	all financing transactions contemplated by the Plan shall have been consummated on the terms contemplated by the Plan and the Disclosure Statement; and
6.	the Bankruptcy Court shall have issued the Confirmation Order.

Significant Assumptions Regarding the Pre-Consummation Projections

Cash Balance At December 31, 2003

The Debtor assumes that it will have cash available to reimburse creditors at year-end 2003 of approximately $2.5 billion. This amount is based on the current cash balances, and taking into account various cash impacts through 2003. These impacts include reductions for restricted funds, outstanding checks and all operating receipts and disbursements, including a one-time bill credit to ratepayers of a California Department of Water Resources rate reduction. Capital expenditures included in the forecast total $1.7 billion in 2003.

Earnings For 2003

Earnings during 2003 reflect both earnings from ongoing utility operations, as well as non-recurring items (including those described as “items affecting comparability”) in the Reorganized Debtor’s public filings with the Securities and Exchange Commission). Starting common equity balances in 2004 incorporate these earnings.

Significant Assumptions Regarding Effective Date Funding of Claims

As described in detail in the Plan and Disclosure Statement, claims are funded with a combination of cash on hand, reinstatement of certain financial claims such as preferred stock interests and pollution control bonds in classes 4a, 4b, and 4d, and the cash proceeds of new money notes. The Reorganized Debtor may also draw on a portion of its proposed bank facilities to fund claims, depending upon its seasonal working capital requirements at the actual effective date.

Claims in Classes 6 and 7 have not been reduced for the impact of any refunds ordered by the Federal Energy Regulatory Commission (FERC) or settlements of disputed claims. Because the financial projections assume full payment of Class 6 and 7 claims, the levels of debt at the effective date, the size of the Settlement Regulatory Asset, and customer revenues associated with the Settlement Regulatory Asset have not been adjusted for any potential reductions in these claims.

Structure of the Reorganized Debtor

1.	The Reorganized Debtor will remain an integrated electric and gas utility company serving predominantly retail customers in Northern and Central California. The Reorganized Debtor will retain its existing gas and electric distribution, transmission and customer service assets.
2.	The Reorganized Debtor will provide distribution customer services and revenue cycle services, and will provide and administer public purpose programs for retail electric and gas customers.
3.	The Reorganized Debtor will retain the obligation to procure gas on behalf of its core gas customers and the obligation to procure power on behalf of its retail electric customers.
4.	The Reorganized Debtor will assume and retain the bilateral energy purchase agreements with (a) third party gas suppliers, and (b) QFs and other third party power suppliers, including the Irrigation Districts.
5.	The Reorganized Debtor will retain its electric generation assets, including the 2,174 MW capacity Diablo Canyon nuclear plant, its conventional and pumped storage hydro-electric generating facilities with an aggregate capacity of 3,896 MW, and two small fossil generating facilities.
6.	The Reorganized Debtor will remain subject to rate regulation of the California Public Utilities Commission (CPUC) for its electric distribution, generation and procurement operations, and for its gas distribution, procurement, transmission and storage operations, subject to the terms of the Settlement as incorporated into the Plan and Confirmation Order.
7.	The Reorganized Debtor’s high voltage electric transmission assets will provide services for its own retail customers as well as wholesale market participants, both under the jurisdiction of the FERC.

Income Statement

Total Operating Revenues

Revenues include customer payments for electric and gas distribution services, electric transmission and gas transmission and storage services, electric and gas energy procurement purchases (excluding California Department of Water Resources sources of electricity), electric power generated by the Reorganized Debtor’s retained electric generating facilities, public purpose programs, recovery of the proposed Settlement Regulatory Asset with associated taxes and return, and Rate Reduction Bonds.

1.	Electric and Gas Revenues include base revenues from the 2003 General Rate Case and subsequent annual attrition proceedings intended to enable the Reorganized Debtor to recover increased costs due to inflation, customer growth and ratebase growth. The authorized rate of return on common equity (ROE) remains at 11.22%. The authorized common equity ratio equals 48.6% in 2004, and increases to 52.0% by 2006. Electric annual load growth for bundled sales approximates 1.8%/year, and gas annual load growth for core customers approximates 1.0%/year. Electric Direct Access retail load approximates 8,100 GWh annually (10.2% of total deliveries in 2004) and is held constant throughout the forecast period.

2.	Electric Revenues also include base revenues to enable the Reorganized Debtor to recover non-fuel operating costs, depreciation, taxes and rate of return on its retained electric generation assets, as well as revenues to recover amortization, return, and associated taxes on the Settlement Regulatory Asset.

