UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C., 20549

FORM 10-Q

  (Mark One)

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2011 OR
[  ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                 

Commission         File Number	Exact Name of       Registrant as specified in its charter	State or other Jurisdiction of       Incorporation	IRS Employer Identification Number
1-12609	PG&E Corporation	California	94-3234914
1-2348	Pacific Gas and Electric Company	California	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, including zip code
Pacific Gas and Electric Company (415) 973-7000		PG&E Corporation (415) 267-7000
Registrant’s telephone number, including area code

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.  [X] Yes      [  ] No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

PG&E Corporation	[X] Yes [  ] No
Pacific Gas and Electric Company:	[X] Yes  [  ] No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

PG&E Corporation:	[X] Large accelerated filer	[  ] Accelerated Filer
	[  ] Non-accelerated filer	[  ] Smaller reporting company
Pacific Gas and Electric Company:	[  ] Large accelerated filer	[  ] Accelerated Filer
	[X] Non-accelerated filer	[  ] Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

PG&E Corporation:	[  ] Yes [X] No
Pacific Gas and Electric Company:	[  ] Yes [X] No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Common Stock Outstanding as of October 25, 2011:

PG&E Corporation	405,882,996
Pacific Gas and Electric Company	264,374,809

PG&E CORPORATION AND

PACIFIC GAS AND ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2011

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION	PAGE
ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
	Condensed Consolidated Statements of Income	2
	Condensed Consolidated Balance Sheets	3
	Condensed Consolidated Statements of Cash Flows	5
	Pacific Gas and Electric Company
	Condensed Consolidated Statements of Income	6
	Condensed Consolidated Balance Sheets	7
	Condensed Consolidated Statements of Cash Flows	9
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:   Organization and Basis of Presentation	10
	NOTE 2:   Significant Accounting Policies	10
	NOTE 3:   Regulatory Assets, Liabilities, and Balancing Accounts	12
	NOTE 4:   Debt	16
	NOTE 5:   Equity	18
	NOTE 6:   Earnings Per Share	19
	NOTE 7:   Derivatives and Hedging Activities	20
	NOTE 8:   Fair Value Measurements	24
	NOTE 9:   Resolution of Remaining Chapter 11 Disputed Claims	29
	NOTE 10: Commitments and Contingencies	30
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview	38
	Cautionary Language Regarding Forward-Looking Statements	40
	Results of Operations	43
	Liquidity and Financial Resources	48
	Contractual Commitments	53
	Capital Expenditures	53
	Off-Balance Sheet Arrangements	54
	Contingencies	54
	Natural Gas Pipeline Matters	54
	Regulatory Matters	59
	Environmental Matters	63
	Legal Matters	65
	Risk Management Activities	65
	Critical Accounting Policies	67
	Accounting Standards Issued But Not Yet Adopted	67
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	68
ITEM 4.	CONTROLS AND PROCEDURES	68
PART II. OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	69
ITEM 1A.	RISK FACTORS	70
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	74
ITEM 5.	OTHER INFORMATION	74
ITEM 6.	EXHIBITS	75
SIGNATURES		76

1

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	(Unaudited)
	Three Months Ended     September  30,				Nine Months Ended     September  30,
(in millions, except per share amounts)	2011		2010		2011		2010
Operating Revenues
Electric		$  3,188		$  2,857		$  8,694		$  7,882
Natural gas		672		656		2,447		2,338
Total operating revenues		3,860		3,513		11,141		10,220
Operating Expenses
Cost of electricity		1,224		1,102		3,018		2,885
Cost of natural gas		170		182		936		924
Operating and maintenance		1,492		1,225		3,955		3,175
Depreciation, amortization, and decommissioning		566		501		1,648		1,420
Total operating expenses		3,452		3,010		9,557		8,404
Operating Income		408		503		1,584		1,816
Interest income		2		3		7		7
Interest expense		(176)		(167)		(527)		(510)
Other income, net		18		29		56		25
Income Before Income Taxes		252		368		1,120		1,338
Income tax provision		49		107		349		479
Net Income		203		261		771		859
Preferred stock dividend requirement of subsidiary		3		3		10		10
Income Available for Common Shareholders		$  200		$  258		$  761		$  849
Weighted Average Common Shares Outstanding, Basic		403		390		399		378
Weighted Average Common Shares Outstanding, Diluted		404		392		400		391
Net Earnings Per Common Share, Basic		$  0.50		$  0.66		$  1.91		$  2.22
Net Earnings Per Common Share, Diluted		$  0.50		$  0.66		$  1.90		$  2.19
Dividends Declared Per Common Share		$  0.46		$  0.46		$  1.37		$  1.37

See accompanying Notes to the Condensed Consolidated Financial Statements.

2        

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
(in millions)	September 30,     2011		December 31,     2010
ASSETS
Current Assets
Cash and cash equivalents		$  277		$  291
Restricted cash ($39 and $38 related to energy recovery bonds at September 30, 2011 and December 31, 2010, respectively)		393		563
Accounts receivable
Customers (net of allowance for doubtful accounts of $85 and $81 at September 30, 2011 and December 31, 2010, respectively)		1,011		944
Accrued unbilled revenue		737		649
Regulatory balancing accounts		1,063		1,105
Other		820		794
Regulatory assets		680		599
Inventories
Gas stored underground and fuel oil		198		152
Materials and supplies		219		205
Income taxes receivable		148		47
Other		331		193
Total current assets		5,877		5,542
Property, Plant, and Equipment
Electric		35,120		33,508
Gas		11,700		11,382
Construction work in progress		1,623		1,384
Other		15		15
Total property, plant, and equipment		48,458		46,289
Accumulated depreciation		(15,626)		(14,840)
Net property, plant, and equipment		32,832		31,449
Other Noncurrent Assets
Regulatory assets ($435 and $735 related to energy recovery bonds at September 30, 2011 and December 31, 2010, respectively)		5,714		5,846
Nuclear decommissioning trusts		1,964		2,009
Income taxes receivable		457		565
Other		673		614
Total other noncurrent assets		8,808		9,034
TOTAL ASSETS		$  47,517		$  46,025

See accompanying Notes to the Condensed Consolidated Financial Statements.

3        

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
(in millions, except share amounts)	September 30,     2011		December 31,     2010
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings		$  1,137		$  853
Long-term debt, classified as current		50		809
Energy recovery bonds, classified as current		418		404
Accounts payable
Trade creditors		1,154		1,129
Disputed claims and customer refunds		673		745
Regulatory balancing accounts		421		256
Other		380		379
Interest payable		789		862
Income taxes payable		107		77
Deferred income taxes		-		113
Other		1,689		1,558
Total current liabilities		6,818		7,185
Noncurrent Liabilities
Long-term debt		11,516		10,906
Energy recovery bonds		110		423
Regulatory liabilities		4,596		4,525
Pension and other postretirement benefits		2,343		2,234
Asset retirement obligations		1,591		1,586
Deferred income taxes		6,212		5,547
Other		2,120		2,085
Total noncurrent liabilities		28,488		27,306
Commitments and Contingencies (Note 10)
Equity
Shareholders’ Equity
Preferred stock		-		-
Common stock, no par value, authorized 800,000,000 shares, 405,169,162 shares outstanding at September 30, 2011 and 395,227,205 shares outstanding at December 31, 2010		7,318		6,878
Reinvested earnings		4,817		4,606
Accumulated other comprehensive loss		(176)		(202)
Total shareholders’ equity		11,959		11,282
Noncontrolling Interest – Preferred Stock of Subsidiary		252		252
Total equity		12,211		11,534
TOTAL LIABILITIES AND EQUITY		$  47,517		$  46,025

See accompanying Notes to the Condensed Consolidated Financial Statements.

4        

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Nine Months Ended     September  30,
(in millions)	2011		2010
Cash Flows from Operating Activities
Net income		$ 771		$ 859
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,648		1,420
Allowance for equity funds used during construction		(64)		(89)
Deferred income taxes and tax credits, net		552		328
Other		223		203
Effect of changes in operating assets and liabilities:
Accounts receivable		(186)		(246)
Inventories		(60)		(65)
Accounts payable		93		17
Income taxes receivable/payable		(71)		252
Other current assets and liabilities		(170)		(34)
Regulatory assets, liabilities, and balancing accounts, net		70		(32)
Other noncurrent assets and liabilities		426		(293)
Net cash provided by operating activities		3,232		2,320
Cash Flows from Investing Activities
Capital expenditures		(2,968)		(2,794)
Decrease in restricted cash		170		61
Proceeds from sales and maturities of nuclear decommissioning trust investments		1,574		962
Purchases of nuclear decommissioning trust investments		(1,604)		(1,001)
Other		(102)		(25)
Net cash used in investing activities		(2,930)		(2,797)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities		358		490
Repayments under revolving credit facilities		(283)		-
Net issuances of commercial paper, net of discount of $2 in 2011 and 2010		196		251
Proceeds from issuance of long-term debt, net of discount and issuance costs of $6 in 2011 and $12 in 2010		544		838
Short-term debt matured		-		(500)
Long-term debt matured		(700)		(95)
Energy recovery bonds matured		(299)		(285)
Common stock issued		391		141
Common stock dividends paid		(525)		(492)
Other		2		(51)
Net cash (used in) provided by financing activities		(316)		297
Net change in cash and cash equivalents		(14)		(180)
Cash and cash equivalents at January 1		291		527
Cash and cash equivalents at September 30		$ 277		$ 347
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized		$ (536)		$ (526)
Income taxes, net		8		(52)
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid		$ 184		$ 180
Capital expenditures financed through accounts payable		225		229
Noncash common stock issuances		18		259

See accompanying Notes to the Condensed Consolidated Financial Statements.

5        

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	(Unaudited)
	Three Months Ended     September  30,				Nine Months Ended     September  30,
(in millions)	2011		2010		2011		2010
Operating Revenues
Electric		$ 3,187		$ 2,857		$ 8,691		$ 7,882
Natural gas		672		656		2,447		2,338
Total operating revenues		3,859		3,513		11,138		10,220
Operating Expenses
Cost of electricity		1,224		1,102		3,018		2,885
Cost of natural gas		170		182		936		924
Operating and maintenance		1,497		1,224		3,951		3,172
Depreciation, amortization, and decommissioning		566		500		1,648		1,419
Total operating expenses		3,457		3,008		9,553		8,400
Operating Income		402		505		1,585		1,820
Interest income		2		3		6		7
Interest expense		(171)		(161)		(511)		(481)
Other income, net		19		25		52		20
Income Before Income Taxes		252		372		1,132		1,366
Income tax provision		56		107		376		498
Net Income		196		265		756		868
Preferred stock dividend requirement		3		3		10		10
Income Available for Common Stock		$ 193		$ 262		$ 746		$ 858

See accompanying Notes to the Condensed Consolidated Financial Statements.

6        

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
(in millions)	September 30,          2011		December 31,          2010
ASSETS
Current Assets
Cash and cash equivalents		$  53		$  51
Restricted cash ($39 and $38 related to energy recovery bonds at September 30, 2011 and December 31, 2010, respectively)		393		563
Accounts receivable
Customers (net of allowance for doubtful accounts of $85 and $81 at September 30, 2011 and December 31, 2010, respectively)		1,011		944
Accrued unbilled revenue		737		649
Regulatory balancing accounts		1,063		1,105
Other		821		856
Regulatory assets		680		599
Inventories
Gas stored underground and fuel oil		198		152
Materials and supplies		219		205
Income taxes receivable		203		48
Other		316		190
Total current assets		5,694		5,362
Property, Plant, and Equipment
Electric		35,120		33,508
Gas		11,700		11,382
Construction work in progress		1,623		1,384
Total property, plant, and equipment		48,443		46,274
Accumulated depreciation		(15,612)		(14,826)
Net property, plant, and equipment		32,831		31,448
Other Noncurrent Assets
Regulatory assets ($435 and $735 related to energy recovery bonds at September 30, 2011 and December 31, 2010, respectively)		5,714		5,846
Nuclear decommissioning trusts		1,964		2,009
Income taxes receivable		456		614
Other		338		400
Total other noncurrent assets		8,472		8,869
TOTAL ASSETS		$  46,997		$  45,679

See accompanying Notes to the Condensed Consolidated Financial Statements.

7        

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
(in millions, except share amounts)	September 30,          2011		December 31,          2010
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings		$  1,062		$  853
Long-term debt, classified as current		50		809
Energy recovery bonds, classified as current		418		404
Accounts payable
Trade creditors		1,154		1,129
Disputed claims and customer refunds		673		745
Regulatory balancing accounts		421		256
Other		395		390
Interest payable		779		857
Income taxes payable		115		116
Deferred income taxes		-		118
Other		1,483		1,349
Total current liabilities		6,550		7,026
Noncurrent Liabilities
Long-term debt		11,167		10,557
Energy recovery bonds		110		423
Regulatory liabilities		4,596		4,525
Pension and other postretirement benefits		2,280		2,174
Asset retirement obligations		1,591		1,586
Deferred income taxes		6,341		5,659
Other		2,055		2,008
Total noncurrent liabilities		28,140		26,932
Commitments and Contingencies (Note 10)
Shareholders’ Equity
Preferred stock		258		258
Common stock, $5 par value, authorized 800,000,000 shares, 264,374,809 shares outstanding at September 30, 2011 and December 31, 2010		1,322		1,322
Additional paid-in capital		3,592		3,241
Reinvested earnings		7,304		7,095
Accumulated other comprehensive loss		(169)		(195)
Total shareholders’ equity		12,307		11,721
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$  46,997		$  45,679

See accompanying Notes to the Condensed Consolidated Financial Statements.

8        

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Nine Months Ended     September  30,
(in millions)	2011		2010
Cash Flows from Operating Activities
Net income		$  756		$  868
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,648		1,419
Allowance for equity funds used during construction		(64)		(89)
Deferred income taxes and tax credits, net		564		332
Other		193		175
Effect of changes in operating assets and liabilities:
Accounts receivable		(125)		(240)
Inventories		(60)		(65)
Accounts payable		97		15
Income taxes receivable/payable		(156)		241
Other current assets and liabilities		(153)		(33)
Regulatory assets, liabilities, and balancing accounts, net		70		(32)
Other noncurrent assets and liabilities		491		(240)
Net cash provided by operating activities		3,261		2,351
Cash Flows from Investing Activities
Capital expenditures		(2,968)		(2,794)
Decrease in restricted cash		170		61
Proceeds from sales and maturities of nuclear decommissioning trust investments		1,574		962
Purchases of nuclear decommissioning trust investments		(1,604)		(1,001)
Other		13		15
Net cash used in investing activities		(2,815)		(2,757)
Cash Flows from Financing Activities
Borrowings under revolving credit facility		208		400
Repayments under revolving credit facility		(208)		-
Net issuances of commercial paper, net of discount of $2 in 2011 and 2010		196		251
Proceeds from issuance of long-term debt, net of discount and issuance costs of $6 in 2011 and $12 in 2010		544		838
Short-term debt matured		-		(500)
Long-term debt matured		(700)		(95)
Energy recovery bonds matured		(299)		(285)
Preferred stock dividends paid		(10)		(11)
Common stock dividends paid		(537)		(537)
Equity contribution		350		170
Other		12		(40)
Net cash (used in) provided by financing activities		(444)		191
Net change in cash and cash equivalents		2		(215)
Cash and cash equivalents at January 1		51		334
Cash and cash equivalents at September 30		$  53		$  119
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized		$  (525)		$  (504)
Income taxes, net		6		(87)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable		$  225		$  229

See accompanying Notes to the Condensed Consolidated Financial Statements.

9        

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

PG&E Corporation is a holding company whose primary purpose is to hold interests in energy-based businesses. PG&E Corporation conducts its business principally through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is regulated by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). In addition, the Nuclear Regulatory Commission (“NRC”) oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. The Utility’s accounts for electric and gas operations are maintained in accordance with the Uniform System of Accounts prescribed by the FERC.

This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility that includes separate Condensed Consolidated Financial Statements for each company. The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated from the Condensed Consolidated Financial Statements.

The accompanying Condensed Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X promulgated by the Securities and Exchange Commission (“SEC”) and therefore do not contain all of the information and footnotes required by GAAP and the SEC for annual financial statements. PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of their financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2010 in both PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets incorporated by reference into their combined 2010 Annual Report on Form 10-K filed with the SEC on February 17, 2011. PG&E Corporation’s and the Utility’s combined 2010 Annual Report on Form 10-K, together with the information incorporated by reference into such report, is referred to in this quarterly report as the “2010 Annual Report.” This quarterly report should be read in conjunction with the 2010 Annual Report.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions based on a wide range of factors, including future regulatory decisions and economic conditions that are difficult to predict. Some of the more critical estimates and assumptions relate to the Utility’s regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal matters, asset retirement obligations (“ARO”s), and pension plan and other postretirement plan obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. Actual results could differ materially from those estimates.

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies used by PG&E Corporation and the Utility are discussed in Notes 1 and 2 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.

Pension and Other Postretirement Benefits

PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees and retirees (referred to collectively as “pension benefits”), contributory postretirement medical plans for eligible employees and retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees (referred to collectively as “other benefits”). PG&E Corporation and the Utility use a December 31 measurement date for all plans.

10        

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2011 and 2010 were as follows:

	Pension Benefits				Other Benefits
	Three Months Ended             September 30,				Three Months Ended     September 30,
(in millions)	2011		2010		2011		2010
Service cost for benefits earned		$76		$  70		$  9		$  8
Interest cost		167		162		23		21
Expected return on plan assets		(168)		(155)		(22)		(18)
Amortization of transition obligation		-		-		7		6
Amortization of prior service cost		8		13		8		7
Amortization of unrecognized loss		13		11		1		1
Net periodic benefit cost		96		101		26		25
Less: transfer to regulatory account (1)		(32)		(60)		-		-
Total		$  64		$  41		$  26		$  25
(1) The Utility recorded $32 million and $60 million for the three month periods ended September 30, 2011 and 2010, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates.
	Pension Benefits				Other Benefits
	Nine Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2011		2010		2011		2010
Service cost for benefits earned		$  240		$  209		$  31		$  27
Interest cost		495		484		69		66
Expected return on plan assets		(502)		(467)		(62)		(55)
Amortization of transition obligation		-		-		19		19
Amortization of prior service cost		26		39		20		19
Amortization of unrecognized loss		37		32		3		2
Net periodic benefit cost		296		297		80		78
Less: transfer to regulatory account (1)		(104)		(175)		-		-
Total		$  192		$  122		$  80		$  78
(1) The Utility recorded $104 million and $175 million for the nine month periods ended September 30, 2011 and 2010, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates.

There was no material difference between PG&E Corporation’s and the Utility’s consolidated net periodic benefit costs for the three and nine months ended September 30, 2011 and 2010.

Variable Interest Entities

The Utility has contracts to purchase energy and capacity from variable interest entities (“VIE”s). The Utility evaluated these contracts and determined that it either does not have a variable interest in the VIE or it is not the primary beneficiary of the VIE where a variable interest exists. The determination of whether the Utility has a variable interest in a VIE includes an analysis of the impact the power purchase agreement has on the variability in the VIE’s gross margin. The primary beneficiary determination considers which entity has the power to direct the activities of the VIE that are most significant to the VIE’s economic performance, and may include any decision-making rights associated with designing the VIE, dispatch rights, operating and maintenance activities, and re-marketing activities of the power plant after the end of the power purchase agreement with the Utility. The Utility’s financial exposure is limited to the amount it pays for delivered electricity and capacity. The Utility has not provided any other support to these VIEs. (See Note 10 below.)

The Utility has consolidated the accounts of PG&E Energy Recovery Funding LLC (“PERF”) at September 30, 2011 as the Utility continues to be the primary beneficiary of PERF. The Utility has determined that it is PERF’s primary beneficiary because the Utility is exposed to PERF’s losses and returns through the Utility’s 100% equity investment in PERF and the Utility was involved in the design of PERF, an activity that was significant to PERF’s economic performance. The assets of PERF were $593 million at September 30, 2011 and primarily consisted of assets related to energy recovery bonds, which are included in other noncurrent assets – regulatory assets in the Condensed Consolidated Balance Sheets. The liabilities of PERF were $529 million at September 30, 2011 and consisted of liabilities related to energy recovery bonds,

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which are included in current and noncurrent liabilities in the Condensed Consolidated Balance Sheets. (See Note 4 below.) The assets of PERF are only available to settle the liabilities of PERF and PERF’s creditors have no recourse to the Utility.

As of September 30, 2011, PG&E Corporation’s affiliates had entered into four tax equity agreements with two privately held companies to fund residential and commercial retail solar energy installations. Under these agreements, PG&E Corporation has agreed to provide lease payments and investment contributions of up to $398 million to these companies in exchange for the right to receive benefits from local rebates, federal investment tax credits or grants, and a share of the customer payments made to these companies. The majority of these amounts are recorded in other noncurrent assets – other in PG&E Corporation’s Condensed Consolidated Balance Sheets. As of September 30, 2011, PG&E Corporation had made total payments of $326 million under these tax equity agreements and received $115 million in benefits and customer payments. PG&E Corporation holds a variable interest in these companies as a result of these agreements. PG&E Corporation was not the primary beneficiary of and did not consolidate any of these companies at September 30, 2011. In making this determination, PG&E Corporation evaluated which party has control over these companies’ significant economic activities such as designing the companies, vendor selection, construction, customer selection, and re-marketing activities at the end of customer leases, and determined that these activities are under the control of these companies. PG&E Corporation’s financial exposure from these arrangements is generally limited to its lease payments and investment contributions to these companies.

Accounting Standards Issued But Not Yet Adopted

Amendments to Fair Value Measurement Requirements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update that will clarify certain fair value measurement requirements. In addition, the accounting standards update will permit an entity to measure the fair value of a portfolio of financial instruments based on the portfolio’s net position, provided that the portfolio has met certain criteria. Furthermore, the accounting standards update will refine when an entity should, and should not, apply certain premiums and discounts to a fair value measurement. The accounting standards update will be effective prospectively for PG&E Corporation and the Utility beginning on January 1, 2012. PG&E Corporation and the Utility are currently evaluating the impact of the accounting standards update.

Presentation of Comprehensive Income

In June 2011, the FASB issued an accounting standards update that will require an entity to present either (1) a statement of comprehensive income or loss or (2) a statement of other comprehensive income or loss. A statement of comprehensive income or loss would be comprised of a statement of income or loss with other comprehensive income and losses, total other comprehensive income or loss, and total comprehensive income or loss appended. A statement of other comprehensive income or loss would immediately follow a statement of income or loss and would be comprised of other comprehensive income and losses, total other comprehensive income or loss, and total comprehensive income or loss. In addition, under either approach, the accounting standards update will require an entity to present reclassifications between other comprehensive income or loss and net income or loss. Furthermore, the accounting standards update will prohibit an entity from presenting other comprehensive income and losses in a statement of equity. The accounting standards update will be effective retrospectively for PG&E Corporation and the Utility beginning on January 1, 2012. PG&E Corporation and the Utility are currently evaluating the impact of the accounting standards update.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

As a regulated entity, the Utility’s rates are designed to recover the costs of providing service. The Utility capitalizes and records, as a regulatory asset, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods that the costs are expected to be recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. In addition, amounts that are probable of being credited or refunded to customers in the future are recorded as regulatory liabilities.

A significant portion of the Utility’s recovery of authorized revenue requirements is independent, or “decoupled”, from the volume of electricity and natural gas sales. As a result, differences occur between actual billed and unbilled revenues and the Utility’s authorized revenue requirement. The Utility records these differences in regulatory balancing accounts. The Utility also uses regulatory balancing accounts to record differences between incurred costs and actual billed and unbilled revenues and differences between incurred costs and authorized revenue meant to recover those costs. Under-collections that are probable of recovery through regulated rates are recorded as regulatory balancing account assets. Over-collections that are probable of being refunded to customers are recorded as regulatory balancing account liabilities.

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Regulatory Assets

Current Regulatory Assets

At September 30, 2011 and December 31, 2010, the Utility had current regulatory assets of $680 million and $599 million, respectively, consisting primarily of price risk management regulatory assets and the Utility’s retained generation regulatory assets. The current portion of price risk management regulatory assets represents the deferral of unrealized losses related to price risk management derivative instruments with terms of one year or less. (See Note 7 below.) The current portion of the Utility’s retained generation regulatory assets represents one year of amortization of these regulatory assets over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. In addition, at September 30, 2011, current regulatory assets included the current portion of the Utility’s regulatory asset that represents the net book value of electromechanical meters that have been replaced with SmartMeter™ devices. The Utility expects to recover this regulatory asset over the next six years.

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

	Balance at
(in millions)	September 30, 2011		December 31, 2010
Pension benefits		$  1,801		$  1,759
Deferred income taxes		1,371		1,250
Utility retained generation		628		666
Energy recovery bonds		435		735
Environmental compliance costs		470		450
Price risk management		297		424
Undepreciated conventional electromechanical meters		260		-
Unamortized loss, net of gain, on reacquired debt		168		181
Other		284		381
Total long-term regulatory assets		$  5,714		$  5,846

The regulatory asset for pension benefits represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP, which also includes amounts that otherwise would be fully recorded to accumulated other comprehensive loss in the Condensed Consolidated Balance Sheets. (See Note 12 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.)

The regulatory assets for deferred income taxes represent deferred income tax benefits previously passed through to customers. The CPUC requires the Utility to pass through certain tax benefits to customers by reducing rates, thereby ignoring the effect of deferred taxes on rates. Based on current regulatory ratemaking and income tax laws, the Utility expects to recover these regulatory assets over average plant depreciation lives of 1 to 45 years.

In connection with the settlement agreement entered into between PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11 Settlement Agreement”), the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. The weighted average remaining life of the assets is 13 years.

The regulatory asset for energy recovery bonds represents the refinancing of the regulatory asset provided for in the Chapter 11 Settlement Agreement. (See Note 4 below.) The regulatory asset is amortized over the life of the bonds, consistent with the period over which the related revenues and bond-related expenses are recognized. The Utility expects to fully recover this asset by the end of 2012 when the bonds mature.

The regulatory assets for environmental compliance costs represent the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP. The Utility expects to recover these costs over the next 32 years as the environmental compliance work is performed. (See Note 10 below.)

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Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative instruments with terms in excess of one year. The Utility expects to recover these losses as they are realized over the next 11 years. (See Note 7 below.)

The regulatory asset for undepreciated conventional electromechanical meters represents the net book value of electromechanical meters that have been replaced with SmartMeter™ devices, as discussed above.

The regulatory assets for unamortized loss, net of gain, on reacquired debt represent costs related to debt reacquired or redeemed prior to maturity with associated discount and debt issuance costs. These costs are expected to be recovered over the next 15 years, which is the remaining amortization period of the reacquired debt. The Utility expects to fully recover these costs by 2026.

At September 30, 2011 and December 31, 2010, “other” primarily consisted of regulatory assets relating to ARO expenses for decommissioning of the Utility’s fossil-fuel generation facilities that are probable of future recovery through the ratemaking process; costs that the Utility incurred in terminating a 30-year power purchase agreement which are being amortized and collected in rates through September 2014; and advisory fees incurred in relation to the Utility’s plan of reorganization under Chapter 11 that became effective in April 2004 and are being amortized and collected in rates through April 2034.

In general, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return only on its retained generation regulatory assets and regulatory assets for unamortized loss, net of gain, on reacquired debt.

Regulatory Liabilities

Current Regulatory Liabilities

At September 30, 2011 and December 31, 2010, the Utility had current regulatory liabilities of $120 million and $81 million, respectively, primarily consisting of amounts that the Utility expects to refund to customers for over-collected electric transmission rates and amounts that the Utility expects to refund to electric transmission customers for their portion of settlements the Utility entered into with various electricity suppliers to resolve certain remaining Chapter 11 disputed claims. (See Note 9 below.) Current regulatory liabilities are included in current liabilities – other in the Condensed Consolidated Balance Sheets.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

	Balance at
(in millions)	September 30, 2011		December 31, 2010
Cost of removal obligation		$  3,394		$  3,229
Recoveries in excess of ARO		559		600
Public purpose programs		500		573
Other		143		123
Total long-term regulatory liabilities		$  4,596		$  4,525

The regulatory liability for the Utility’s cost of removal obligations represents differences between amounts collected in rates for asset removal costs and the asset removal costs recorded in accordance with GAAP.

The regulatory liability for recoveries in excess of ARO represents differences between ARO expenses recorded in accordance with GAAP and amounts collected in rates for the decommissioning of the Utility’s nuclear power facilities. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The regulatory liability for recoveries in excess of ARO also represents the deferral of realized and unrealized gains and losses on those nuclear decommissioning trust assets.

The regulatory liability for public purpose programs represents amounts received from customers designated for public purpose program costs that are expected to be incurred in the future. The public purpose programs regulatory liabilities primarily consist of revenues collected from customers to pay for costs that the Utility expects to incur in the future under energy efficiency programs designed to encourage the manufacture, design, distribution, and customer use of energy

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efficient appliances and other energy-using products; under the California Solar Initiative program to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties; and under the Self-Generation Incentive program to promote distributed generation technologies installed on the customer’s side of the Utility meter that provide electricity and gas for all or a portion of that customer’s load.

“Other” at September 30, 2011 and December 31, 2010 primarily consisted of regulatory liabilities related to the gain associated with the Utility’s acquisition of the permits and other assets related to the Gateway Generating Station as part of a settlement that the Utility entered into with Mirant Corporation, insurance recoveries for hazardous substance remediation, and the price risk management regulatory liabilities representing the deferral of unrealized gains related to price risk management derivative instruments with terms in excess of one year. (See Note 7 below.)

Regulatory Balancing Accounts

The Utility’s current regulatory balancing accounts represent the amounts expected to be received from or refunded to the Utility’s customers through authorized rate adjustments within the next 12 months. Regulatory balancing accounts that the Utility does not expect to collect or refund in the next 12 months are included in other noncurrent assets – regulatory assets and noncurrent liabilities – regulatory liabilities in the Condensed Consolidated Balance Sheets.

Current Regulatory Balancing Accounts, net

	Receivable (Payable)
	Balance at
(in millions)	September 30, 2011		December 31, 2010
Utility generation		$  173		$  303
Distribution revenue adjustment mechanism		145		145
Gas fixed cost		115		56
Public purpose programs		98		164
Hazardous substance		57		38
Energy recovery bonds		(118)		(34)
Energy procurement		(70)		(25)
Other		242		202
Total regulatory balancing accounts, net		$  642		$  849

The utility generation balancing account is used to record and recover the authorized revenue requirements associated with Utility-owned electric generation, including capital and related non-fuel operating and maintenance expenses. The distribution revenue adjustment mechanism balancing account is used to record and recover the authorized electric distribution revenue requirements and certain other electric distribution-related authorized costs. The Utility’s recovery of these revenue requirements is decoupled from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers will fluctuate depending on the volume of electricity sales. During the colder months of winter there is generally an under-collection in these balancing accounts due to lower electricity sales and lower rates. During the warmer months of summer there is generally an over-collection due to higher electricity sales and higher rates.

The gas fixed cost balancing account is used to track the recovery of CPUC-authorized gas distribution revenue requirements and certain other gas distribution-related costs. Similar to the utility generation and the distribution revenue adjustment mechanism balancing accounts discussed above, the Utility’s recovery of these revenue requirements is decoupled from the volume of sales. During the colder months of winter there is generally an over-collection in this balancing account primarily due to higher natural gas sales. During the warmer months of summer there is generally an under-collection primarily due to lower natural gas sales.

The public purpose programs balancing accounts are primarily used to track the recovery of the authorized public purpose program revenue requirements and incentive awards earned by the Utility for implementing customer energy efficiency programs. The public purpose programs primarily consist of the energy efficiency programs; low-income energy efficiency programs; research, development, and demonstration programs; and renewable energy programs.

The hazardous substance balancing accounts are used to track recoverable hazardous substance remediation costs through the CPUC-approved ratemaking mechanism that authorizes the Utility to recover 90% of such costs. The current

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balance represents eligible remediation costs incurred by the Utility during 2010 that are expected to be recovered during 2012. (See Note 10 below.)

The balancing account for energy recovery bonds records the benefits and costs associated with bonds that are provided to, or received from, customers. This account ensures that customers receive the benefits of the net amount of energy supplier refunds, claim offsets, and other credits received by the Utility.

The Utility is generally authorized to recover 100% of its prudently incurred electric fuel and energy procurement costs. The Utility tracks energy procurement costs in balancing accounts and files annual forecasts of energy procurement costs that it expects to incur during the following year. The Utility’s electric rates are set to recover such expected costs.

At September 30, 2011 and December 31, 2010, “other” primarily consisted of balancing accounts that track recovery of the authorized revenue requirements and costs related to the SmartMeter^TM advanced metering project. In addition, at September 30, 2011, “other” included balancing accounts that were authorized by the 2011 General Rate Case to track the recovery of meter reading costs.

NOTE 4: DEBT

Revolving Credit Facilities - PG&E Corporation and the Utility

On May 31, 2011, PG&E Corporation entered into a $300 million revolving credit facility with a syndicate of lenders. This revolving credit facility replaced the $187 million revolving credit facility that PG&E Corporation entered into on February 26, 2007 (amended April 27, 2009). Also on May 31, 2011, the Utility entered into a $3.0 billion revolving credit facility with a syndicate of lenders. This revolving credit facility replaced the $1.9 billion revolving credit facility that the Utility entered into on February 26, 2007 (amended April 27, 2009), and the $750 million revolving credit facility that the Utility entered into on June 8, 2010. The revolving credit facilities have terms of five years and all amounts are due and payable on the facilities’ termination date, May 31, 2016. At PG&E Corporation’s and the Utility’s request and at the sole discretion of each lender, the facilities may be extended for additional periods. The revolving credit facilities may be used for working capital and other corporate purposes, including commercial paper back-up.

Provided certain conditions are met, PG&E Corporation and the Utility have the right to increase, in one or more requests, given not more frequently than once a year, the aggregate lenders’ commitments under the revolving credit facilities by up to $100 million and $500 million, respectively, in the aggregate for all such increases.

Borrowings under the revolving credit facilities (other than swingline loans) will bear interest based, at PG&E Corporation’s and the Utility’s election, on (1) a London Interbank Offered Rate (“LIBOR”) plus an applicable margin or (2) the base rate plus an applicable margin. The base rate will equal the higher of the following: the administrative agent’s announced base rate, 0.5% above the federal funds rate, or the one-month LIBOR plus an applicable margin. Interest is payable quarterly in arrears, or earlier for loans with shorter interest periods. PG&E Corporation and the Utility also will pay a facility fee on the total commitments of the lenders under the revolving credit facilities. The applicable margins and the facility fees will be based on PG&E Corporation’s and the Utility’s senior unsecured debt ratings issued by Standard & Poor’s Rating Services and Moody’s Investor Service. Facility fees are payable quarterly in arrears.

The revolving credit facilities include usual and customary covenants for revolving credit facilities of this type, including covenants limiting liens to those permitted under PG&E Corporation’s and the Utility’s senior note indentures, mergers, sales of all or substantially all of PG&E Corporation’s and the Utility’s assets, and other fundamental changes. In addition, the revolving credit facilities require that PG&E Corporation and the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% as of the end of each fiscal quarter. The $300 million revolving credit facility agreement also requires that PG&E Corporation must own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting capital stock of the Utility. At September 30, 2011, PG&E Corporation and the Utility were in compliance with all covenants under each of the revolving credit facilities.

At September 30, 2011, PG&E Corporation had $75 million of cash borrowings outstanding under its $300 million revolving credit facility which had an interest rate of 1.42%.

At September 30, 2011, the Utility had no cash borrowings and $335 million of letters of credit outstanding under its $3.0 billion revolving credit facility.

The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facility. At September 30, 2011, the Utility had $801 million of commercial paper outstanding.

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Utility

Senior Notes

On May 13, 2011, the Utility issued $300 million principal amount of 4.25% Senior Notes due May 15, 2021.

On September 12, 2011, the Utility issued $250 million principal amount of 3.25% Senior Notes due September 15, 2021.

Pollution Control Bonds

The California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank have issued various series of tax-exempt pollution control bonds for the benefit of the Utility. The payments on the Series 1996 C, E, and F bonds; the Series 1997 B bonds; and the Series 2009 A-D bonds are made through draws on separate direct-pay letters of credit issued by a financial institution for each series. On May 31, 2011, new letters of credit were substituted for the letters of credit supporting the Series 2009 A-D bonds. The substitute letters of credit expire on May 31, 2016. In connection with the substitutions, the Utility entered into new reimbursement agreements related to the substitute letters of credit. Also on May 31, 2011, the Utility extended the letters of credit supporting the Series 1996 C, E, and F bonds, and the Series 1997 B bonds, and amended and restated the reimbursement agreements related to such bonds into a single reimbursement agreement. The new termination date of the letters of credit is May 31, 2016.

On September 30, 2011, the Utility redeemed all of the Series 1996 A bonds in the principal amount of $200 million.

Other Short-term Borrowings

At September 30, 2011, the interest rate on the Utility’s $250 million principal amount of Floating Rate Senior Notes was 0.83%. The interest rate on these notes remained at 0.83% until their maturity on October 11, 2011.

Energy Recovery Bonds

In 2005, PERF issued two separate series of bonds in the aggregate amount of $2.7 billion. PERF used the bond proceeds to purchase from the Utility the right, known as “recovery property,” to be paid a specified amount from a dedicated rate component to be collected from the Utility’s electricity customers. The total amount of bond principal outstanding was $528 million at September 30, 2011.

While PERF is a wholly owned subsidiary of the Utility, it is legally separate from the Utility. The assets (including the recovery property) of PERF are not available to creditors of the Utility or PG&E Corporation, and the recovery property is not legally an asset of the Utility or PG&E Corporation.

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NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the nine months ended September 30, 2011 were as follows:

	PG&E Corporation		Utility
(in millions)	Total Equity		Total      Shareholders’ Equity
Balance at December 31, 2010		$  11,534		$  11,721
Net income		771		756
Common stock issued		409		-
Share-based compensation expense		30		-
Common stock dividends declared		(550)		(537)
Preferred stock dividend requirement		-		(10)
Preferred stock dividend requirement of subsidiary		(10)		-
Other comprehensive income		26		26
Equity contribution		-		350
Other		1		1
Balance at September 30, 2011		$  12,211		$  12,307

For the nine months ended September 30, 2011, PG&E Corporation issued 5,332,780 shares of common stock under its 401(k) plan, its Dividend Reinvestment and Stock Purchase Plan, and upon exercise of employee stock options.

On May 9, 2011, PG&E Corporation entered into an Equity Distribution Agreement pursuant to which PG&E Corporation’s sales agents may offer and sell, from time to time, PG&E Corporation common stock having an aggregate gross offering price of up to $288 million. This amount represents the approximate unissued amount of the $400 million program previously announced on November 4, 2010. Sales of the shares are made by means of ordinary brokers’ transactions on the New York Stock Exchange, or in such other transactions as agreed upon by PG&E Corporation and the sales agents and in conformance with applicable securities laws. For the nine months ended September 30, 2011, PG&E Corporation issued 4,388,034 shares of common stock under the Equity Distribution Agreement for cash proceeds of $185 million, net of fees and commissions paid of $2 million.

For the nine months ended September 30, 2011, PG&E Corporation contributed equity of $350 million to the Utility in order to maintain the 52% common equity ratio authorized by the CPUC.