3.	Electric and gas procurement revenues match electric and gas procurement expenses. Excluded are revenues collected for electric energy procured by DWR on behalf of the Reorganized Debtor’s customers. Cash revenues (receipts) lag expenses (disbursements) by the average working capital lag of 16 days.

4.	Electric and Gas Public Purpose Program Revenue, excluding CARE, total $310 million in 2004 and escalate thereafter. Identical M&O expenses offset these revenues so there is no impact on earnings or cash from operations.

Operating Expenses

1.	Total Cost of Energy includes all electric and gas commodity procured on behalf of retail electric and gas customers by the Reorganized Debtor. Electric commodity costs include QF contracts, natural gas fuel for the Hunters Point and Humboldt power plants, nuclear fuel for the Diablo Canyon power plant, Irrigation District contracts, and other commodity procurement and grid management expenses. Excluded are remittances to DWR for power it procures on behalf of the Reorganized Debtor’s customers and for bond debt service.

2.	M&O and A&G Costs include direct M&O Expenses for electric and gas distribution, transmission, and the Reorganized Debtor’s retained generating assets, A&G costs, public purpose programs and franchise and uncollectibles expenses.

3.	Depreciation is calculated for distribution and electric generation assets using depreciation rates expected to be adopted as part of the Reorganized Debtor’s proposed settlement of its 2003 Test Year CPUC General Rate Case (GRC). Electric and gas transmission depreciation reflects depreciation rates used to develop tariffs currently authorized by the FERC and CPUC, respectively. Depreciation expense also includes amortization of the Settlement regulatory asset including its provision for taxes on recovery of principal. Other items included in depreciation include provisions for fossil and nuclear power plant decommissioning.

4.	Property Tax is estimated at about 1% of net plant. Franchise Fees and Uncollectable expenses are estimated at about 1% of revenue.

Interest Expense

Interest Expense (excluding Rate Reduction Bonds) consists mainly of interest on long-term debt. Interest expense is based on interest rates of approximately 6.5% for new debt and 4.5% for reinstated Pollution Control bonds. Borrowing costs are based on the all-in, effective costs to the Reorganized Debtor. Corresponding debt balances are net of issuance expenses. Accordingly, the par value of debt issued will be approximately 1.0 percent higher than the net balances shown. Rate Reduction Bond interest and the amortization of the net gain or loss on reacquired debt are shown separately.

Other Income

Other Income is comprised of “below-the-line” income and expenses, including AFUDC, operating costs not recoverable in retail rates, and non-recurring items.

Income Taxes

Income Taxes are calculated using a 35% federal tax rate and an 8.84% state tax rate, with a combined tax rate of 40.746%. The book income tax provision reflects existing regulatory practices for recognizing the timing of income tax expenses.

Dividends

Preferred Dividend arrearages are paid on the Effective Date. Preferred dividends are based on an embedded cost of preferred stock of approximately 6.5%.

Balance Sheet

Assets

Generally, balances of assets and liabilities are either held constant at their starting level, or are taken as a percentage of a revenue or expense. Plant in service, construction work in progress, common stock and long-term debt are dynamic balances, changing as a function of cash from operations and capital expenditures. Net plant includes the value of the Reorganized Debtor’s retained generation facilities under cost of service regulation per Advice Letter 2233-E implementing D.02-04-016, as per the Settlement, Plan and Confirmation Order and as expected to be further modified through normal depreciation, additions, and retirements. Cash balances are held constant at an initial level for restricted funds and check float.

Capitalization

Short-term debt is used to fund seasonal working capital requirements and natural gas storage inventory. Any subsequent surplus cash is used for debt retirement or distribution to common shareholders in amounts necessary to achieve and then maintain the target capital structure. For the Reorganized Debtor, the targeted common equity to total long-term capitalization ratio is 52% (excluding rate reduction bonds and short-term debt used to finance seasonal working capital requirements or natural gas storage inventory).

Cash Flow Statement

1.	Cash from operations is estimated by adding back depreciation and deferred taxes to net income, plus changes in working capital. Seasonal variations in receipts and reimbursements will cause these average requirements to fluctuate within a range of approximately +/- $300 million.

2.	Subsequent to the Effective Date, the Reorganized Debtor manages its capital structure such that it achieves an overall ratio of common equity to total capitalization of 52% within two years, and then maintains that common equity ratio over time. Reorganized Debtor commences cash distributions to common shareholders (shown as common stock repurchases) when it reaches its target capital structure in the second half of 2005. Subsequently, Reorganized Debtor issues or repurchases debt and common equity annually in order to maintain this capital structure.