Comprehensive Income

Comprehensive income consists of net income and other comprehensive income, which includes certain changes in equity that are excluded from net income. Specifically, adjustments for employee benefit plans, net of tax, are recorded in other comprehensive income. PG&E Corporation’s comprehensive income for the three and nine months ended September 30, 2011 and 2010 was as follows:

	PG&E Corporation
	Three Months Ended     September 30,				Nine Months Ended         September 30,
(in millions)	2011		2010		2011		2010
Net income		$  203		$  261		$  771		$  859
Employee benefit plan adjustment, net of tax (1)		8		8		26		(64)
Comprehensive Income		$  211		$  269		$  797		$  795
(1) These balances are net of income tax expense of $6 million and $7 million for the three months ended September 30, 2011 and 2010, respectively. For the nine months ended September 30, 2011 and 2010, the income tax expense was $17 million and the income tax benefit was $42 million, respectively.

There was no material difference between PG&E Corporation’s and the Utility’s consolidated comprehensive income for the three and nine months ended September 30, 2011 and 2010.

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NOTE 6: EARNINGS PER SHARE

For the three and nine months ended September 30, 2011, PG&E Corporation’s basic earnings per common share (“EPS”) was calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. For the three and nine months ended September 30, 2010, PG&E Corporation calculated EPS using the “two-class” method because PG&E Corporation’s convertible subordinated notes that were outstanding prior to June 29, 2010 were considered to be participating securities under applicable accounting standards. Under the two-class method, the sum of distributed earnings to common shareholders and undistributed earnings allocated to common shareholders is divided by the weighted average number of common shares outstanding during the period. In applying the two-class method, undistributed earnings were allocated to both common shares and participating securities. Since all of PG&E Corporation’s convertible subordinated notes have been converted into common stock, there were no participating securities outstanding as of September 30, 2011.

The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating basic EPS for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended     September 30,				Nine Months Ended     September 30,
(in millions, except per share amounts)	2011		2010		2011		2010
Basic
Income available for common shareholders		$  200		$ 258		$  761		$  849
Less: distributed earnings to common shareholders		-		179		-		527
Undistributed earnings		$ -		$ 79		$ -		$  322
Allocation of undistributed earnings to common shareholders
Distributed earnings to common shareholders		$ -		$ 179		$ -		$  527
Undistributed earnings allocated to common shareholders		-		79		-		313
Total common shareholders earnings		$ -		$ 258		$ -		$  840
Weighted average common shares outstanding, basic		403		390		399		378
Convertible subordinated notes		-		-		-		11
Weighted average common shares outstanding and participating securities		403		390		399		389
Net earnings per common share, basic
Distributed earnings, basic (1)		$ -		$  0.46		$ -		$  1.39
Undistributed earnings, basic		-		0.20		-		0.83
Total		$  0.50		$  0.66		$  1.91		$  2.22

⁽¹⁾  Distributed earnings, basic may differ from actual per share amounts paid as dividends, as the EPS computation under GAAP requires the use of the weighted average, rather than the actual, number of shares outstanding.

In calculating diluted EPS, PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation. During 2010, when PG&E Corporation’s convertible subordinated notes were outstanding, the “if-converted” method was also applied in calculating diluted EPS to reflect the dilutive effect of the convertible subordinated notes to the extent that the impact was dilutive when compared to basic EPS. As noted above, these convertible subordinated notes were fully converted into shares of common stock in 2010 and were not outstanding during 2011.

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The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating diluted EPS for the three and nine months ended September 30, 2011:

	Three Months     Ended		Nine Months     Ended
(in millions, except per share amounts)	September 30,     2011		September 30,     2011
Diluted
Income available for common shareholders		$  200		$  761
Weighted average common shares outstanding, basic		403		399
Add incremental shares from assumed conversions:
Employee share-based compensation		1		1
Weighted average common shares outstanding, diluted		404		400
Net earnings per common share, diluted		$  0.50		$  1.90

The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating diluted EPS for the three and nine months ended September 30, 2010:

(in millions, except per share amounts)	Three Months     Ended		Nine Months     Ended
	September 30,     2010		September 30,     2010
Diluted
Income available for common shareholders		$  258		$  849
Add earnings impact of assumed conversion of participating securities:
Interest expense on convertible subordinated notes, net of tax		-		8
Income available for common shareholders and assumed conversion		$  258		$  857
Weighted average common shares outstanding, basic		390		378
Add incremental shares from assumed conversions:
Convertible subordinated notes		-		11
Employee share-based compensation		2		2
Weighted average common shares outstanding, diluted		392		391
Net earnings per common share, diluted		$  0.66		$  2.19

For each of the periods presented above, the calculation of outstanding shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

NOTE 7: DERIVATIVES AND HEDGING ACTIVITIES

Use of Derivative Instruments

The Utility and PG&E Corporation, mainly through its ownership of the Utility, face market risk primarily related to electricity and natural gas commodity prices. All of the Utility’s risk management activities involving derivatives reduce the volatility of commodity costs on behalf of its customers. The CPUC allows the Utility to charge customer rates designed to recover the Utility’s reasonable costs of providing services, including the cost to obtain and deliver electricity and natural gas.

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The Utility uses both derivative and non-derivative contracts in managing its customers’ exposure to commodity-related price risk, including:

• forward contracts that commit the Utility to purchase a commodity in the future;

• swap agreements that require payments to or from counterparties based upon the difference between two prices for a predetermined contractual quantity; and

• option contracts that provide the Utility with the right to buy a commodity at a predetermined price.

These instruments are not held for speculative purposes and are subject to certain regulatory requirements.

Commodity-related price risk management activities that meet the definition of a derivative are recorded at fair value on the Condensed Consolidated Balance Sheets. As long as the ratemaking mechanisms discussed above remain in place and the Utility’s risk management activities are carried out in accordance with CPUC directives, the Utility expects to fully recover from customers, in rates, all costs related to commodity derivative instruments. Therefore, all unrealized gains and losses associated with the change in fair value of these derivative instruments are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. (See Note 3 above.) Net realized gains or losses on commodity derivative instruments are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from customers.

The Utility elects the normal purchase and sale exception for qualifying commodity derivative instruments. Derivative instruments that require physical delivery, are probable of physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered are eligible for the normal purchase and sale exception. The fair value of instruments that are eligible for the normal purchase and sales exception are not reflected in the Condensed Consolidated Balance Sheets.

Electricity Procurement

The Utility enters into third-party power purchase agreements to ensure sufficient supply of electricity to meet customer needs. The Utility’s third-party power purchase agreements are generally accounted for as leases, but certain third-party power purchase agreements are considered derivative instruments. The Utility elects to use the normal purchase and sale exception for eligible derivative instruments.

A portion of the Utility’s third-party power purchase agreements contain market-based pricing terms. In order to reduce volatility in customer rates, the Utility enters into financial swap contracts to effectively fix the price of future purchases and reduce cash flow variability associated with fluctuating electricity prices. These financial swaps are considered derivative instruments.

Electric Transmission Congestion Revenue Rights

The California electric transmission grid, controlled by the California Independent System Operator (“CAISO”), is subject to transmission constraints when there is insufficient transmission capacity to supply the market resulting in transmission congestion. The CAISO imposes congestion charges on market participants to manage transmission congestion. To allocate the congestion revenues among the market participants the CAISO has created congestion revenue rights (“CRRs”) to allow market participants to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. The CAISO releases CRRs through an annual and monthly process, each of which includes an allocation phase (in which load-serving entities such as the Utility are allocated CRRs at no cost based on the customer demand or “load” they serve) and an auction phase (in which CRRs are priced at market and available to all market participants). The Utility participates in the allocation and auction phases of the annual and monthly CRR processes. The CRRs held by the Utility are considered derivative instruments.

Natural Gas Procurement (Electric Fuels Portfolio)

The Utility’s electric procurement portfolio is exposed to natural gas price risk primarily through physical natural gas commodity purchases to fuel Utility-owned natural gas generating facilities and tolling agreements, and electricity procurement contracts indexed to natural gas prices. To reduce the volatility in customer rates, the Utility purchases financial instruments such as swaps and options to reduce future cash flow variability from fluctuating natural gas prices. These financial instruments are considered derivative instruments.

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Natural Gas Procurement (Core Gas Supply Portfolio)

The Utility enters into physical natural gas commodity contracts to fulfill the needs of its residential and smaller commercial customers known as “core” customers. (The Utility does not procure natural gas for industrial and large commercial, or “non-core,” customers.) Changes in temperature cause natural gas demand to vary daily, monthly, and seasonally. Consequently, varying volumes of gas may be purchased or sold in the multi-month, monthly, and to a lesser extent, daily spot market to balance such seasonal supply and demand. The Utility purchases financial instruments such as swaps and options as part of its core winter hedging program in order to manage customer exposure to high gas prices during peak winter months. These financial instruments are considered derivative instruments.

Volume of Derivative Activity

At September 30, 2011, the volumes of PG&E Corporation’s and the Utility’s outstanding derivative contracts were as follows:

		Contract Volume (1)
Underlying Product	Instruments	Less Than 1 Year	Greater Than     1 Year but     Less Than 3     Years	Greater Than     3 Years but     Less Than 5     Years	Greater Than     5 Years (2)
Natural Gas (3) (MMBtus (4))	Forwards and      Swaps	520,257,890	247,388,834	9,990,000	-
	Options	251,652,959	313,795,682	23,700,000	-
Electricity (Megawatt-hours)	Forwards and      Swaps	4,703,003	5,648,312	2,528,599	3,903,048
	Options	2,074	106,980	264,348	289,164
	Congestion      Revenue Rights	49,296,971	72,732,318	72,771,156	69,900,050

⁽¹⁾ Amounts shown reflect the total gross derivative volumes by commodity type that are expected to settle in each time period.

⁽²⁾ Derivatives in this category expire between 2016 and 2022.

⁽³⁾ Amounts shown are for the combined positions of the electric fuels and core gas portfolios.

⁽⁴⁾ Million British Thermal Units.

Presentation of Derivative Instruments in the Financial Statements

In PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets, derivative instruments are presented on a net basis by counterparty where the right of offset exists under a master netting agreement. The net balances include outstanding cash collateral associated with derivative positions.

At September 30, 2011, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

	Gross Derivative     Balance		Netting		Cash Collateral		Total Derivative     Balances
(in millions)	Commodity Risk (PG&E Corporation and the Utility)
Current assets – other		$  45		$  (37)		$  157		$  165
Other noncurrent assets – other		130		(97)		-		33
Current liabilities – other		(425)		37		210		(178)
Noncurrent liabilities – other		(394)		97		37		(260)
Total commodity risk		$  (644)		$  -		$  404		$  (240)

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At December 31, 2010, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

	Gross Derivative     Balance		Netting		Cash Collateral		Total Derivative     Balances
(in millions)	Commodity Risk (PG&E Corporation and the Utility)
Current assets – other		$  56		$  (45)		$  79		$  90
Other noncurrent assets – other		77		(62)		96		111
Current liabilities – other		(388)		45		119		(224)
Noncurrent liabilities – other		(486)		62		130		(294)
Total commodity risk		$  (741)		$  -		$  424		$  (317)

Gains and losses recorded on PG&E Corporation’s and the Utility’s derivative instruments were as follows:

	Commodity Risk (PG&E  Corporation and Utility)
	Three months ended          September 30,				Nine months ended          September 30,
(in millions)	2011		2010		2011		2010
Unrealized (loss) gain - regulatory assets and liabilities (1)		$  (61)		$  (222)		$  97		$  (493)
Realized loss - cost of electricity (2)		(149)		(154)		(406)		(435)
Realized loss - cost of natural gas (2)		(4)		(6)		(66)		(50)
Total commodity risk instruments		$  (214)		$  (382)		$  (375)		$  (978)
(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings. (2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.

Cash inflows and outflows associated with the settlement of all derivative instruments are included in operating cash flows on PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Cash Flows.

The majority of the Utility’s commodity risk-related derivative instruments contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. As of September 30, 2011, the Utility’s credit rating was investment grade. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to immediately post additional cash to fully collateralize its net liability derivative positions.

At September 30, 2011, the additional cash collateral that the Utility would be required to post if its credit risk-related contingency features were triggered was as follows:

(in millions)
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized	$  (508)
Related derivatives in an asset position	8
Collateral posting in the normal course of business related to these derivatives	69
Net position of derivative contracts/additional collateral posting requirements (1)	$  (431)
(1)  This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit risk-related contingencies.

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NOTE 8: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, trust assets, and price risk management instruments at fair value. Fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or a liability. A three-tier fair value hierarchy is established as a basis for considering such assumptions and for inputs used in the valuation methodologies in measuring fair value:

Level 1 - Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 - Other inputs that are directly or indirectly observable in the marketplace.

Level 3 - Unobservable inputs which are supported by little or no market activities.

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

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Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below (money market investments and assets held in rabbi trusts are held by PG&E Corporation and not the Utility). The 2010 presentation has been changed to reflect gross assets and liabilities by level to conform to the current period presentation. Additionally, the Company corrected $125 million that was netted and classified inappropriately between Level 3 price risk management instrument assets and liabilities and other immaterial price risk management instrument changes.

	Fair Value Measurements
	At September 30, 2011										At December 31, 2010
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total		Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments		$  223		$  -		$  -		$  -		$  223		$  138		$  -		$  -		$  -		$  138
Nuclear decommissioning trusts
U.S. equity securities		786		12		-		-		798		1,029		7		-		-		1,036
Non-U.S. equity securities		311		-		-		-		311		349		-		-		-		349
U.S. government and agency securities		715		150		-		-		865		584		40		-		-		624
Municipal securities		-		65		-		-		65		-		119		-		-		119
Other fixed-income securities		-		94		-		-		94		-		66		-		-		66
Total nuclear decommissioning trusts (2)		1,812		321		-		-		2,133		1,962		232		-		-		2,194
Price risk management instruments (Note 7)
Electric		-		-		166		24		190		6		2		119		63		190
Gas		-		-		9		(1)		8		-		-		6		5		11
Total price risk management instruments		-		-		175		23		198		6		2		125		68		201
Rabbi trusts
Fixed-income securities		-		26		-		-		26		-		24		-		-		24
Life insurance contracts		-		67		-		-		67		-		65		-		-		65
Total rabbi trusts		-		93		-		-		93		-		89		-		-		89
Long-term disability trust
U.S. equity securities		4		13		-		-		17		11		24		-		-		35
Non-U.S. equity securities		-		9		-		-		9		-		-		-		-		-
Fixed-income securities		-		132		-		-		132		-		150		-		-		150
Total long-term disability trust		4		154		-		-		158		11		174		-		-		185
Total assets		$  2,039		$  568		$  175		$  23		$  2,805		$  2,117		$  497		$  125		$  68		$  2,807
Liabilities:
Price risk management instruments (Note 7)
Electric		$  299		$  12		$  448		$  (329)		$  430		$  235		$  73		$  475		$  (315)		$  468
Gas		49		3		8		(52)		8		41		1		49		(41)		50
Total liabilities		$  348		$  15		$  456		$  (381)		$  438		$  276		$  74		$  524		$  (356)		$  518

⁽¹⁾    Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

⁽²⁾    Excludes $169 million and $185 million at September 30, 2011 and December 31, 2010, respectively, primarily related to deferred taxes on appreciation of investment value.

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Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above.

Money Market Investments

PG&E Corporation invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, such as treasury bills, federal agency securities, certificates of deposit, and commercial paper with a maximum weighted average maturity of 60 days or less. PG&E Corporation’s investments in these money market funds are generally valued using unadjusted quotes in an active market for identical assets and are thus classified as Level 1. Money market funds are recorded as cash and cash equivalents in PG&E Corporation’s Condensed Consolidated Balance Sheets.

Trust Assets

The assets held by the nuclear decommissioning trusts, the rabbi trusts related to the non-qualified deferred compensation plans, and the long-term disability trust are composed primarily of equity securities and debt securities. In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.

Equity securities primarily include investments in common stock, which are valued based on unadjusted prices in active markets for identical transactions and are classified as Level 1. Equity securities also include commingled funds composed of equity securities traded publicly on exchanges across multiple industry sectors in the U.S. and other regions of the world, which are classified as Level 2. Price quotes for the assets held by these funds are readily observable and available.

Debt securities are composed primarily of fixed-income securities that include U.S. government and agency securities, municipal securities, and corporate debt securities. U.S. government and agency securities consist primarily of treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market-based valuation approach is generally used to estimate the fair value of debt securities classified as Level 2. Under a market approach, fair values are determined based on evaluated pricing data, such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable.

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as forwards, swaps, options, and CRRs that are either exchange-traded or over-the-counter traded. (See Note 7 above.)

Forwards and swaps that are valued using observable market prices for the underlying commodity or an identical instrument are classified as Level 1 or Level 2. Forwards and swaps that are valued using unobservable data are considered Level 3. These contracts are valued using either estimated basis adjustments from liquid trading points or techniques including extrapolation from observable prices when a contract term extends beyond a period for which market data is available.

All commodity-related options are classified as Level 3 and are valued using a standard option pricing model with various assumptions, including forward prices for the underlying commodity, time value at a risk free rate, and volatility. For periods in which market data is not available, the Utility extrapolates these assumptions using internal models.

The Utility holds CRRs to hedge financial risk of CAISO-imposed congestion charges in the day-ahead markets. CRRs are valued based on prices observed in the auction which are extrapolated and discounted at the risk free rate. Limited market data is available between auction dates; therefore, CRRs are classified as Level 3.

Transfers between Levels

PG&E Corporation and the Utility recognize any transfers between levels in the fair value hierarchy as of the end of the reporting period. There were no significant transfers between levels for the nine months ended September 30, 2011.

26        

Level 3 Reconciliation

The following tables present reconciliations for price risk management instruments measured and recorded at fair value on a recurring basis for PG&E Corporation and the Utility, using significant unobservable inputs (Level 3), for the three months ended September 30, 2011 and 2010, respectively:

(in millions)	Price Risk Management Instruments
	2011		2010
Liability balance as of July 1		$  (280)		$  (470)
Realized and unrealized gains (losses):
Included in cost of electricity or cost of natural gas (1)		4		(14)
Included in regulatory assets and liabilities		(89)		(223)
Purchases, issuances, sales, and settlements:
Purchases		53		49
Settlements		31		60
Liability balance as of September 30		$  (281)		$  (598)

⁽¹⁾  Balancing account revenue is recorded for these amounts, therefore, there is no impact to net income.

The following tables present the reconciliation for Level 3 price risk management instruments for the nine months ended September 30, 2011 and 2010, respectively:

(in millions)	Price Risk Management Instruments
	2011		2010
Liability balance as of January 1		$  (399)		$  (250)
Realized and unrealized gains (losses):
Included in cost of electricity or cost of natural gas (1)		20		(76)
Included in regulatory assets and liabilities		(190)		(558)
Purchases, issuances, sales, and settlements:
Purchases		153		141
Settlements		135		145
Liability balance as of September 30		$  (281)		$  (598)

⁽¹⁾  Balancing account revenue is recorded for these amounts, therefore, there is no impact to net income.

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments:

• The fair values of cash, restricted cash, deposits, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at September 30, 2011 and December 31, 2010, as they are short term in nature or have interest rates that reset daily.

• The fair values of the Utility’s fixed rate senior notes and fixed rate pollution control bond loan agreements, PG&E Corporation’s fixed rate senior notes, and the energy recovery bonds issued by PERF were based on quoted market prices at September 30, 2011 and December 31, 2010.

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The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):

	At September 30, 2011				At December 31, 2010
(in millions)	Carrying     Amount		Fair Value		Carrying   Amount		Fair Value
Debt (Note 4)
PG&E Corporation		$ 349		$ 385		$ 349		$ 383
Utility		10,295		11,797		10,444		11,314
Energy recovery bonds (Note 4)		528		544		827		862

Nuclear Decommissioning Trust Investments

The Utility classifies its investments held in the nuclear decommissioning trust as “available-for-sale.” As the day-to-day investing activities of the trusts are managed by external investment managers, the Utility is unable to assert that it has the intent and ability to hold investments to maturity. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. (See Note 3 above for further discussion.)

The following table provides a summary of available-for-sale investments held in the Utility’s nuclear decommissioning trusts:

(in millions)	Amortized     Cost		Total   Unrealized   Gains		Total   Unrealized   Losses		Total Fair     Value (1)
As of September 30, 2011
Equity securities
U.S.		$  377		$  432		$  (11)		$  798
Non-U.S.		201		119		(9)		311
Debt securities
U.S. government and agency securities		764		101		-		865
Municipal securities		63		2		-		65
Other fixed-income securities		91		3		-		94
Total		$  1,496		$  657		$  (20)		$  2,133
As of December 31, 2010
Equity securities
U.S.		$  509		$  529		$  (2)		$  1,036
Non-U.S.		180		170		(1)		349
Debt securities
U.S. government and agency securities		571		55		(2)		624
Municipal securities		119		1		(1)		119
Other fixed-income securities		65		1		-		66
Total		$  1,444		$  756		$  (6)		$  2,194

⁽¹⁾  Excludes $169 million and $185 million at September 30, 2011 and December 31, 2010, respectively, primarily related to deferred taxes on appreciation of investment value.

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The debt securities mature on the following schedule:

(in millions)	As of September 30, 2011
Less than 1 year		$ 61
1–5 years		326
5–10 years		299
More than 10 years		338
Total maturities of debt securities		$ 1,024

The following table provides a summary of activity for the debt and equity securities:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
(in millions)
Proceeds from sales and maturities of nuclear decommissioning trust investments		$ 567		$ 277		$ 1,574		$ 962
Gross realized gains on sales of securities held as available-for-sale		11		4		40		26
Gross realized losses on sales of securities held as available-for-sale		(7)		(2)		(14)		(8)

NOTE 9: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

Various electricity suppliers filed claims in the Utility’s Chapter 11 Settlement Agreement seeking payment for energy supplied to the Utility’s customers through the wholesale electricity markets operated by the CAISO and the California Power Exchange (“PX”) between May 2000 and June 2001. These claims, which the Utility disputes, are being addressed in various FERC and judicial proceedings in which the State of California, the Utility, and other electricity purchasers are seeking refunds from electricity suppliers, including municipal and governmental entities, for overcharges incurred in the CAISO and the PX wholesale electricity markets between May 2000 and June 2001. Hearings at the FERC are scheduled to commence on March 7, 2012 to address the Utility’s and other electricity purchasers’ refund claims for the May through September 2000 period.

While the FERC and judicial proceedings have been pending, the Utility entered into a number of settlements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. These settlement agreements provide that the amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. The proceeds from these settlements, after deductions for contingencies based on the outcome of the various refund offset and interest issues being considered by the FERC, will continue to be refunded to customers in rates. Additional settlement discussions with other electricity suppliers are ongoing. Any net refunds, claim offsets, or other credits that the Utility receives from energy suppliers through resolution of the remaining disputed claims, either through settlement or the conclusion of the various FERC and judicial proceedings, will also be refunded to customers.

At September 30, 2011 and December 31, 2010, the Utility held $320 million and $512 million in escrow, respectively, including interest earned, for payment of the remaining net disputed claims. These amounts are included within restricted cash on the Condensed Consolidated Balance Sheets.

The following table presents the changes in the remaining net disputed claims liability:

(in millions)
Balance at December 31, 2010	$ 934
Interest accrued	20
Less: supplier settlements	(114)
Balance at September 30, 2011	$ 840

At September 30, 2011, the Utility’s net disputed claims liability was $840 million, consisting of $673 million of remaining disputed claims (classified on the Condensed Consolidated Balance Sheets within accounts payable – disputed claims and customer refunds) and interest accrued at the FERC-ordered rate of $661 million (classified on the Condensed

29        

Consolidated Balance Sheets within interest payable) partially offset by accounts receivable from the CAISO and the PX of $494 million (classified on the Condensed Consolidated Balance Sheets within accounts receivable – other).

Interest accrues on the net liability for disputed claims at the FERC-ordered rate, which is higher than the rate earned by the Utility on the escrow balance. Although the Utility has been collecting the difference between the accrued interest and the earned interest from customers, this amount is not held in escrow. If the amount of interest accrued at the FERC-ordered rate is greater than the amount of interest ultimately determined to be owed with respect to disputed claims, the Utility would refund to customers any excess net interest collected from customers. The amount of any interest that the Utility may be required to pay will depend on the final amounts to be paid by the Utility with respect to the disputed claims and when such interest is paid.

NOTE 10: COMMITMENTS AND CONTINGENCIES

PG&E Corporation and the Utility have substantial financial commitments in connection with agreements entered into to support the Utility’s operating activities. PG&E Corporation and the Utility also have significant contingencies arising from their operations, including contingencies related to guarantees, regulatory proceedings, nuclear operations, legal matters, environmental remediation, and tax matters.

Commitments

Third-Party Power Purchase Agreements

As part of the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either gas or electricity at the date of purchase. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s development of new generation facilities to provide the power to be purchased by the Utility under these agreements.

At September 30, 2011, the undiscounted future expected payment obligations were as follows:

(in millions)
2011	$ 539
2012	2,316
2013	2,969
2014	3,333
2015	3,562
Thereafter	55,242
Total	$ 67,961

Costs incurred by the Utility under power purchase agreements amounted to $1,845 million and $1,791 million for the nine months ended September 30, 2011 and 2010, respectively.

Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities. The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins. In addition, the Utility has contracted for gas storage services in northern California in order to better meet core customers’ winter peak loads. At September 30, 2011, the Utility’s undiscounted future expected payment obligations for natural gas purchases, natural gas transportation services, and natural gas storage were as follows:

30        

(in millions)
2011	$ 284
2012	630
2013	245
2014	201
2015	189
Thereafter	1,121
Total	$ 2,670

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage amounted to $1,351 million and $1,183 million for the nine months ended September 30, 2011 and 2010, respectively.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements have terms ranging from one to 14 years and are intended to ensure long-term fuel supply. The contracts for uranium and for conversion and enrichment services provide for 100% coverage of reactor requirements through 2016, while contracts for fuel fabrication services provide for 100% coverage of reactor requirements through 2017. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.

At September 30, 2011, the undiscounted future expected payment obligations under nuclear fuel agreements were as follows:

(in millions)
2011	$ 36
2012	88
2013	89
2014	130
2015	189
Thereafter	1,050
Total	$ 1,582

Payments for nuclear fuel amounted to $55 million and $140 million for the nine months ended September 30, 2011 and 2010, respectively.

Contingencies

PG&E Corporation

In 2000, PG&E Corporation issued a guarantee to the purchaser of a subsidiary of National Energy and Gas Transmission, Inc. (“NEGT”), formerly owned by PG&E Corporation. PG&E Corporation’s primary remaining exposure relates to any potential environmental obligations that were known to NEGT at the time of the sale but not disclosed to the purchaser, and is limited to $150 million. PG&E Corporation has not received any claims nor does it consider it probable that any claims will be made under the guarantee. PG&E Corporation believes that its potential exposure under this guarantee would not have a material impact on its financial condition or results of operations.

Utility

Spent Nuclear Fuel Storage Proceedings

As part of the Nuclear Waste Policy Act of 1982, Congress authorized the U.S. Department of Energy (“DOE”) and electric utilities with commercial nuclear power plants to enter into contracts under which the DOE would be required to dispose of the utilities’ spent nuclear fuel and high-level radioactive waste no later than January 31, 1998, in exchange for fees paid by the utilities. In 1983, the DOE entered into a contract with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and its retired nuclear facility at Humboldt Bay (“Humboldt Bay Unit 3”).

Because the DOE failed to develop a permanent storage site, the Utility constructed a dry cask storage facility to store spent fuel at Diablo Canyon through at least 2024. The Utility and other nuclear power plant owners sued the DOE to

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recover costs that they incurred to build on-site spent nuclear fuel storage facilities. The Utility sought to recover $92 million of costs that it incurred through 2004. After several years of litigation, on March 30, 2010, the U.S. Court of Federal Claims awarded the Utility $89 million. The DOE filed an appeal of this decision on May 28, 2010. The appeal was argued in the Federal Circuit Court of Appeals on March 10, 2011. The Utility is currently awaiting a decision on the appeal and has not recorded any receivable for the award.

Additionally, on August 3, 2010, the Utility filed two complaints against the DOE in the U.S. Court of Federal Claims seeking to recover all costs incurred since 2005 to build on-site storage facilities. The Utility estimates that it has incurred at least $205 million of such costs since 2005. Any amounts recovered from the DOE will be credited to customers.

Nuclear Insurance

The Utility has several types of nuclear insurance for the two nuclear generating units at Diablo Canyon and Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited (“NEIL”). NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.2 billion per incident ($2.7 billion for property damage and $490 million for business interruption) for Diablo Canyon. In addition, NEIL provides $131 million of property damage insurance for Humboldt Bay Unit 3. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss, the Utility may be required to pay an additional premium of up to $40 million per one-year policy term. NRC regulations require that the Utility’s property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after an accident and, second, to decontaminate the plant before any proceeds can be used for decommissioning or plant repair.

NEIL policies also provide coverage for damages caused by acts of terrorism at nuclear power plants. Certain acts of terrorism may be “certified” by the Secretary of the Treasury. If damages are caused by certified acts of terrorism, NEIL can obtain compensation from the federal government and will provide up to its full policy limit of $3.2 billion for each insured loss. In contrast, NEIL would treat all non-certified terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL as one event and the owners of the affected plants would share the $3.2 billion policy limit amount.

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to $12.6 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon. The balance of the $12.6 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. The Utility may be assessed up to $235 million per nuclear incident under this program, with payments in each year limited to a maximum of $35 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due on or before October 29, 2013.

The Price-Anderson Act does not apply to public liability claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. Such claims are covered by nuclear liability policies purchased by the enricher and the fuel fabricator as well as by separate supplier’s and transporter’s (“S&T”) insurance policies. The Utility has a S&T policy that provides coverage for claims arising from some of these incidents up to a maximum of $375 million per incident.

In addition, the Utility has $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents, covering liabilities in excess of the $53 million of liability insurance.

If the Utility incurs losses in connection with any of its nuclear generation facilities that are either not covered by insurance or exceed the amount of insurance available, these losses could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

Legal and Regulatory Contingencies

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and litigation, regulatory proceedings, and other legal matters. In addition, PG&E Corporation and the Utility can incur penalties for failure to comply with federal, state, or local laws and regulations.

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PG&E Corporation and the Utility record a provision for a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated costs and record a liability based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. These accruals, and the estimates of any additional reasonably possible losses, are analyzed quarterly and are adjusted to reflect the impacts of negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. In estimating such contingencies, PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs.

The accrued liability associated with claims and litigation, regulatory proceedings, and other legal matters (other than third-party claims related to the San Bruno accident and penalties related to the Rancho Cordova accident as discussed below) totaled $74 million at September 30, 2011 and $55 million at December 31, 2010 and is included in PG&E Corporation’s and the Utility’s current liabilities – other in the Condensed Consolidated Balance Sheets. Except as discussed below, PG&E Corporation and the Utility do not believe that losses associated with legal matters would have a material impact on their financial condition, results of operations, or cash flows after consideration of the accrued liability at September 30, 2011.

The San Bruno Accident

On September 9, 2010, an underground 30-inch natural gas transmission pipeline (Line 132) owned and operated by the Utility, ruptured in a residential area located in the City of San Bruno, California (“San Bruno accident”). The ensuing explosion and fire resulted in the deaths of eight people, numerous personal injuries, and extensive property damage. On August 30, 2011, the National Transportation Safety Board (“NTSB”) announced that it had determined that the probable cause of the San Bruno accident was the Utility’s inadequate quality assurance and quality control in 1956 during its Line 132 relocation project and an inadequate pipeline integrity management program. The NTSB publicly issued its final accident investigation report on September 26, 2011.

The CPUC has also been investigating the San Bruno accident and other natural gas transmission matters, including an investigation pertaining to safety recordkeeping for the Utility’s gas transmission system as described below. These investigations could lead to significant fines and other sanctions being imposed on the Utility. The Utility has been responding to various requests for information from the CPUC staff about the Utility’s natural gas operations and from an independent auditing firm engaged by the CPUC’s Consumer Protection and Safety Division (“CPSD”) to conduct an audit of the Utility’s spending on its natural gas transmission pipelines from 1996 to 2010. Also as described below, a criminal investigation is being conducted in connection with the San Bruno accident.

In addition to these investigations, approximately 100 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, have been filed against PG&E Corporation and the Utility on behalf of approximately 370 plantiffs. These cases have been coordinated and assigned to one judge in the San Mateo County Superior Court. The lawsuits seek compensation for these third-party claims and other relief, including punitive damages. On October 6, 2011, the judge overseeing the consolidated San Bruno civil litigation set a trial date for July 23, 2012 for the first of these lawsuits. In 2010, the Utility recorded $220 million for estimated third-party claims related to the San Bruno accident. For the three and nine months ended September 30, 2011, the Utility recorded additional amounts of $96 million and $155 million, respectively, for a cumulative provision of $375 million. The Utility estimates it is reasonably possible that it may incur as much as an additional $225 million for third-party claims, for a total loss of $600 million, increased from the $400 million total loss previously estimated. The Utility’s change in estimate resulted primarily from new information regarding the nature of claims filed against the Utility, experience to date in resolving cases, and developments in the litigation and regulatory proceedings related to the San Bruno accident. As more information becomes known, estimates and assumptions regarding the amount of liability incurred in connection with the San Bruno accident may be subject to further changes. Future changes in estimates may have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. PG&E Corporation and the Utility are unable to estimate a possible loss or range of loss associated with any fines, penalties, or punitive damages related to the matters discussed above, and such amounts could be material.

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As of September 30, 2011 and December 31, 2010, $289 million and $214 million, respectively, was accrued for third-party claims in other current liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. The following table presents the change in the accrual for third-party claims from September 30, 2010 to September 30, 2011:

(in millions)
Balance at September 30, 2010	$ 220
Less: Payments	(6)
Balance at December 31, 2010	214
Additional costs accrued	155
Less: Payments	(80)
Balance at September 30, 2011	$ 289

The Utility has liability insurance from various insurers who provide coverage at different policy limits that are triggered in sequential order or “layers.” Generally, as the policy limit for a layer is exhausted the next layer of insurance becomes available. The aggregate amount of this insurance coverage is approximately $992 million in excess of a $10 million deductible. The Utility submitted insurance claims to certain insurers for the lower layers and recognized $60 million for insurance recoveries in the second quarter of 2011, which were collected during the third quarter. As of September 30, 2011 and December 31, 2010, no insurance recovery receivables were recorded in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. Although the Utility currently considers it likely that a significant portion of costs incurred for third-party claims relating to the San Bruno accident will ultimately be recovered through its insurance, it is unable to predict the amount and timing of additional insurance recoveries.

CPUC Investigation Regarding Utility’s Facilities Records for its Natural Gas Pipelines

On February 24, 2011, the CPUC issued an order instituting a formal investigation pertaining to safety recordkeeping for Line 132 that ruptured in the San Bruno accident, as well as for the Utility’s entire gas transmission system. If the CPUC determines that the Utility violated gas safety recordkeeping requirements, the CPUC will schedule a later phase or phases to determine whether penalties are warranted, and if so the amount of such penalties. The CPUC could impose penalties of up to $20,000 per day, per violation or up to $50,000 per day, per violation for violations occurring on or after January 1, 2012, when the maximum statutory penalty increases.

PG&E Corporation and the Utility are unable to estimate a possible loss or range of loss associated with any penalties that may be imposed by the CPUC on the Utility.

Criminal Investigation Regarding San Bruno Accident

On June 9, 2011, the Utility was notified that representatives from the U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo County District Attorney’s Office, are conducting an investigation of the San Bruno accident. The Utility is cooperating with the investigation. The investigation is in the early stages and PG&E Corporation and the Utility are unable to estimate a possible loss or range of loss associated with any criminal fines or penalties that may be imposed on the Utility.

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CPUC Investigation Regarding Rancho Cordova Accident

The CPUC has also been investigating a natural gas explosion and fire that occurred on December 24, 2008 in a house located in Rancho Cordova, California (“Rancho Cordova accident”). On September 29, 2011, an administrative law judge (“ALJ”) denied a request to approve stipulations previously submitted by the Utility, the CPSD, and The Utility Reform Network (“TURN”), to resolve the CPUC’s investigation of the Rancho Cordova accident including the proposed payment of a $26 million penalty by the Utility. Instead, the ALJ recommended that the Utility pay a penalty of $38 million based on the ALJ’s determination that (1) CPUC case law warrants a higher penalty when a fatality has occurred and (2) the Utility could be fined as much as $97 million if the case were fully litigated and all allegations were proven.

On October 19, 2011, the Utility, the CPSD, and TURN filed a joint motion to accept the increased penalty amount. The Utility has agreed to pay the CPUC for the costs it incurred in connection with the investigation and that it would not seek to recover the penalty or costs through rates. On October 31, 2011, the ALJ issued a proposed decision extending the statutory 12-month deadline to conclude the investigation. The proposed decision, to be voted on by the CPUC on November 10, 2011, will give the CPUC time to consider and rule on the joint motion accepting the increased penalty.

As of September 30, 2011, approximately $39 million was accrued for penalties and other costs associated with the Rancho Cordova accident in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.

Environmental Remediation Contingencies

The Utility has been, and may be required to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party under federal and state environmental laws. These sites include former manufactured gas plant (“MGP”) sites, power plant sites, gas gathering sites, sites where natural gas compressor stations are located, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous substances. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site.

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. The Utility records an environmental remediation liability when site assessments indicate that remediation is probable and it can reasonably estimate the loss within a range of possible amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated costs, unless an amount within the range is a better estimate than any other amount. Amounts recorded are not discounted to their present value.

The following table presents the changes in the environmental remediation liability from December 31, 2010:

(in millions)
Balance at December 31, 2010	$ 612
Additional remediation costs accrued:
Transfer to regulatory account for recovery	107
Amounts not recoverable from customers	142
Less: Payments	(98)
Balance at September 30, 2011	$ 763

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The $763 million accrued at September 30, 2011 consisted of the following:

• $150 million for remediation at the Utility’s natural gas compressor site located near Hinkley, California (“Hinkley natural gas compressor site”), as described below;

• $178 million for remediation at the Utility’s natural gas compressor site located on the California border, near Topock, Arizona;

• $81 million related to remediation at divested generation facilities;

• $140 million related to remediation costs for the Utility’s generation and other facilities and for third-party disposal sites;

• $157 million related to investigation and/or remediation costs at former MGP sites owned by the Utility or third parties (including those sites that are the subject of remediation orders by environmental agencies or claims by the current owners of the former MGP sites); and

• $57 million related to remediation costs for fossil fuel decommissioning sites.

Hinkley Natural Gas Compressor Site

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor site located near Hinkley, California. The Utility is also required to take measures to abate the effects of the contamination on the environment. The Utility’s remediation and abatement efforts are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region (“Water Board”). The Utility has been working with the Water Board for several years to implement interim remedial measures to both reduce the mass of the underground plume of hexavalent chromium and to monitor and control movement of the plume.

In August 2010, the Utility filed a comprehensive feasibility study with the Water Board that included an evaluation of possible alternatives for a final groundwater remediation plan. The Utility filed several addendums to its feasibility study based on additional analyses of remediation alternatives and correspondence with the Water Board. The Utility’s recommended alternative for a final remediation plan was submitted to the Water Board in September 2011 and involves a combination of using pumped groundwater from extraction wells to irrigate agricultural land and in-situ remediation. The Water Board stated that it anticipates it will consider certification of the final environmental impact report (“EIR”), which will include the final approved remediation plan, in July 2012. The Water Board has indicated that it anticipates releasing a preliminary draft of the EIR for discussion in late 2011.