REORGANIZED DEBTOR
	12/31/2003	12/31/2004	12/31/2005	12/31/2006	12/31/2007	12/31/2008
				($Millions)
INCOME STATEMENT
Total Operating Revenues*		10467.7	10350.3	10529.6	10880.0	10906.5

Operating Expenses
Total Cost of Energy*		3485.3	3206.8	3224.2	3385.1	3524.3
M&O and A&G Costs		2999.5	2989.3	3020.3	3088.2	3150.6
Depreciation & Decommissioning		1310.1	1386.0	1464.1	1568.3	1673.3
Property & Other Taxes		164.1	171.2	176.4	180.0	182.6
RRB Asset Amortization		290.1	289.7	289.7	289.7	(0.4)
Total Operating Expenses		8249.1	8043.1	8174.6	8511.3	8530.5

Operating Income		2218.6	2307.3	2355.0	2368.7	2376.0

Total Interest Income		12.4	12.4	12.4	12.4	12.4

Interest Expense (Excl RRBs)		568.8	553.5	554.4	564.5	571.2
Amortization of Loss on Reacquired Debt		33.6	33.6	33.6	33.6	33.6
RRB Interest.		68.9	50.3	31.5	12.1	0.0
Total Interest Expense		671.3	637.4	619.5	610.2	604.8

Other Income		(5.2)	(6.6)	(12.6)	(13.7)	(14.4)

Pretax Income		1554.5	1675.6	1735.3	1757.1	1769.2

Total Booked Income Taxes		643.2	693.0	705.2	715.0	719.8

Preferred Dividend Req.		24.7	24.2	23.2	23.5	24.5

Total Earnings Avail for Common		886.6	958.4	1006.9	1018.6	1024.9
___________________		886.6	958.4	1006.9	1018.6	1024.9
* Excludes Receipts and Disbursements for CDWR Procurement.

BALANCE SHEET
Assets
Plant in Service	28965.9	30406.0	32014.4	33289.7	34652.8	36043.4
Accumulated Depr	(13056.1)	(13862.2)	(14668.2)	(15488.2)	(16363.8)	(17289.9)
Net Plant	15909.8	16543.7	17346.2	17801.5	18289.0	18753.6

Construction Work In Progress…	318.3	359.1	292.1	291.4	290.9	306.9
Nuclear Decommissioning Trust Fund	1376.0	1406.6	1437.3	1467.9	1498.6	1529.2
Other Noncurrent Assets	65.1	65.1	65.1	65.1	65.1	65.1
Total Long-term Assets	17669.3	18374.6	19140.7	19626.0	20143.6	20654.8

Current Assets:
	0.0	0.0	0.0	1.0	2.0	2.0
Short-term Investments (Net)	413.0	413.0	413.0	413.0	413.0	413.0

Accounts Receivable	1643.9	1661.3	1654.1	1668.6	1717.6	1726.0

Balancing Accts Receivable	72.2	85.4	85.5	85.6	85.6	85.7
Inventory - Fuels	407.5	444.7	417.7	383.7	365.0	353.6
Inventory - M&S	127.7	129.5	131.2	132.9	134.6	136.3
Prepayments & Adv to Gas Prod	79.3	79.3	79.3	79.3	79.3	79.3

Total Current Assets	2743.6	2813.2	2780.7	2763.1	2795.1	2793.8

Deferred Charges:

Expense Deferral	1241.8	951.7	662.0	372.3	82.6	83.0
Regulatory Assets	2210.0	2065.9	1903.7	1721.6	1515.6	1282.6
URG Regulatory Assets	793.0	747.5	702.0	656.5	611.0	565.5
Regulatory Assets Def Tax	2065.0	1934.6	1791.8	1635.3	1462.4	1270.8
Other Deferred Charges	1750.9	1717.3	1683.7	1650.1	1616.5	1582.9
Total Deferred Charges	8060.7	7417.0	6743.2	6035.8	5288.1	4784.8

TOTAL ASSETS	28473.6	28604.8	28664.7	28424.8	28226.7	28233.4

Capitalization:
Common Stock Equity	7895.7	8782.3	9480.9	9603.9	9738.6	9786.2
Preferred Stock (incl QUIDS)	416.0	409.1	402.2	395.4	421.0	417.9
RRBs Outstanding	1160.3	870.2	580.1	290.0	(0.1)	(0.1)
Other Long-term Debt	8725.3	8725.3	8349.4	8469.8	8568.4	8615.7
Total Capitalization	18197.3	18787.0	18812.7	18759.1	18727.9	18819.6