Additionally, on October 11, 2011, the Water Board issued an amended cleanup and abatement order (“CAO”) to require the Utility to provide an interim and permanent replacement water system for certain properties located near the underground plume of hexavalent chromium. The CAO requires the Utility to propose a method to perform an initial and quarterly evaluation of wells in the affected area to determine if detectable levels of hexavalent chromium that are lower than the background level but higher than the new public health goal, represent background conditions, or are more likely than not, partially or completely caused by the Utility’s discharge of waste. On October 25, 2011, the Utility filed a petition with the California Water Resources Control Board (“Control Board”) and requested that the Control Board determine that the Utility is not required to comply with these provisions of the CAO, in part, because the Utility believes that it is not feasible to implement the ordered actions and that the ordered actions are not supported by California law.

For the three and nine months ended September 30, 2011, the Utility increased its provision for environmental remediation liabilities associated with the Hinkley site by $106 million and $132 million, respectively. The increase resulted primarily from changes in costs estimates and assumptions associated with the above developments. As of September 30, 2011 and December 31, 2010, $150 million and $45 million, respectively, were accrued in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets for estimated undiscounted future costs. Actual costs will depend on many factors, including the certification of a final remediation plan, the extent of the groundwater chromium plume, the levels of hexavalent chromium used as the standard for remediation, and the scope of requirements to provide a permanent water replacement system to affected residents. The Utility is unable to recover remediation costs for the Hinkley site through customer rates. As a result, future increases to the Utility’s provision for its remediation liability will impact PG&E Corporation’s and the Utility’s financial results.

Reasonably Possible Environmental Contingencies

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized. The Utility’s undiscounted future costs could increase to as much as $1.4 billion (including amounts related to the Hinkley natural gas compressor site) if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements.

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Recoveries of Environmental Remediation Costs

The CPUC has authorized the Utility to recover 90% of its hazardous substance remediation costs from customers without a reasonableness review (excluding any remediation costs associated with the Hinkley natural gas compressor site). Of the total $763 million environmental remediation liability at September 30, 2011, the Utility expects to recover $364 million through this ratemaking mechanism. The CPUC has also authorized the Utility to recover 100% of its remediation costs for decommissioning fossil-fueled sites and certain of the Utility’s transmission stations (excluding any remediation associated with divested generation facilities). The Utility expects to recover $128 million through this ratemaking mechanism. The Utility also recovers these costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility’s ultimate obligations may be subject to refund to customers.

Tax Matters

In 2008, PG&E Corporation began participating in the Compliance Assurance Process (“CAP”), a real-time Internal Revenue Service (“IRS”) audit intended to expedite resolution of tax matters. The CAP audit culminates with a letter from the IRS indicating its acceptance of the return. The IRS partially accepted the 2008 return, withholding two matters for further review. The most significant of these relates to a tax accounting method change filed by PG&E Corporation to accelerate the amount of deductible repairs. In August 2011, the IRS issued new guidance regarding the repairs deduction for electric transmission and distribution assets and is expected to clarify this guidance for tax years prior to 2011. PG&E Corporation expects to reflect this guidance in a cumulative adjustment for the repairs deduction for each of the applicable years. This adjustment may result in a change in unrecognized tax benefits. PG&E Corporation and the Utility are unable to determine the potential impact of this change to the unrecognized tax benefits at this time.

The IRS also is continuing to work with the utility industry to provide consistent repairs deduction guidance for gas transmission, gas distribution, and electric generation businesses. PG&E Corporation and the Utility expect the IRS to release this guidance within the next 12 months. This guidance may result in a change in unrecognized tax benefits. PG&E Corporation and the Utility are unable to determine the potential impact of this change to the unrecognized tax benefits at this time.

In September 2011 the IRS partially accepted the 2010 return, withholding two matters for further review. The most significant of these matters relates to the accelerated tax deductions for repairs discussed above. The IRS has not completed the CAP audit for 2011.

The California Franchise Tax Board (“FTB”) is auditing PG&E Corporation’s 2004 and 2005 combined California income tax returns, as well as the 1997-2007 amended income tax returns reflecting IRS settlements and state tax claims for these years. PG&E Corporation expects the FTB to complete the audits for 1997 through 2004 by the end of 2011. It is uncertain when the FTB will complete the remaining audits.

PG&E Corporation believes that the final resolution of the federal and California audits will not have a material impact on its financial condition or results of operations.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

OVERVIEW

PG&E Corporation, incorporated in California in 1995, is a holding company whose primary purpose is to hold interests in energy-based businesses. PG&E Corporation conducts its business principally through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997. Both PG&E Corporation and the Utility are headquartered in San Francisco, California. The Utility served 5 million electricity distribution customers and 4 million natural gas distribution customers at September 30, 2011.

The Utility is regulated primarily by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). The CPUC determines the rates and terms and conditions of service for the Utility’s electric and natural gas distribution operations, electric generation, and natural gas transportation and storage. The FERC determines the rates and terms and conditions of service for the Utility’s electric transmission operations and its interstate natural gas transportation contracts. Before setting rates, the CPUC and the FERC authorize the annual amount of revenue (“revenue requirements”) that the Utility is authorized to collect from its customers to recover its reasonable operating and capital costs of providing utility services. The authorized revenue requirements also provide the Utility an opportunity to earn a return on “rate base” (i.e., the Utility’s net investment in facilities, equipment, and other property used or useful in providing utility service to its customers). The CPUC requires the Utility to maintain a certain capital structure (i.e., the relative weightings of common equity, preferred equity, and debt) when financing its rate base and authorizes a specific rate of return on each capital component. Additionally, the Nuclear Regulatory Commission (“NRC”) oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities, including the Diablo Canyon power plant (“Diablo Canyon”).

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s separate Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in this quarterly report. In addition, this quarterly report should be read in conjunction with PG&E Corporation’s and the Utility’s combined Annual Report on Form 10-K for the year ended December 31, 2010 which incorporates by reference each company’s audited Consolidated Financial Statements, the Notes to the Consolidated Financial Statements, and other information (“2010 Annual Report”).

Key Factors Affecting Results of Operations and Financial Condition

PG&E Corporation’s and the Utility’s results of operations and financial condition depend primarily on whether the Utility is able to operate its business within authorized revenue requirements, recover its authorized costs timely, and earn its authorized rate of return. A number of factors have had, or are expected to have, a significant impact on PG&E Corporation’s and the Utility’s results of operations and financial condition, including the outcome of natural gas pipeline matters, environmental remediation costs, and other factors discussed below.

On August 30, 2011, the National Transportation Safety Board (“NTSB”) announced that it had determined the probable cause of the natural gas transmission pipeline rupture and fire that occurred on September 9, 2010 in San Bruno, California (the “San Bruno accident”) placing the blame primarily on the Utility. (See “Natural Gas Pipeline Matters” below for a discussion of the NTSB report, and various pending investigations and proceedings related to the San Bruno accident and the Utility’s natural gas pipeline operations.)

• The Outcome of Matters Related to the Utility’s Natural Gas Pipeline System. The Utility has incurred natural gas pipeline-related costs of $177 million and $303 million for the three and nine months ended September 30, 2011 that will not be recovered through rates. The Utility projects that it will incur as much as $550 million in 2011 and between $100 million and $200 million in 2012 for pipeline-related matters that will not be recovered through rates. It is uncertain how much of the costs the Utility incurs in 2012 and future years under its proposed natural gas transmission pipeline safety enhancement plan will be recoverable through rates. (See “Natural Gas Pipeline Matters - CPUC Rulemaking Proceeding” below.) Additionally, the Utility has recorded a cumulative provision of $375 million as of September 30, 2011 and estimates it is reasonably possible that it may incur up to $600 million for third-party liability claims related to the San Bruno accident. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.) Finally, the CPUC may impose penalties on the Utility in connection with the San Bruno accident and natural gas pipeline matters. An investigation of the San Bruno accident by the U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo District Attorney’s Office could result in the imposition of criminal fines or penalties on the Utility. PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows will be affected by the scope and timing of the final CPUC-approved plan, the ultimate pipeline-related costs

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that the Utility is able to recover from customers, the ultimate amount of costs incurred for third-party claims that are not recoverable through insurance, and the amount of civil or criminal fines, penalties, or punitive damages the Utility may be required to pay.

• The Timing and Outcome of Ratemaking and Other Regulatory Proceedings. In decisions issued earlier this year, the CPUC approved settlement agreements that determine the majority of the Utility’s base revenue requirements for the next several years. The decision in the Utility’s 2011 General Rate Case (“GRC”) sets revenue requirements for electric and natural gas distribution and electric generation operations from 2011 through 2013. The decision in the Utility’s 2011 Gas Transmission and Storage rate case (“GT&S”) sets revenue requirements for natural gas transmission and storage operations from 2011 through 2014. On August 10, 2011, the FERC approved an uncontested settlement of the Utility’s 13^th Electric Transmission Owner (“TO”) rate case. (See “Results of Operations” and “Regulatory Matters” below.) From time to time, the Utility also requests that the CPUC authorize additional base revenue requirements for specific capital expenditure projects, such as new power plants. The Utility also collects revenue requirements to recover certain costs that the CPUC has authorized the Utility to pass through to customers, such as electric procurement costs. The Utility’s recovery of these costs is often subject to compliance and audit proceedings conducted by the CPUC which may result in the disallowance of costs previously recorded for recovery. The outcome of these proceedings can be affected by many factors, including general economic conditions, the level of customer rates, regulatory policies, and political considerations. (See “Risk Factors” in the 2010 Annual Report and Item 1.A. below.)

• The Ability of the Utility to Control Operating Costs and Capital Expenditures. The Utility’s revenue requirements are generally set by the CPUC and the FERC at a level to allow the Utility to recover its forecasted operating expenses, to recover depreciation, tax, and interest expenses associated with forecasted capital expenditures, and to earn a return on equity (“ROE”). Actual costs may differ from the Utility’s forecasts, or the Utility may incur significant unanticipated costs, such as costs related to storms, outages, catastrophic events, or to comply with regulatory orders or legislation. In addition, there may be some costs that the CPUC has determined will not be recoverable through rates, such as environmental-related costs associated with the Utility’s natural gas compressor station located in Hinkley, California. Further, the Utility also forecasts that it will incur expenses in 2012 (and a comparable amount in 2013) that are approximately $200 million higher than amounts assumed under the 2011 GRC and GT&S settlements as the Utility works to improve the safety and reliability of its operations. Other differences in the amount or timing of forecasted or authorized and actual costs also may affect the Utility’s ability to earn its authorized rate of return and the amount of PG&E Corporation’s income available for common shareholders.

• Authorized Rate of Return, Capital Structure, and Financing. The Utility’s CPUC-authorized ROE of 11.35% is scheduled to remain in effect through 2012, but is subject to change based on an annual adjustment mechanism. The Utility’s CPUC-authorized capital structure for its electric and natural gas distribution and electric generation rate base consists of 52% common equity and 48% debt and preferred stock and is scheduled to remain in effect through 2012. The Utility’s next cost of capital application, required to be filed with the CPUC in April 2012, will determine the Utility’s proposed capital structure to be effective beginning January 1, 2013. PG&E Corporation contributes equity to the Utility as needed by the Utility to maintain its CPUC-authorized capital structure. The Utility’s equity needs will be affected by various factors, including the timing and amount of its capital expenditures, changes to its authorized capital structure and rates of return, the amount of natural gas pipeline-related costs that are not probable of recovery through rates, and the amount of any fines or penalties the Utility may be required to pay, and collateral requirements. PG&E Corporation’s and the Utility’s ability to access the capital markets may, among other factors, be affected by the outcome of the various matters involving the Utility’s natural gas pipeline system. (See “Liquidity and Financial Resources” below.)

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Summary of Changes in Earnings per Common Share and Income Available for Common Shareholders for the Three and Nine Months Ended September 30, 2011

PG&E Corporation’s income available for common shareholders for the three months ended September 30, 2011 decreased by $58 million, or 22%, to $200 million, compared to $258 million for the same period in 2010. For the nine months ended September 30, 2011, income available for common shareholders decreased by $88 million, or 10%, to $761 million, compared to $849 million for the same period in 2010. The following table is a summary reconciliation of the key changes, after-tax, in income available for common shareholders and earnings per common share for the three and nine months ended September 30, 2011. See “Results of Operations” below for further information.

	Three Months  Ended September 30,				Nine Months  Ended September 30,
	Earnings		Earnings Per   Common Share (Diluted)		Earnings		Earnings Per   Common Share (Diluted)
(in millions)
Income Available for Common Shareholders – September 30, 2010		$ 258		$ 0.66		$ 849		$ 2.19
Natural gas pipeline matters		(21)		(0.04)		(96)		(0.24)
Environmental-related costs		(74)		(0.18)		(74)		(0.19)
Litigation and regulatory matters		(18)		(0.04)		(46)		(0.11)
Nuclear refueling outage		-		-		(26)		(0.06)
Storm and outage expenses		-		-		(23)		(0.06)
Gas transmission revenues		-		-		(18)		(0.05)
Increase in rate base earnings		41		0.10		123		0.31
Statewide ballot initiative		-		-		45		0.12
Federal healthcare law		-		-		19		0.05
Other		14		0.03		8		0.03
Increase in shares outstanding (1)		-		(0.03)		-		(0.09)
Income Available for Common Shareholders – September 30, 2011		$ 200		$ 0.50		$ 761		$ 1.90

⁽¹⁾  Represents the impact of a higher number of shares outstanding at September 30, 2011, compared to the number of shares outstanding at September 30, 2010. PG&E Corporation issues shares to fund its equity contributions to the Utility that are used by the Utility to maintain its capital structure and fund operations, including expenses related to natural gas pipeline matters. This has no dollar impact on earnings.

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions which are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures; estimated environmental remediation, tax, and other liabilities; estimates and assumptions used in PG&E Corporation’s and the Utility’s critical accounting policies; the anticipated outcome of various regulatory, governmental, and legal proceedings; estimated losses and insurance recoveries associated with the San Bruno accident; the estimated range of additional costs the Utility will incur related to its natural gas transmission business; estimated future cash flows; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “target,” “predict,” “anticipate,” “aim,” “may,” “might,” “should,” “would,” “could,” “goal,” “potential,” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

• the outcome of pending and future investigations and regulatory proceedings related to the San Bruno accident, the CPUC’s investigation of a natural gas explosion that occurred on December 24, 2008 in Rancho Cordova, California (the “Rancho Cordova accident”), and the safety of the Utility’s natural gas transmission pipelines in its northern and central California service territory; the ultimate amount of costs the Utility incurs for natural gas pipeline matters that are not recoverable through rates; the ultimate amount of third-party claims associated with the San Bruno accident that will not be recovered through insurance; and the amount of any civil or criminal fines, penalties, or punitive damages the Utility may incur related to these matters;

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• the outcome of future investigations or proceedings that may be commenced by the CPUC or other regulatory authorities relating to the Utility’s compliance with law, rules, regulations, or orders applicable to the operation, inspection, and maintenance of its electric and gas facilities (in addition to investigations or proceedings related to the San Bruno accident and natural gas pipeline matters);

• reputational harm that PG&E Corporation and the Utility may suffer depending on whether the Utility is able to adequately and timely respond to the findings and recommendations made by the NTSB and CPUC’s independent review panel; the outcome of the various regulatory proceedings and investigations of the San Bruno accident and natural gas pipeline matters; service disruptions caused by pressure reductions in the Utility’s natural gas pipeline system, the outcome of civil litigation; and the extent to which additional regulatory, civil, or criminal proceedings may be pursued by regulatory or governmental agencies;

• the adequacy and price of electricity and natural gas supplies, the extent to which the Utility can manage and respond to the volatility of electricity and natural gas prices, and the ability of the Utility and its counterparties to post or return collateral;

• explosions, fires, accidents, mechanical breakdowns, the disruption of information technology and systems (including the newly installed advanced electric and gas metering system), human errors, and similar events that may occur while operating and maintaining an electric and natural gas system in a large service territory with varying geographic conditions that can cause unplanned outages, reduce generating output, damage the Utility’s assets or operations, which could subject the Utility to third-party claims for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utility;

• the impact of storms, earthquakes, floods, drought, wildfires, disease, and similar natural disasters, or acts of terrorism or vandalism, that affect customer demand or that damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies;

• the potential impacts of climate change on the Utility’s electricity and natural gas businesses, the impact of environmental laws and regulations aimed at the reduction of carbon dioxide and other greenhouse gases (“GHG”) on the Utility’s electricity and natural gas businesses, and whether the Utility is able to recover associated compliance costs including the cost of emission allowances and offsets that the Utility may incur under cap and trade regulations;

• changes in customer demand for electricity (“load”) and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, the development of alternative energy technologies including self-generation and distributed generation technologies, or other reasons;

• the occurrence of unplanned outages at the Utility’s two nuclear generating units at Diablo Canyon, the availability of nuclear fuel, and the ability of the Utility to procure replacement electricity if nuclear generation from Diablo Canyon were unavailable;

• the outcome of seismic studies the Utility is conducting that could affect the Utility’s ability to continue operating Diablo Canyon or renew the operating licenses for Diablo Canyon, the issuance of NRC orders or the adoption of new legislation or regulations to address seismic and other risks at nuclear facilities to avoid the type of damage sustained by nuclear facilities in Japan following the March 2011 earthquake, or to address the operations, decommissioning, storage of spent nuclear fuel, security, safety, cooling water intake, or other operating or licensing matters associated with Diablo Canyon and whether the Utility is able to comply with such new orders, legislation, or regulations and recover the increased costs of compliance through rates;

• the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies, including how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company;

• whether the Utility’s newly installed electric and gas SmartMeter^TM devices and related software systems and wireless communications equipment continue to accurately and timely measure customer energy usage and generate billing information, whether the Utility can successfully implement the system design changes necessary to accommodate changing retail electric rates, and whether the Utility can continue to rely on third-party vendors and contractors to support the advanced metering system;

• the extent to which PG&E Corporation or the Utility incurs costs in connection with third-party claims or litigation, that are not recoverable through insurance, rates, or from other third parties;

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• the ability of PG&E Corporation, the Utility, and counterparties to access capital markets and other sources of credit in a timely manner on acceptable terms;

• the impact of environmental remediation laws and regulations, particularly those affecting the remediation of the Utility’s former manufactured gas plants and natural gas compressor sites, the extent to which the Utility is able to recover compliance and remediation costs from third parties or through rates or insurance, and the ultimate amount of environmental remediation costs the Utility incurs related to the Hinkley compressor station;

• the loss of customers due to various forms of bypass and competition, including municipalization of the Utility’s electric distribution facilities, increasing levels of “direct access” by which consumers procure electricity from alternative energy providers, and implementation of “community choice aggregation,” which permits cities and counties to purchase and sell electricity for their local residents and businesses; and

• the outcome of federal or state tax audits and the impact of changes in federal or state tax laws, policies, or regulations, such as The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (the “Tax Relief Act”).

For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition and results of operations, see the section entitled “Risk Factors” in the 2010 Annual Report and Item 1.A. Risk Factors, below. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

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RESULTS OF OPERATIONS

The table below details certain items from the accompanying Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2011 and 2010:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2011		2010		2011		2010
Utility
Electric operating revenues		$ 3,187		$ 2,857		$ 8,691		$ 7,882
Natural gas operating revenues		672		656		2,447		2,338
Total operating revenues		3,859		3,513		11,138		10,220
Cost of electricity		1,224		1,102		3,018		2,885
Cost of natural gas		170		182		936		924
Operating and maintenance		1,497		1,224		3,951		3,172
Depreciation, amortization, and decommissioning		566		500		1,648		1,419
Total operating expenses		3,457		3,008		9,553		8,400
Operating Income		402		505		1,585		1,820
Interest income		2		3		6		7
Interest expense		(171)		(161)		(511)		(481)
Other income (expense), net		19		25		52		20
Income Before Income Taxes		252		372		1,132		1,366
Income tax provision		56		107		376		498
Net Income		196		265		756		868
Preferred stock dividend requirement		3		3		10		10
Income Available for Common Stock		$ 193		$ 262		$ 746		$ 858
PG&E Corporation, Eliminations, and Other (1)
Operating revenues		$ 1		$ -		$ 3		$ -
Operating expenses		(5)		2		4		4
Operating Income (Loss)		6		(2)		(1)		(4)
Interest income		-		-		1		-
Interest expense		(5)		(6)		(16)		(29)
Other income, net		(1)		4		4		5
Income (Loss) Before Income Taxes		-		(4)		(12)		(28)
Income tax benefit		(7)		-		(27)		(19)
Net Income (Loss)		$ 7		$ (4)		$ 15		$ (9)
Consolidated Total
Operating revenues		$ 3,860		$ 3,513		$ 11,141		$ 10,220
Operating expenses		3,452		3,010		9,557		8,404
Operating Income		408		503		1,584		1,816
Interest income		2		3		7		7
Interest expense		(176)		(167)		(527)		(510)
Other income (expense), net		18		29		56		25
Income Before Income Taxes		252		368		1,120		1,338
Income tax provision		49		107		349		479
Net Income		203		261		771		859
Preferred stock dividend requirement of subsidiary		3		3		10		10
Income Available for Common Shareholders		$ 200		$ 258		$ 761		$ 849

⁽¹⁾   PG&E Corporation eliminates all intercompany transactions in consolidation.

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Utility

The following presents the Utility’s operating results for the three and nine months ended September 30, 2011 and 2010.

Electric Operating Revenues

The Utility’s electric operating revenues consist of amounts charged to customers for electricity generation and for electric transmission and distribution services, as well as amounts charged to customers to recover the cost of electric procurement, public purpose, energy efficiency, and demand response programs. The Utility provides electricity to residential, industrial, agricultural, and small and large commercial customers through its own generation facilities and through power purchase agreements with third parties.

The following table provides a summary of the Utility’s total electric operating revenues:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2011		2010		2011		2010
Revenues excluding pass-through costs		$ 1,712		$ 1,545		$ 4,968		$ 4,464
Revenues for recovery of passed-through costs		1,475		1,312		3,723		3,418
Total electric operating revenues		$ 3,187		$ 2,857		$ 8,691		$ 7,882

The Utility’s total electric operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $330 million, or 12%, and by $809 million, or 10%, in the three and nine months ended September 30, 2011, as compared to the same periods in 2010. Costs that are passed through to customers and do not impact net income increased by $163 million and $305 million in the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010, primarily due to increases in the cost of electricity procurement (see “Cost of Electricity” below), cost of public purpose programs, and pension expense. Electric operating revenues, excluding costs passed through to customers, increased by $167 million and $504 million in the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010. The increase for both periods is primarily due to additional base revenues that were authorized by the CPUC in the 2011 GRC, the FERC in the 13^th TO rate case, and various separately funded projects. (See “Regulatory Matters” below.)

The Utility’s future electric operating revenues for 2012 and 2013 are expected to increase as authorized by the CPUC in the 2011 GRC. The Utility’s electric operating revenues for 2012 are also expected to increase as authorized by the FERC in the 13^th TO rate case. (See “Regulatory Matters” below.) Additionally, the Utility’s future electric operating revenues will be impacted by the cost of electricity and other costs that are passed through to customers.

Cost of Electricity

The Utility’s cost of electricity includes costs to purchase power from third parties, certain transmission costs, the cost of fuel used in its own generation facilities, the cost of fuel supplied to other facilities under tolling agreements and realized gains and losses on price risk management activities. The volume of power the Utility purchases is driven by customer demand, the availability of the Utility’s own electricity generation, and the cost effectiveness of each source of electricity. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.) The Utility’s cost of electricity is passed through to customers. The Utility’s cost of electricity excludes non-fuel costs associated with operating the Utility’s own generation facilities, which are included in operating and maintenance expense in the Condensed Consolidated Statements of Income.

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The following table provides a summary of the Utility’s cost of electricity and the total amount and average cost of purchased power:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2011		2010		2011		2010
Cost of purchased power		$ 1,141		$ 1,041		$ 2,819		$ 2,694
Fuel used in own generation facilities		83		61		199		191
Total cost of electricity		$ 1,224		$ 1,102		$ 3,018		$ 2,885
Average cost of purchased power per kWh (1)		$ 0.092		$ 0.082		$ 0.089		$ 0.083
Total purchased power (in millions of kWh)		12,446		12,742		31,582		32,568

              ⁽¹⁾  Kilowatt-hour

The Utility’s total cost of electricity increased by $122 million, or 11%, and by $133 million, or 5%, in the three and nine months ended September 30, 2011 as compared to the same periods in 2010, primarily due to an increase in the price of purchased power resulting from increased renewable energy deliveries and transmission costs.

Various factors will affect the Utility’s future cost of electricity, including the market prices for electricity and natural gas, the availability of Utility-owned generation, and changes in customer demand. Additionally, the cost of electricity is expected to be impacted by the higher cost of procuring renewable energy as the Utility increases the amount of its renewable energy deliveries to comply with current and future California law and regulatory requirements. The Utility’s future cost of electricity also will be affected by legislation and rules applicable to GHG emissions. (See “Environmental Matters” below.)

Natural Gas Operating Revenues

The Utility sells natural gas and natural gas transportation services. The Utility transports gas throughout its service territory. The Utility uses its distribution system to deliver gas to most end-use customers. In addition, the Utility delivers gas to large end-use customers who are connected directly to the transmission system. The Utility also delivers natural gas to off-system markets, primarily in southern California.

The following table provides a summary of the Utility’s natural gas operating revenues:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2011		2010		2011		2010
Revenues excluding pass-through costs		$ 424		$ 421		$ 1,275		$ 1,250
Revenues for recovery of passed-through costs		248		235		1,172		1,088
Total natural gas operating revenues		$ 672		$ 656		$ 2,447		$ 2,338

The Utility’s natural gas operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $16 million, or 2%, and by $109 million, or 5%, in the three and nine months ended September 30, 2011, as compared to the same periods in 2010. Costs that are passed through to customers and do not impact net income increased by $13 million and $84 million in the three and nine months ended September 30, 2011, respectively, as compared to the same periods in 2010, primarily due to an increase in the costs of public purpose programs and pension expense. Natural gas operating revenues, excluding costs passed through to customers, increased by $3 million and $25 million in the three and nine months ended September 30, 2011, respectively. The increase for both periods was primarily due to additional base revenues authorized by the CPUC in the 2011 GT&S and GRC, which were partially offset by a decrease in natural gas storage revenues.

The Utility’s operating revenues for natural gas transportation and storage services in 2012, 2013, and 2014 are expected to increase as authorized by the CPUC in the 2011 GT&S rate case. Additionally, the Utility’s revenues for natural gas distribution services in 2012 and 2013 are expected to increase as authorized by the CPUC in the 2011 GRC. The Utility’s gas operating revenues for future years also will be impacted by changes in the cost of natural gas, the Utility’s gas transportation rates, natural gas throughput volume, and other factors. (See “Regulatory Matters” below.)

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Cost of Natural Gas

The Utility’s cost of natural gas includes the procurement of natural gas, gas storage, and gas transportation. The cost of natural gas excludes the cost of transportation on the Utility’s owned pipeline, which is included in operating and maintenance expense in the Condensed Consolidated Statements of Income. The Utility’s cost of natural gas also includes realized gains and losses on price risk management activities. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)

The following table provides a summary of the Utility’s cost of natural gas:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2011		2010		2011		2010
Cost of natural gas sold		$ 128		$ 142		$ 802		$ 796
Transportation cost of natural gas sold		42		40		134		128
Total cost of natural gas		$ 170		$ 182		$ 936		$ 924
Average cost per Mcf of natural gas sold		$ 3.88		$ 4.18		$ 4.20		$ 4.54
Total natural gas sold (in millions of Mcf) (1)		33		34		191		186
(1)  One thousand cubic feet

The Utility’s total cost of natural gas decreased by $12 million, or 7%, in the three months ended September 30, 2011 as compared to the same period in 2010, primarily due to a decrease in procurement costs resulting from a decline in the average market price of natural gas during the period. The Utility’s total cost of natural gas increased by $12 million, or 1%, in the nine months ended September 30, 2011 as compared to the same period in 2010.

The Utility’s future cost of natural gas will be affected by the market price of natural gas and changes in customer demand. In addition, the Utility’s future cost of natural gas may be affected by federal or state legislation or rules to regulate the GHG emissions from the Utility’s natural gas transportation and distribution facilities and from natural gas consumed by the Utility’s customers.

Operating and Maintenance

Operating and maintenance expenses consist mainly of the Utility’s costs to operate and maintain its electricity and natural gas facilities, customer billing and service expenses, the cost of public purpose programs, and administrative and general expenses.

The Utility’s operating and maintenance expenses (including costs currently passed through to customers) increased by $273 million, or 22%, and by $779 million, or 25%, in the three and nine months ended September 30, 2011, as compared to the same periods in 2010. Costs that are passed through to customers and do not impact net income increased by $37 million and $172 million, respectively, primarily due to the cost of public purpose programs and pension plan contributions.

Excluding costs currently passed through to customers, operating and maintenance expenses increased by $236 million for the three months ended September 30, 2011, as compared to the same period in 2010. This increase was attributable to a number of factors, including $125 million for estimated environmental remediation and other liabilities associated with the Utility’s natural gas compressor site located near Hinkley, California (see “Environmental Matters” below); $22 million for legal and regulatory matters, including penalties associated with the Rancho Cordova accident (see “Rancho Cordova Accident” below); $21 million for employee benefit costs primarily driven by rising healthcare expenses; and $35 million for higher costs in connection with natural gas pipeline matters. Total costs for natural gas pipeline matters were $273 million for the three months ended September 30, 2011, which included $177 million to conduct hydrostatic pressure tests and perform other pipeline-related activities and $96 million for estimated third-party liability related to the San Bruno accident. In comparison, total pipeline-related costs were $238 million for the three months ended September 30, 2010 and included the initial provision of $220 million for estimated third-party liability related to the San Bruno accident. (See “Natural Gas Pipeline Matters” below.)

Excluding costs currently passed through to customers, operating and maintenance expenses increased by $607 million for the nine months ended September 30, 2011, as compared to the same period in 2010. This increase was attributable to a number of factors, including $151 million for estimated environmental remediation and other liabilities associated with the Utility’s natural gas compressor site located near Hinkley, California; $127 million for labor and other

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maintenance-related costs, the majority of which was associated with the scheduled refueling outage at Diablo Canyon and higher storm costs; $55 million for legal and regulatory matters, including penalties associated with the Rancho Cordova accident; and $160 million for higher costs in connection with natural gas pipeline matters. Total costs for natural gas pipeline matters were $398 million for the nine months ended September 30, 2011, which included $303 million to conduct hydrostatic pressure tests and perform other pipeline-related activities, and $155 million for estimated third-party liability related to the San Bruno accident, that were partially offset by $60 million in insurance recoveries. In comparison, for the nine months ended September 30, 2010, the Utility incurred total pipeline-related costs of $238 million as described above.

The Utility projects that it will incur as much as $550 million in total expenses in 2011 to conduct pressure tests and other tests on portions of its natural gas pipeline system, continue its review and validation of pipeline records, respond to the regulatory proceedings and investigations described under “Natural Gas Pipeline Matters” below, and perform pipeline-related activities that are within the scope of the Utility’s proposed pipeline safety enhancement plan. The Utility also projects that it will incur costs of between $100 million and $200 million in 2012 for pipeline-related activities that are outside of the scope of the Utility’s proposed plan. The Utility will not seek to recover these 2011 and 2012 costs from customers. The amount of future unrecoverable costs also will be affected by the amount of third-party liability related to the San Bruno accident, related insurance recoveries, and the amount of any civil or criminal fines, penalties, or punitive damages that may be imposed on the Utility.

In addition, the Utility expects it will incur costs in 2012 and future periods to perform work within the scope of the Utility’s proposed pipeline safety enhancement plan and to comply with new state or federal requirements applicable to natural gas transmission operators. Although the Utility intends to seek recovery of these additional costs from customers, it is uncertain what portion of these additional costs ultimately will be recoverable through rates.

The Utility also forecasts that it will incur expenses in 2012 (and a comparable amount in 2013) that are approximately $200 million higher than amounts assumed under the 2011 GRC and GT&S settlements as the Utility works to improve the safety and reliability of its operations.

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation and amortization expense consists of depreciation and amortization on plant and regulatory assets, and decommissioning expenses associated with fossil fuel and nuclear plant decommissioning. The Utility’s depreciation, amortization, and decommissioning expenses increased by $66 million, or 13%, in the three months ended September 30, 2011, and $229 million, or 16%, in the nine months ended September 30, 2011, as compared to the same periods in 2010, primarily due to an increase in capital additions and an increase in depreciation rates as authorized by the 2011 GRC and GT&S rate cases.

The Utility’s depreciation expense for future periods is expected to increase as a result of an overall increase in capital expenditures and the implementation of higher depreciation rates as authorized by the CPUC.

Interest Income

In the three and nine months ended September 30, 2011, the Utility’s interest income decreased by $1 million, or 33%, and by $1 million, or 14%, as compared to the same periods in 2010. The Utility’s interest income in future periods will be primarily affected by changes in the balance of funds held in escrow pending resolution of the Chapter 11 disputed claims, changes in regulatory balancing accounts, and changes in interest rates. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements.)

Interest Expense

In the three and nine months ended September 30, 2011, the Utility’s interest expense increased by $10 million, or 6%, and $30 million, or 6%, respectively, as compared to the same periods in 2010. Interest costs rose as the Utility issued additional senior notes. The higher interest costs were partially offset by decreases in the outstanding balance of the energy recovery bonds. (See Note 4 of the Notes to the Condensed Consolidated Financial Statements.)

The Utility’s interest expense in future periods will be impacted by changes in interest rates, changes in the liability for Chapter 11 disputed claims, changes in regulatory balancing accounts and regulatory assets, and changes in the amount of debt outstanding as long-term debt matures and additional long-term debt is issued. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements and “Liquidity and Financial Resources” below.)

Other Income, Net

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The Utility’s other income net decreased by $6 million, or 24%, in the three months ended September 30, 2011, as compared to the same period in 2010. The Utility’s other income net increased by $32 million in the nine months ended September 30, 2011, as compared to the same period in 2010 when the Utility incurred costs to support a California ballot initiative that appeared on the June 2010 ballot. The increase was partially offset by a decrease in allowance for equity funds used during construction as the average balance of construction work in progress was lower as compared to the same period in 2010.

Income Tax Provision

The Utility’s income tax provision decreased by $51 million, or 48%, for the three months ended September 30, 2011, and $122 million, or 24% for the nine months ended September 30, 2011, as compared to the same periods in 2010. The effective tax rates for the three months ended September 30, 2011 and 2010 were 22% and 29%, respectively. The effective tax rates for the nine months ended September 30, 2011 and 2010 were 33% and 37%, respectively. The effective tax rate decreased in the three months ended September 30, 2011, as compared to the same period in 2010, due to a benefit associated with a loss carryback recorded in 2011. The effective tax rate decreased in the nine months ended September 30, 2011, as compared to the same period in 2010, due to the loss carryback noted above and the reversal of a deferred tax asset that had previously been recorded to reflect the future tax benefits attributable to the Medicare Part D subsidy after 2012, which was eliminated as part of the federal healthcare legislation passed during 2010.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

The Utility’s ability to fund operations depends on the levels of its operating cash flows and access to the capital and credit markets. The levels of the Utility’s operating cash and short-term debt fluctuate as a result of seasonal load, volatility in energy commodity costs, collateral requirements related to price risk management activity, the timing and amount of tax payments or refunds, and the timing and effect of regulatory decisions and financings, among other factors. The Utility generally utilizes equity contributions from PG&E Corporation and long-term senior unsecured debt issuances to fund debt maturities and capital expenditures and to maintain its CPUC-authorized capital structure. The Utility relies on short-term debt, including commercial paper, to fund temporary financing needs. The CPUC authorizes the aggregate amount of long-term debt and short-term debt that the Utility may issue and authorizes the Utility to recover its related debt financing costs. The Utility has short-term borrowing authority of $4.0 billion, including $500 million that is restricted to certain contingencies.

PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, fund Utility equity contributions as needed for the Utility to maintain its CPUC-authorized capital structure, fund tax equity investments, and pay dividends primarily depends on the level of cash distributions received from the Utility and PG&E Corporation’s access to the capital and credit markets.

Revolving Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s revolving credit facilities at September 30, 2011:

(in millions)	Termination   Date	Facility Limit		Letters of Credit   Outstanding		Borrowings		Commercial  Paper		Availability
PG&E Corporation	May 2016		$ 300(1)		$ -		$ 75		$ -		$ 225
Utility	May 2016		3,000(2)		335		-		801		1,864
Total revolving credit facilities			$ 3,300		$ 335		$ 75		$ 801		$ 2,089

⁽¹⁾  Includes a $100 million sublimit for letters of credit and a $100 million commitment for “swingline” loans, defined as loans that are made available on a same-day basis and are repayable in full within 7 days.

⁽²⁾  Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for swingline loans.

For the nine months ended September 30, 2011, the average outstanding commercial paper balance was $777 million and the maximum outstanding balance during the period was $1.2 billion; the average outstanding borrowings on PG&E Corporation’s revolving credit facility was $47 million and the maximum outstanding balance during the period was $75 million; and the average outstanding borrowings on the Utility’s revolving credit facility was $2 million and the maximum outstanding balance during the period was $208 million.

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On May 31, 2011, PG&E Corporation entered into a $300 million revolving credit facility with a syndicate of lenders. This revolving credit facility replaced the $187 million revolving credit facility that PG&E Corporation entered into on February 26, 2007 (amended April 27, 2009). Also on May 31, 2011, the Utility entered into a $3.0 billion revolving credit facility with a syndicate of lenders. This revolving credit facility replaced the $1.9 billion revolving credit facility that the Utility entered into on February 26, 2007 (amended April 27, 2009), and the $750 million revolving credit facility that the Utility entered into on June 8, 2010. The revolving credit facilities have terms of five years and all amounts are due and payable on the facilities’ termination date, May 31, 2016. At PG&E Corporation’s and the Utility’s request and at the sole discretion of each lender, the facilities may be extended for additional periods. The revolving credit facilities may be used for working capital and other corporate purposes, including commercial paper back-up.

Provided certain conditions are met, PG&E Corporation and the Utility have the right to increase, in one or more requests, given not more frequently than once a year, the aggregate lenders’ commitments under the revolving credit facilities by up to $100 million and $500 million, respectively, in the aggregate for all such increases.

Borrowings under the revolving credit facilities (other than swingline loans) will bear interest based, at PG&E Corporation’s and the Utility’s election, on (1) a London Interbank Offered Rate (“LIBOR”) plus an applicable margin or (2) the base rate plus an applicable margin. The base rate will equal the higher of the following: the administrative agent’s announced base rate, 0.5% above the federal funds rate, or the one-month LIBOR plus an applicable margin. Interest is payable quarterly in arrears, or earlier for loans with shorter interest periods. PG&E Corporation and the Utility also will pay a facility fee on the total commitments of the lenders under the revolving credit facilities. The applicable margins and the facility fees will be based on PG&E Corporation’s and the Utility’s senior unsecured debt ratings issued by Standard & Poor’s Rating Services and Moody’s Investor Service. Facility fees are payable quarterly in arrears.

The revolving credit facilities include usual and customary covenants for revolving credit facilities of this type, including covenants limiting liens to those permitted under PG&E Corporation’s and the Utility’s senior note indentures, mergers, sales of all or substantially all of PG&E Corporation’s and the Utility’s assets, and other fundamental changes. In addition, the revolving credit facilities require that PG&E Corporation and the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% as of the end of each fiscal quarter. The $300 million revolving credit facility agreement also requires that PG&E Corporation must own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting capital stock of the Utility. At September 30, 2011, PG&E Corporation and the Utility were in compliance with all covenants under each of the revolving credit facilities.

2011 Financings

Utility

On May 13, 2011, the Utility issued $300 million principal amount of 4.25% Senior Notes due May 15, 2021. The proceeds from this issuance were used to repay a portion of outstanding commercial paper.