Current Liabilities:
Short-Term Borrowings	500.0	88.9	251.8	228.9	220.1	217.7
Accounts Payable - Creditors	876.1	851.8	829.5	827.5	852.2	875.8

Balancing Accounts Payable	141.2	140.2	139.3	138.4	137.6	136.8
Accrued Taxes Payable	347.1	334.2	351.2	354.8	358.1	348.3
Interest Payable	17.8	34.8	48.8	48.3	49.1	49.8
Other Current Liabilities	577.7	577.7	577.7	577.7	577.7	577.7
Total Current Liabilities	2460.0	2027.5	2198.3	2175.6	2194.9	2206.0

Deferred Credits and Other NC Liabilities:
Deferred Income Taxes	3389.0	3346.7	3182.8	2993.3	2779.3	2657.4
Deferred ITC	140.9	134.7	128.5	122.3	116.1	109.9
Noncurrent Balancing Acct Liab
Customer Advances for Construction.	132.0	123.9	126.8	128.3	131.7	133.0
Other Deferred Credits	1867.5	1867.5	1867.5	1867.5	1867.5	1867.5
Other Noncurrent Liab	2286.8	2317.4	2348.1	2378.7	2409.4	2440.0

Total Deferred Credits & NC Liab	7816.3	7790.3	7653.7	7490.1	7304.0	7207.8

TOTAL CAPITAL & LIABILITIES.	28473.6	28604.8	28664.7	28424.8	28226.7	28233.4

CASH FLOW STATEMENT
Cash Flows From Operations:
Net Income		911.37	982.6	1030.2	1042.1	1049.4
Depreciation		1313.03	1389.0	1467.1	1571.2	1676.3
Change in Deferred Taxes		(48.47)	(170.1)	(195.7)	(220.2)	(128.2)
Change in Accts Receivable		(17.35)	7.2	(14.5)	(49.0)	(8.3)
Change in Inventories		(39.03)	25.4	32.2	17.1	9.7
Change in Accts Payable		(24.36)	(22.3)	(2.0)	24.8	23.5
Change in Accrued Taxes Payable		(12.89)	17.0	3.6	3.3	(9.8)
Change in Bal Accts & Reg Asset Amort		289.14	288.7	288.8	288.8	(1.3)
Change in Other Working Capital		12.78	14.1	(0.3)	0.8	0.5
Other Net Cash from Operations		69.83	99.3	96.9	93.1	95.3
Net Cash from Operations		2454.1	2630.9	2706.2	2771.9	2707.0

Investing Activities:
Capital Expenditures		(1694.7)	(1806.3)	(1568.6)	(1659.2)	(1716.4)
Other Net Investing Activities		(30.6)	(30.6)	(30.6)	(30.6)	(30.6)
Net Cash Used In Investing		(1725.3)	(1836.9)	(1599.3)	(1689.8)	(1747.1)

Financing Activities:
Common Stock Issued (Repurchased).		0.0	(259.8)	(884.0)	(883.9)	(977.3)
Preferred Stock Issued		0.0	0.0	0.0	85.0	0.0
Preferred Stock redeemed		(6.9)	(6.9)	(6.9)	(59.4)	(3.1)
Long-term Debt issued		(0.0)	(375.9)	120.4	98.6	47.2
Long-term Debt matured/redeemed		0.0	0.0	0.0	0.0	0.0
Long-term Debt purch/sinking		0.0	0.0	0.0	0.0	0.0
RRB Principal Repayments		(290.1)	(290.1)	(290.1)	(290.1)	0.0
Change in Short-term Position		(411.1)	163.0	(22.9)	(8.8)	(2.4)
Dividends Disbursed		(20.6)	(24.3)	(23.4)	(23.5)	(24.4)
Other Net Financing Activities		0.0	0.0	0.0	0.0	0.0
Net Cash Used In Financing		(728.8)	(794.0)	(1106.9)	(1082.0)	(960.0)

Net Change in Cash		(0.0)	0.0	(0.0)	0.0	(0.0)

SUPPLEMENTAL INFORMATION
Revenues
Gas		2741.6	2670.2	2600.7	2649.9	2700.5
Public Purpose		312.1	319.9	327.9	336.1	344.5
Electric		7414.0	7360.2	7601.0	7893.9	7861.5
Total from Inc Stmt		10467.7	10350.3	10529.6	10880.0	10906.5

Energy Costs
Gas Procurement		1323.8	1201.0	1076.4	1085.7	1103.7
Nuclear Fuel + Hydro Water + ID Pmts		150.1	156.8	141.5	142.1	143.6
QF Payments.		1649.9	1637.5	1639.5	1613.0	1579.5
Net Open		247.2	39.2	224.3	398.6	590.7
Other Gen Costs¹		114.3	172.3	142.5	145.6	106.8
Total from Inc Stmt		3485.3	3206.8	3224.2	3385.1	3524.3

M&O and A&G Costs
Gas.		660.7	669.7	684.8	703.7	717.9
Public Purpose		309.1	316.9	324.8	332.9	341.2
Electric		2029.7	2002.7	2010.7	2051.6	2091.5
Total from Inc Stmt		2999.5	2989.3	3020.3	3088.2	3150.6

Depreciation & Decommissioning
Gas		279.5	293.2	307.8	324.0	336.3
Electric²		1064.2	1126.5	1189.9	1277.9	1370.6
Total from Inc Stmt		1343.7	1419.6	1497.7	1601.9	1706.9

Property & Other Taxes
Gas		38.2	39.2	40.6	41.3	41.6
Electric		125.9	132.0	135.7	138.7	141.1
Total from Inc Stmt		164.1	171.2	176.4	180.0	182.6

Average Annual Rate Base
Gas		3568.1	3705.8	3826.8	3836.3	3867.8
Electric.		10504.6	10939.6	11321.5	11642.4	11939.9
URG Regulatory Asset		770.3	724.8	679.3	633.8	588.3
Settlement Regulatory Asset		2138.0	1984.8	1812.7	1618.6	1399.1

Authorized Capital Structure
% Debt		49.1%	47.3%	45.8%	45.7%	45.8%
% Preferred		2.3%	2.2%	2.2%	2.3%	2.3%
% Equity		48.6%	50.5%	52.0%	52.0%	52.0%
		100.0%	100.0%	100.0%	100.0%	100.0%
Authorized Cost of Capital
Debt*		6.22%	6.26%	6.31%	6.35%	6.38%
Preferred*		6.50%	6.50%	6.50%	6.50%	6.50%
Equity		11.20%	11.20%	11.20%	11.20%	11.20%
Return on Rate Base		8.65%	8.76%	8.86%	8.88%	8.89%
______________
¹Includes ISO and Retained Fossil fuel costs net of RMR revenues and WAPA payments
²Includes URG and Settlement Regulatory Asset Amortization
^*Excludes refunding costs recovered through authorized cost of debt

SUPPLEMENTAL INFORMATION
Gas Procurement Volumes and Average Price
Gas Sales (mDTH)		289,964	293,022	295,963	299,030	302,121
Average Price ($/mmBtu)		4.57	4.10	3.64	3.63	3.65

Elec Procurement Volumes and Average Price¹
Volumes (GWh)
Hydro/Helms/Diablo/ID		32,920	33,360	33,445	33,580	33,674
QF		20,827	20,807	20,744	19,971	19,489
Other Gen²		2,085	1,666	1,380	1,382	597
Net Open		3,458	(1,410)	1,473	4,227	6,956
Total Non-DWR Supply		59,291	54,423	57,042	59,161	60,716
DWR		25,173	26,297	25,296	24,828	24,875
Total (excl D/A)		84,464	80,720	82,339	83,989	85,591

Average Price ($/MWh)
QF		79.22	78.70	79.03	80.76	81.05
Other Gen³		54.83	103.36	103.21	105.39	179.01
Net Open		71.47	(27.76)	152.25	94.30	84.92
Total Non-DWR Supply		76.27	87.78	85.02	84.33	84.20
DWR		85.47	84.21	84.84	87.34	88.66
Overall Average (excl D/A)		80.76	85.80	84.93	85.81	86.34

Sales/Deliveries (GWh)
Total Deliveries		79,303	80,422	81,880	83,386	84,819
Bundled Sales		71,186	72,304	73,762	75,268	76,702
Direct Access		8,118	8,118	8,118	8,118	8,118

Average Rate (½/kWh)
Total Deliveries		12.22	12.08	12.07	12.24	12.05
Bundled Sales		13.04	12.87	12.85	13.03	12.80
Direct Access		4.98	4.98	4.98	4.98	4.98
______________
¹Electric Procurement Volumes and Average Prices are shown before the effects of netting line losses and Helms pumping
²Includes Retained Fossil, Etiwanda & EBMUD, and Puget inbound
³Includes ISO Ancillary Services and Retained Fossil fuel costs net of RMR revenues and WAPA payments