On September 12, 2011, the Utility issued $250 million principal amount of 3.25% Senior Notes due September 15, 2021. The proceeds from this issuance were used to redeem $200 million principal amount of Series 1996 A pollution control bonds and to repay a portion of outstanding commercial paper.

During the nine months ended September 30, 2011, the Utility received cash contributions of $350 million from PG&E Corporation to ensure that the Utility had adequate capital to maintain the 52% common equity ratio authorized by the CPUC.

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PG&E Corporation

On May 9, 2011, PG&E Corporation entered into an Equity Distribution Agreement pursuant to which PG&E Corporation’s sales agents may offer and sell, from time to time, PG&E Corporation common stock having an aggregate gross offering price of up to $288 million. This amount represents the approximate unissued amount of the $400 million program previously announced on November 4, 2010. Sales of the shares are made by means of ordinary brokers’ transactions on the New York Stock Exchange, or in such other transactions as agreed upon by PG&E Corporation and the sales agents and in conformance with applicable securities laws. For the nine months ended September 30, 2011, PG&E Corporation issued 4,388,034 shares of common stock under the Equity Distribution Agreement for cash proceeds of $185 million, net of fees and commissions paid of $2 million. The proceeds from these issuances were used for general corporate purposes.

In addition, during the nine months ended September 30, 2011, PG&E Corporation issued 5,332,780 shares of common stock under its 401(k) plan, its Dividend Reinvestment and Stock Purchase Plan, and upon the exercise of employee stock options, generating $206 million of cash.

Future Financing Needs

As the Utility incurs costs associated with the matters discussed below under “Natural Gas Pipeline Matters,” the Utility’s debt financing and equity needs are expected to increase significantly. The following factors, among others, also will affect the amount and timing of the Utility’s future debt financings and equity needs:

• the amount of cash internally generated through normal business operations;

• the timing and amount of forecasted capital expenditures authorized by the CPUC;

• the timing of the resolution of the Chapter 11 disputed claims and the amount of interest on these claims that the Utility will be required to pay (see Note 9 of the Notes to the Condensed Consolidated Financial Statements);

• the amount of future tax payments (see the discussion of the Tax Relief Act under “Utility – Operating Activities” below); and

• the conditions in the capital markets, and other factors.

PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure. PG&E Corporation has issued equity of $391 million during the nine months ended September 30, 2011 and forecasts that it may need to issue additional equity of approximately $600 million through the end of 2012, including equity issued through the 401(k) plan and the Dividend Reinvestment and Stock Purchase Plan. Among other assumptions, this forecast assumes that the CPUC timely approves the Utility’s pipeline safety enhancement plan, cost allocation, and ratemaking proposals described below under “Natural Gas Pipeline Matters,” and excludes the impact of any fines, penalties, or punitive damages that may be imposed on the Utility in connection with the matters discussed below under “Natural Gas Pipeline Matters.” Changes in these assumptions could cause equity needs to increase.

The Utility’s current authorized capital structure will remain in effect through 2012. The Utility is required to file an application with the CPUC in April 2012 to begin the cost of capital proceeding in which the CPUC will determine the Utility’s authorized capital structure and rates of return beginning on January 1, 2013. A change in the Utility’s authorized capital structure also may impact PG&E Corporation’s and the Utility’s future debt and equity financing needs.

Dividends

The following table summarizes PG&E Corporation’s and the Utility’s dividends paid during the nine months ended September 30, 2011:

(in millions)
PG&E Corporation
Common stock dividends paid	$	525
Utility
Common stock dividends paid	$	537
Preferred stock dividends paid		10

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On September 21, 2011, the Board of Directors of the Utility declared a dividend on its outstanding series of preferred stock, payable on November 15, 2011, to shareholders of record on October 31, 2011.

On September 21, 2011, the Board of Directors of PG&E Corporation declared dividends of $0.455 per share, totaling $184 million, of which $179 million was paid on October 15, 2011 to shareholders of record on October 3, 2011. The remaining $6 million was reinvested under the Dividend Reinvestment and Stock Purchase Plan.

As the Utility focuses on improving the safety and reliability of its natural gas and electric operations, and subject to the outcome of the matters described under “Natural Gas Pipeline Matters” above, PG&E Corporation expects that its Board of Directors will maintain the current annual common stock dividend of $1.82 per share.

Utility

Operating Activities

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash.

The Utility’s cash flows from operating activities for the nine months ended September 30, 2011 and 2010 were as follows:

	Nine months ended September 30,
(in millions)	2011		2010
Net income		$ 756		$ 868
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,648		1,419
Allowance for equity funds used during construction		(64)		(89)
Deferred income taxes and tax credits, net		564		332
Other		193		175
Effect of changes in operating assets and liabilities:
Accounts receivable		(125)		(240)
Inventories		(60)		(65)
Accounts payable		97		15
Income taxes receivable/payable		(156)		241
Other current assets and liabilities		(153)		(33)
Regulatory assets, liabilities, and balancing accounts, net		70		(32)
Other noncurrent assets and liabilities		491		(240)
Net cash provided by operating activities		$ 3,261		$ 2,351

In the nine months ended September 30, 2011, net cash provided by operating activities increased by $910 million compared to the same period in 2010 primarily due to a decrease of $398 million in net collateral paid by the Utility related to price risk management activities. Collateral payables and receivables are included in other noncurrent assets and liabilities and other current assets and liabilities within the Condensed Consolidated Statements of Cash Flows. The increase also reflects a decrease in tax payments of $93 million in 2011 compared to 2010. The remaining changes in cash flows from operating activities consisted of fluctuations in activities within the normal course of business such as the timing and amount of customer billings and collections.

On December 17, 2010, the Tax Relief Act was signed into law, which generally allows the Utility to accelerate depreciation by deducting up to 100% of the investment cost of certain qualified property placed into service during 2011 (or as late as 2012 under “phase out” or transition rules) and up to 50% of the investment cost of property placed into service in 2012 (or as late as 2013 under the phase out rules). As a result of the accelerated depreciation, the Utility expects that it will not make a federal tax payment in 2011. The Utility also expects that its 2012 federal tax payment will be reduced depending on the amount and timing of the Utility’s qualifying capital additions. (See “Regulatory Matters – CPUC Resolution Regarding the Tax Relief Act” below.)

Future cash flow from operating activities will be affected by the timing and amount of payments to be made to third parties in connection with the San Bruno accident, related insurance recoveries, any penalties that may be assessed, and higher operating and maintenance costs associated with the Utility’s natural gas and electric operations. (See “Operating and Maintenance” above and “Natural Gas Pipeline Matters” below.)

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Investing Activities

The Utility’s investing activities consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. Cash used in investing activities depends primarily upon the amount and timing of the Utility’s capital expenditures, which can be affected by many factors, including the timing of regulatory approvals and the occurrence of storms and other events causing outages or damages to the Utility’s infrastructure. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear facilities.

The Utility’s cash flows from investing activities for the nine months ended September 30, 2011 and 2010 were as follows:

	Nine months ended          September 30,
(in millions)	2011		2010
Capital expenditures		$ (2,968)		$ (2,794)
Decrease in restricted cash		170		61
Proceeds from sales and maturities of nuclear decommissioning trust investments		1,574		962
Purchases of nuclear decommissioning trust investments		(1,604)		(1,001)
Other		13		15
Net cash used in investing activities		$ (2,815)		$ (2,757)

Net cash used in investing activities increased by $58 million in the nine months ended September 30, 2011 compared to the same period in 2010. This increase was primarily due an increase of $174 million in capital expenditures. This increase was partially offset by a decrease of $109 million in restricted cash that was primarily due to releases from escrow for settled or withdrawn Chapter 11 disputed claims in the nine months ended September 30, 2011, with few similar releases in 2010.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. (See “Capital Expenditures” below for further discussion of expected spending and significant capital projects.)

Financing Activities

The Utility’s cash flows from financing activities for the nine months ended September 30, 2011 and 2010 were as follows:

	Nine months ended September 30,
(in millions)	2011		2010
Borrowings under revolving credit facilities		$ 208		$ 400
Repayments under revolving credit facilities		(208)		-
Net issuances of commercial paper, net of discount of $2 in 2011 and 2010		196		251
Proceeds from issuance of long-term debt, net of discount and issuance costs of $6 in 2011 and $12 in 2010		544		838
Short-term debt matured		-		(500)
Long-term debt matured or repurchased		(700)		(95)
Energy recovery bonds matured		(299)		(285)
Preferred stock dividends paid		(10)		(11)
Common stock dividends paid		(537)		(537)
Equity contribution		350		170
Other		12		(40)
Net cash (used in) provided by financing activities		$ (444)		$ 191

In the nine months ended September 30, 2011, net cash used in financing activities increased by $635 million compared to the same period in 2010. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities and the level of cash provided by or used

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in investing activities. The Utility generally utilizes long-term senior unsecured debt issuances and equity contributions from PG&E Corporation to fund debt maturities and capital expenditures and to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.

PG&E Corporation

As of September 30, 2011, PG&E Corporation’s affiliates had entered into four tax equity agreements with two privately held companies to fund residential and commercial retail solar energy installations. Under these agreements, PG&E Corporation has agreed to provide lease payments and investment contributions of up to $398 million to these companies in exchange for the right to receive the benefits from local rebates, federal investment tax credits or grants, and a share of the customer payments made to these companies. As of September 30, 2011, PG&E Corporation had made total payments of $326 million under these tax equity agreements and received $115 million in benefits and customer payments. On April 14, 2011, PG&E Corporation borrowed $75 million under its $187 million revolving credit facility to partially fund the obligations under the tax equity agreements. On May 31, 2011, this borrowing was repaid and $75 million was borrowed under PG&E Corporation’s new $300 million revolving credit facility. (See Note 4 of the Notes to the Condensed Consolidated Financial Statements.) Lease payments, investment contributions, benefits, and customer payments received are included in cash flows from operating and investing activities within the Condensed Consolidated Statements of Cash Flows. PG&E Corporation’s financial exposure for these arrangements is generally limited to its lease payments and investment contributions to these companies.

In addition to the investments above, PG&E Corporation had the following material cash flows on a stand-alone basis for the nine months ended September 30, 2011 and 2010: dividend payments, common stock issuances, and transactions between PG&E Corporation and the Utility.

CONTRACTUAL COMMITMENTS

PG&E Corporation and the Utility enter into contractual commitments in connection with business activities. These future obligations primarily relate to financing arrangements (such as long-term debt, preferred stock, and certain forms of regulatory financing), purchases of electricity and natural gas for customers, purchases of transportation capacity, purchases of renewable energy, and the purchase of fuel and transportation to support the Utility’s generation activities. (Refer to the 2010 Annual Report, the “Liquidity and Financial Resources” section above and Notes 4 and 10 of the Notes to the Condensed Consolidated Financial Statements.)

CAPITAL EXPENDITURES

Most of the Utility’s revenue requirements to recover forecasted capital expenditures are authorized in the GRC, TO rate cases, and GT&S rate cases. (See “Regulatory Matters” below.)

The Utility also collects additional revenue requirements to recover capital expenditures related to projects that have been specifically authorized by the CPUC, such as new power plants, gas or electric distribution projects, and the SmartMeter^TM advanced metering infrastructure. As discussed below, the Utility could incur additional capital expenditures in the future if it acquires the Oakley Generation facility.

Additionally, as directed by the CPUC, the Utility filed its proposed natural gas transmission pipeline safety enhancement plan on August 26, 2011 to replace certain natural gas pipeline segments, install automatic or remote shut-off valves, and take other actions to improve its natural gas pipeline system. Under the first phase of the plan, the Utility forecasts that its total capital expenditures over a four-year period (2011-2014) will be approximately $1.4 billion. The Utility is uncertain whether and when its proposed plan will be approved by the CPUC and what portion of costs will be recoverable from customers. (See “Natural Gas Pipeline Matters – CPUC Rulemaking Proceeding” below.)

Finally, the Utility expects that it will make additional capital investments over the next 20 years related to the deployment of the “Smart Grid” in California. As required by California state law enacted in 2009, the Utility filed an application with the CPUC on June 30, 2011 requesting that the CPUC approve the Utility’s Smart Grid deployment plan. The Utility’s plan defines the Smart Grid as a modernized electric infrastructure which integrates advanced communications and control systems to create a highly automated, responsive, and resilient power delivery system that will both optimize service and empower customers to make informed energy decisions. If approved by the CPUC, the Utility’s plan will provide policy guidance for future Utility investments in Smart Grid projects and initiatives to be reviewed in future CPUC proceedings. The Utility’s application does not request approval or funding for specific Smart Grid projects or programs.

Oakley Generation Facility

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In December 2010, the CPUC approved a purchase and sale agreement between the Utility and Contra Costa Generating Station LLC for the development and construction of the Oakley Generation Facility, a 586-megawatt natural gas-fired, combined-cycle generation facility proposed to be located in Oakley, California. After the CPUC denied various applications for rehearing of its decision, several parties filed appeals with the California Supreme Court and the California Courts of Appeal. These appeals are still pending. Under the CPUC’s decision, if the Utility acquires the facility before January 1, 2016 the Utility would be unable to recover costs incurred before January 1, 2016 to acquire and operate the facility through rates. Instead, the Utility would have to rely on market revenues received from the sale of electricity generated by the facility to recover its costs. Costs the Utility incurs after January 1, 2016 would be recoverable through rates. The Utility and the developer are negotiating an amendment to the purchase and sale agreement to delay the acquisition until January 1, 2016 or later, and to reflect the possibility that the facility may be operated before the Utility acquires the facility. The Utility is uncertain whether and when the proposed amendment will be executed.

The California Energy Commission (“CEC”) authorized the developer to begin construction of the facility. Various environmental groups have filed an appeal of the CEC’s decision with the California Supreme Court, which is currently pending.

OFF-BALANCE SHEET ARRANGEMENTS

PG&E Corporation and the Utility do not have any other off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed in Note 2 (PG&E Corporation’s tax equity financing agreements) and Note 10 (the Utility’s commodity purchase agreements) of the Notes to the Condensed Consolidated Financial Statements.

CONTINGENCIES

In addition to the contingencies described under “Natural Gas Pipeline Matters” below, PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to Chapter 11 disputed claims, guarantees, regulatory proceedings, nuclear operations, legal matters, environmental compliance and remediation, and tax matters. (See Notes 9 and 10 of the Notes to the Condensed Consolidated Financial Statements.)

NATURAL GAS PIPELINE MATTERS

Following the San Bruno accident on September 9, 2010, various regulatory proceedings, investigations, and civil lawsuits were commenced, as discussed in the 2010 Annual Report. The current status and outcome of these matters as well as new developments are summarized here and described more fully below:

• NTSB Investigation. On August 30, 2011, the NTSB announced that it had determined the probable cause of the San Bruno accident, placing most of the blame on the Utility. The NTSB publicly issued its final accident investigation report on September 26, 2011. (See “The NTSB Pipeline Accident Report” below.)

• CPUC’s Independent Review Panel. On June 8, 2011, the independent review panel appointed by the CPUC issued its report containing the panel’s findings and recommendations. (See “Report of CPUC’s Independent Review Panel” below.)

• CPUC Investigations Regarding the Utility’s Natural Gas Pipelines. The CPUC has been investigating the San Bruno accident and other natural gas transmission matters, including an investigation pertaining to safety recordkeeping for the Utility’s pipeline that ruptured in San Bruno, as well as for its entire gas transmission system. (See “CPUC Investigation Regarding Utility’s Facilities Records for its Natural Gas Pipelines” below.) These investigations could lead to significant fines and other sanctions being imposed on the Utility.

• CPUC Rulemaking Proceeding. As directed by the CPUC, on August 26, 2011, the Utility filed its proposed natural gas transmission pipeline safety and enhancement plan. The Utility also requested that the CPUC approve the Utility’s proposed ratemaking and cost allocation mechanisms. (See “CPUC Rulemaking Proceeding” below.)

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• Criminal Investigation. On June 9, 2011, the Utility received notification that representatives from the U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo County District Attorney’s Office are conducting an investigation of the San Bruno accident. (See “Criminal Investigation Regarding San Bruno Accident” below.)

• CPUC’s Independent Audit. The CPUC Consumer Protection and Safety Division (“CPSD”) has engaged an independent auditing firm to conduct an audit of the Utility’s spending on its natural gas transmission function from 1996 to 2010. The Utility is uncertain when the audit will be completed and what action the CPUC may take in response to the audit results.

• The Utility’s Report Regarding the Class Location Designations for Pipelines. On June 30, 2011, the Utility submitted a report to the CPUC containing the results of the Utility’s system-wide review of class location designations for its natural gas transmission pipelines. Under federal and state regulations, the class location designation of a pipeline is used to determine the pipeline’s maximum allowable operating pressure (“MAOP”) up to which it can be operated. This review of class location designations has indicated that some segments of pipe had an MAOP higher than appropriate for their current class location designations. The Utility is uncertain whether the CPUC will take action with respect to the foregoing report.

• Pending Lawsuits and Claims. Various civil lawsuits have been filed by residents of San Bruno in California state courts against PG&E Corporation and the Utility related to the San Bruno accident. These lawsuits seek compensation for personal injury and property damage and other relief, including punitive damages. (See “Pending Lawsuits and Other Claims” below.)

• Special Review Committees. The independent special review committees appointed by the Boards of Directors of PG&E Corporation and the Utility have completed their reviews of the natural gas transmission and distribution practices used in the industry and by the Utility. The committees submitted their reports to the Boards of Directors in August 2011. The outcome of the committees’ reviews was consistent with the recommendations made in reports from the NTSB and CPUC’s independent review panel.

• CPUC Investigation Regarding Rancho Cordova Accident. On September 29, 2011, the presiding officer’s decision recommended that the Utility pay a penalty of $38 million (instead of $26 million as had been originally proposed). (See “CPUC Investigation Regarding Rancho Cordova Accident” below.)

• Natural gas distribution. Finally, several natural gas incidents that have recently occurred involve cracking in some of the Utility’s older natural gas distribution lines that are composed of plastic pipe. The Utility intends to replace over 1,200 miles of its natural gas distribution pipelines that are composed of this plastic pipe. The timing and estimated cost of replacement has not yet been determined. See Item 1.A. Risk Factors below.

The resolutions of these matters, including the amount of any civil or criminal fines or penalties, may have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. (See “Impact on Financial Condition and Results of Operations” and Part II, Item 1.A., Risk Factors below.)

The NTSB Pipeline Accident Report

On September 26, 2011, the NTSB issued its final investigation report concluding that the probable cause of the San Bruno accident was as follows:

• The Utility’s inadequate quality assurance and quality control in 1956 during its Line 132 relocation project, which allowed the installation of a substandard and poorly welded pipe section with a visible seam weld flaw that, over time grew to a critical size, causing the pipeline to rupture during a pressure increase stemming from poorly planned electrical work at the Milpitas Terminal; and

• The Utility’s inadequate pipeline integrity management program, which failed to detect and repair or remove the defective pipe section.

The NTSB also noted that state and federal exemptions of older pipelines from regulatory requirements to pressure test the pipelines contributed to the accident because pressure tests likely would have detected the installation defects. The NTSB also found that contributing factors were the lack of either automatic shutoff valves or remote control valves on the line and the Utility’s flawed emergency response procedures and delay in isolating the rupture to stop the flow of gas. The NTSB stated that several deficiencies revealed by its investigation of the San Bruno accident, such as “poor quality control during the pipe installation and inadequate emergency response,” were also contributing factors in the Rancho Cordova accident.

Among other recommendations, the NTSB recommended that the Utility establish a comprehensive emergency response procedure for responding to large-scale emergencies on transmission lines; equip its supervisory control and data acquisition system with tools to assist in recognizing and pinpointing the location of leaks, including line breaks; expedite the

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installation of automatic shutoff valves and remote control valves on transmission lines in certain areas; revise its post-accident toxicological testing program to ensure that testing is timely and complete; assess every aspect of its pipeline integrity management program and implement a revised program; conduct threat assessments using the revised risk analysis methodology incorporated into the revised integrity management program, and report the results of those assessments to the CPUC and the federal Pipeline and Hazardous Materials Safety Administration (“PHMSA”).

The NTSB recommended that the CPUC conduct a comprehensive audit of all aspects of the Utility’s operations and require the Utility to correct all deficiencies identified as a result of the NTSB’s investigation, as well as any additional deficiencies identified through the CPUC’s comprehensive audit, and verify that all corrective actions are completed.

The NTSB also recommended that, with respect to natural gas transmission pipelines nationwide, PHMSA amend its regulations to directly require the installation of automatic shutoff valves or remote control valves in certain areas, delete the regulatory exemption from hydrostatic pressure-testing requirements for pre-1970 pipelines, and require that all natural gas transmission pipelines be configured so as to accommodate in-line inspection tools, with priority given to older pipelines.

The Utility is required to submit a report to the NTSB in December 2011 that addresses the actions taken or intended to be taken by the Utility to implement the NTSB’s recommendations.

Report of CPUC’s Independent Review Panel

On June 8, 2011, the CPUC’s independent review panel issued its report concluding that “the explosion of the pipeline at San Bruno was a consequence of multiple weaknesses in PG&E Corporation’s and the Utility’s management and oversight of the safety of its gas transmission system.” Among other findings, the panel found that the Utility’s pipeline integrity management program had several shortcomings and issued 18 formal recommendations.

The Utility filed comments on the panel’s report stating that the Utility agreed with the panel’s overall conclusions and in principle with its recommendations. Other parties filed comments to the panel’s report, including a suggestion that the deficiencies identified by the panel in the Utility’s management of its gas transmission system may also apply to its gas distribution system, and urged the CPUC to review the Utility’s gas distribution system as soon as possible.

The independent review panel report also contained findings and recommendations about the structure, culture, and resources of the CPUC. In response to recommendations to provide the CPSD staff with additional enforcement tools, on September 30, 2011, the CPUC released a draft resolution that would delegate authority to the CPSD staff (and other staff as may be directed by the CPUC’s Executive Director) to levy citations and impose fines to enforce compliance with certain state and federal regulations related to the safety of natural gas facilities and utilities’ natural gas operating practices. The proposed resolution states that any citation issued by the staff must assess the maximum penalty that could be imposed by the CPUC under state law. Under current state law, the maximum penalty that the CPUC could impose is $20,000 per day, per violation. In October 2011, the California Governor signed legislation that will increase the maximum penalty to $50,000 per day, per violation, effective January 1, 2012. The proposed resolution is scheduled to be considered by the CPUC on November 10, 2011.

PG&E Corporation and the Utility are uncertain how the CPUC will use the independent review panel’s and the NTSB’s findings and recommendations concerning the Utility’s operations or whether the CPUC will commence additional investigations or proceedings.

CPUC Investigation Regarding Rancho Cordova Accident

On September 29, 2011, a CPUC administrative law judge (“ALJ”) denied a request to approve stipulations previously submitted by the Utility, the CPSD, and The Utility Reform Network (“TURN”), to resolve the CPUC’s investigation of the Rancho Cordova accident including the proposed payment of a $26 million penalty by the Utility. Instead, the ALJ recommended that the Utility pay a penalty of $38 million based on the ALJ’s determination that (1) CPUC case law warrants a higher penalty when a fatality has occurred and (2) the Utility could be fined as much as $97 million if the case were fully litigated and all allegations were proven.

On October 19, 2011, the Utility, CPSD, and TURN filed a joint motion to accept the increased penalty amount. The Utility has agreed to pay the CPUC for the costs it incurred in connection with the investigation and that it would not seek to recover the penalty or costs through rates. On October 31, 2011, the ALJ issued a proposed decision extending the statutory 12-month deadline to conclude the investigation. The proposed decision, to be voted on by the CPUC on November 10, 2011, will give the CPUC time to consider and rule on the joint motion accepting the increased penalty.

As of September 30, 2011, approximately $39 million was accrued for penalties and other costs associated with the

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Rancho Cordova accident in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.

CPUC Investigation Regarding Utility’s Facilities Records for its Natural Gas Pipelines

On February 24, 2011, the CPUC issued an order instituting a formal investigation pertaining to safety recordkeeping for the Utility’s gas transmission pipeline (Line 132) that ruptured in the San Bruno accident, as well as for its entire gas transmission system.

The first phase of the CPUC’s investigation has been limited to (1) whether the Utility’s gas transmission pipeline recordkeeping and its knowledge of its own transmission gas system (and, in particular, the San Bruno pipeline) was deficient and unsafe, and (2) whether the Utility thereby violated applicable law and safety standards. In particular, this phase will determine, among other matters, whether the San Bruno tragedy would have been preventable by the exercise of safe procedures and/or accurate and effective technical recordkeeping in compliance with the law. The CPUC will consider whether the Utility’s approach to recordkeeping stems from corporate-level management policies and practices and, if so, whether those management practices and policies contributed to recordkeeping violations that adversely affected safety.

During the first two quarters of 2011, the Utility reviewed its records dating back to 1955 and provided extensive information to the CPUC about the regulatory history applicable to gas transmission and recordkeeping practices, the Utility’s recordkeeping policies and practices, actions the Utility has taken since 1955 to promote safety on its gas transmission pipeline system, and safety risk assessments.

If the CPUC determines that the Utility violated gas safety recordkeeping requirements, the CPUC will schedule a later phase or phases to determine whether penalties are warranted, and if so the amount of such penalties. If the CPUC determines that the Utility violated applicable requirements, the CPUC could impose penalties on the Utility of up to $20,000 per day, per violation, or up to $50,000 per day, per violation, for violations occurring on or after January 1, 2012.

PG&E Corporation and the Utility are unable to estimate a possible loss or range of loss associated with any penalties that may be imposed by the CPUC on the Utility.

Criminal Investigation Regarding San Bruno Accident

On June 9, 2011, the Utility was notified that representatives from the U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo County District Attorney’s Office are conducting an investigation of the San Bruno accident. The Utility is cooperating with the investigation. The investigation is in the early stages and PG&E Corporation and the Utility are unable to estimate a possible loss or range of loss associated with any criminal fines or penalties that may be imposed on the Utility.

CPUC Rulemaking Proceeding

As directed by the June 9, 2011 CPUC order, on August 26, 2011, the Utility filed its proposed natural gas transmission pipeline safety enhancement plan to conduct pressure tests, replace certain natural gas pipeline segments, install automatic or remote shut-off valves, and perform other activities to improve its natural gas pipeline system. The Utility’s proposed plan contains two phases:

• In the first phase, to be completed over a four-year period (2011 through 2014), the Utility would focus on older pipeline segments in highly populated areas that have not been pressure tested previously. The Utility plans to replace at least 186 miles of pipeline, conduct pressure testing on 783 miles of pipeline, conduct in-line inspections of 234 miles of pipeline, and retrofit 199 miles of pipeline to accommodate in-line inspections.

• In the second phase, beginning in 2015, the Utility would focus on pipeline segments that have been previously pressure tested or are in rural areas.

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The Utility has requested that the CPUC approve the proposed scope of activities for both phases and authorize recovery of certain phase 1 costs in rates, as described below. The Utility proposed to address phase 2 timing and cost recovery in a separate application to change rates beginning on January 1, 2015, consistent with the GT&S rate case cycle.

The Utility forecasts that its total expenditures over the four-year period of phase 1 will be approximately $2.2 billion, which includes an estimated $1.4 billion in capital expenditures and $750 million in expenses. The Utility has proposed that plan-related costs incurred after 2011, and certain costs to be incurred from 2012 through 2014, be recovered through rates. The Utility would recover capital costs in rates only after specific projects have been placed into operation and the actual costs of the projects are known. For non-capital-related expenses, the Utility would recover in rates its forecast of annual expenses subject to true-up at the end of each year to reflect actual costs incurred by the Utility. Any forecasted amounts that the Utility does not spend by the end of phase 1 would be refunded to ratepayers.

The Utility’s cost estimate and project schedule assumes that the CPUC will issue a proposed decision early in 2012 authorizing the Utility to proceed with phase 1. If there is a significant delay in issuing the CPUC decision or if the CPUC requires material modifications to the plan, the Utility may need to change the scope of work or schedule which could result in changes to cost estimates. On November 2, 2011, an amended scoping memo was issued that establishes a revised procedural schedule. Under the revised schedule, hearings will begin on March 12, 2012 and conclude on March 23, 2012. The Utility expects that it will incur costs to perform pipeline-related work within the scope of the proposed plan before the CPUC issues a decision which, in light of the new schedule, may not occur until mid-2012 or later. The Utility has requested that the CPUC authorize the Utility to track costs incurred under the plan after January 1, 2012 so that the CPUC can consider whether such costs will be recoverable from customers after a final decision on the plan is issued. If the CPUC does not authorize this request, plan-related costs the Utility incurs before the CPUC issues a final decision on the plan may not be recoverable through rates.

Finally, the CPUC has not yet acted on the proposed stipulation to resolve an order to show cause (“OSC”) that the CPUC issued on March 24, 2011 to require the Utility to show why it should not be penalized for failing to present evidence that it “aggressively and diligently searched” its pipeline records as previously ordered. On September 12, 2011, the Utility filed its report with the CPUC stating that the Utility had completed validation of the MAOPs on high-priority pipelines.

Pending Lawsuits and Other Claims

In addition to the investigations and proceedings discussed above, approximately 100 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, have been filed against PG&E Corporation and the Utility in connection with the San Bruno accident on behalf of approximately 370 plaintiffs. The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages. These cases have been coordinated and assigned to one judge in the San Mateo County Superior Court. On October 6, 2011, the judge overseeing the consolidated San Bruno civil litigation set a trial date for July 23, 2012 for the first of these cases.

The Utility has recorded a cumulative provision of $375 million ($220 million in 2010 and $155 million in 2011) for estimated third-party liability claims, and has made payments of $86 million as of September 30, 2011. The Utility estimates it is reasonably possible that it may incur as much as an additional $225 million for third-party claims, for a total loss of $600 million, increased from the $400 million previously estimated. As more information becomes known, estimates and assumptions regarding the amount of third-party liability incurred in connection with the San Bruno accident may be subject to further changes. Future changes in estimates may have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. PG&E Corporation and the Utility are unable to estimate a possible loss or range of loss associated with any punitive damages that may be imposed on the Utility. (See Note 10 to the Condensed Consolidated Financial Statements.)

The Utility has liability insurance from various insurers who provide coverage at different policy limits that are triggered in sequential order or “layers.” Generally, as the policy limit for a layer is exhausted the next layer of insurance becomes available. The aggregate amount of this insurance coverage is approximately $992 million in excess of a $10 million deductible. The Utility submitted insurance claims to certain insurers for the lower layers and recognized $60 million for insurance recoveries in the second quarter of 2011, which were collected during the third quarter. Although the Utility currently considers it likely that a significant portion of costs incurred for third-party claims relating to the San Bruno accident will ultimately be recovered through its insurance, it is unable to predict the amount and timing of additional insurance recoveries. (See Note 10 to the Condensed Consolidated Financial Statements.)

Additionally, a purported shareholder derivative lawsuit was filed following the San Bruno accident to seek recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims. The judge has ordered that proceedings in the derivative lawsuit be delayed until further order of the court.

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In February 2011, PG&E Corporation rejected a shareholder demand that had been made following the San Bruno accident demanding that the PG&E Corporation Board of Directors (“Board”) (1) institute an independent investigation of the San Bruno accident and related alleged safety issues; (2) seek recovery of all costs associated with such issues through legal proceedings against those determined to be responsible, including board members, officers, other employees, and third parties; and (3) adopt corporate governance initiatives and safety programs. The Board authorized PG&E Corporation to reject the demand as had been recommended by the Evaluation Committee, a committee composed of independent directors that had been appointed to evaluate the demand and recommend how the Board should respond. The Board also reserved the right to commence further investigation or litigation regarding the San Bruno accident if the Board deems such investigation or litigation appropriate.

Impact on Financial Condition and Results of Operations

For the three and nine months ended September 30, 2011, the Utility has incurred incremental pipeline-related costs in operating and maintenance expense of $177 million and $303 million, respectively, to perform hydrostatic pressure tests and other tests on portions of its natural gas pipeline system, complete its review and validation of pipeline records, respond to regulatory proceedings and investigations, and perform other activities related to the safety of its natural gas pipeline system. These costs will not be recoverable from customers through rates. (See “Operating and Maintenance” above.)

The Utility projects that it will incur as much as $550 million in total expenses in 2011 to conduct pressure tests and other tests on portions of its natural gas pipeline system, continue its review and validation of pipeline records, respond to regulatory proceedings and investigations, and to perform pipeline-related activities that are within the scope of the Utility’s proposed pipeline safety enhancement plan. The Utility also projects that it will incur costs of between $100 million and $200 million in 2012 for pipeline-related activities that are outside the scope of the proposed plan. The Utility will not seek to recover these 2011 and 2012 costs from customers. In addition, the Utility expects it will incur costs in 2012 and future periods to perform work within the scope of the Utility’s proposed pipeline safety enhancement plan and to comply with new state or federal requirements applicable to natural gas transmission operators. Although the Utility intends to seek recovery of these costs from customers, it is uncertain what portion of these additional costs ultimately will be recoverable through rates.

PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows will be affected by the scope and timing of the Utility’s pipeline safety enhancement plan that is approved by the CPUC; when and whether the CPUC approves the Utility’s request to recover plan-related costs that are incurred before the CPUC issues a final decision; the ultimate amount of pipeline-related costs that are not recoverable from customers, the amount of civil or criminal fines, penalties, or punitive damages the Utility may be required to pay as a result of the outcome of the regulatory proceedings, investigations, and civil litigation discussed above, and new state or federal requirements that may be imposed on operators of natural gas transmission pipelines.

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC and other federal and state regulatory agencies. Significant regulatory developments that have occurred since the 2010 Annual Report was filed with the Securities and Exchange Commission (“SEC”) are discussed below.

2011 General Rate Case Application

On May 5, 2011, the CPUC issued a final decision in the 2011 GRC to authorize the Utility’s revenue requirements for 2011 through 2013 for its costs to own and operate its electric and natural gas distribution and electric generation operations. The final decision approves the unopposed October 15, 2010 settlement agreement among the Utility, the CPUC’s Division of Ratepayer Advocates, and nearly all other intervening parties.

The CPUC authorized a total 2011 revenue requirement of approximately $6.0 billion, which reflects an overall increase of $450 million, or 8.0%, over the total 2010 authorized amount of $5.6 billion, including $55 million for the recovery of financing costs and the accelerated return of capital associated with conventional meters that have been replaced by SmartMeter^TM devices. PG&E Corporation’s and the Utility’s financial results for the three and nine months ended September 30, 2011 reflect the additional authorized base revenues from January 1, 2011. (See “Results of Operations” above.) The CPUC decision also authorized attrition increases of $180 million for 2012 and $185 million for 2013.

As required by the GRC decision, on August 3, 2011, the Utility filed its first annual report with the CPUC containing information about the Utility’s budgeted expense and capital expenditures compared to funding targets set forth in the settlement agreement adopted by the CPUC. Also as required by the decision, on September 30, 2011, the Utility filed its first semi-annual report on gas distribution safety.

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Electric Transmission Owner Rate Cases

On August 10, 2011, the FERC approved an uncontested settlement of the Utility’s 13^th TO rate case that increases the Utility’s annual retail revenue requirement from $875 million to $934 million, with rates effective as of March 1, 2011. The Utility has recorded reserves to refund customers the difference between revenues collected at the higher as-filed rates and the rates included in the settlement since March 1, 2011. Retail electric rates will be adjusted on January 1, 2012 to reflect the revenue requirement adopted in the settlement and any over-collected amounts will be refunded to customers, with interest.

2011 Gas Transmission and Storage Rate Case

On April 14, 2011, the CPUC issued a final decision that approves the settlement agreement, known as the Gas Accord V Settlement Agreement (“Gas Accord V”), entered into among the Utility and other parties to determine the rates and terms and conditions of the Utility’s gas transmission and storage services for a four-year period beginning January 1, 2011. The decision also resolves several objections raised by the other two California gas utilities.

The CPUC authorized a 2011 natural gas transmission and storage revenue requirement of $514 million, an increase of $52 million over the 2010 adopted revenue requirement. PG&E Corporation’s and the Utility’s financial results for the three and nine months ended September 30, 2011 reflect the additional authorized base revenues from January 1, 2011. (See “Results of Operations” above.)

With attrition increases authorized by the decision, the Utility’s natural gas transmission and storage revenue requirements for 2012, 2013, and 2014 will be $541 million, $565 million, and $582 million, respectively. The Utility also has been authorized to recover (through natural gas transmission and storage rates) revenue requirements for other costs, such as the cost of electricity used to operate natural gas compressor stations and other costs, that are determined in the Utility’s 2011 GRC or other Utility regulatory proceedings.

On July 14, 2011, the CPUC issued a decision in the “safety phase” of the GT&S rate case. The decision requires the Utility to offer maps of gas transmission facilities and provide free training to fire departments and other emergency response agencies, verify and submit inspection records to the CPUC for pipeline shutoff valves, and expand customer outreach to promote awareness of gas safety issues, among other required actions. The Utility must fund these activities with the revenues authorized in the Gas Accord V.

Finally, as required by the decision, on September 30, 2011, the Utility filed its semi-annual safety report with the CPUC’s Energy Division and the CPSD to provide details about the Utility’s use of funds budgeted for pipeline safety, reliability and integrity projects and activities, including an explanation of whether the Utility has under-spent or over-spent funds.

Energy Efficiency Programs and Incentive Ratemaking

On June 27, 2011, the Utility requested that the CPUC approve an incentive award of $32 million based on the energy savings attributable to the Utility’s energy efficiency programs in 2009. The CPUC may issue a decision by December 2011 or early 2012.

On June 30, 2011, the California Governor signed Senate Bill 87 (“SB 87”) into law, which includes a provision that allows the transfer of up to $155 million from the statewide gas-consumption surcharge fund to the California General State Fund in the 2011 fiscal year (from July 2011 through June 2012). The surcharge is collected by the Utility, San Diego Gas and Electric Company, and Southern California Gas Company to help fund gas public purpose programs, including energy efficiency programs. On October 6, 2011, the CPUC issued a final decision that authorizes the utilities to use unspent funds from prior program years to address the shortfall that would result if the transfer to the General Fund is made. The decision effectively allows the Utility to continue operating its energy efficiency programs at or near the level of funding previously approved by the CPUC.

On October 6, 2011, the CPUC also extended the statutory deadline to December 12, 2011 for resolving modifications to the incentive ratemaking mechanism for the 2010 through 2012 program cycle and future years. It is uncertain what modifications will ultimately be adopted by the CPUC.

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CPUC Resolution Regarding the Tax Relief Act

The Tax Relief Act generally allows the Utility to accelerate depreciation by deducting up to 100% of the investment cost of certain qualified property placed into service during 2011 (or as late as 2012 under “phase out” or transition rules) and up to 50% of the investment cost of certain qualified property placed into service in 2012 (or as late as 2013 under the phase out rules). Amounts that are not subject to 50% or 100% acceleration will be recovered under normal tax depreciation lives and methods. As a result of the accelerated depreciation, the Utility’s federal tax payments are expected to be lower. (See “Liquidity and Financial Resources” above.) The resolution authorizes the Utility to use the tax savings to invest in certain additional capital infrastructure, not otherwise funded through rates.

On April 14, 2011, the CPUC adopted a resolution establishing a one-way memorandum account for certain rate-regulated utilities, including the Utility, to record the net change in the cost of providing utility service associated with the Tax Relief Act. The CPUC adopted an amended resolution on June 23, 2011 that primarily clarified certain language in the April 14, 2011 resolution.

The memorandum account will track: (1) the reduction in revenue requirements that is due to lower rate base resulting from deferred tax liabilities related to the accelerated federal tax depreciation, (2) the increase in revenue requirements associated with incremental eligible capital investments that meet certain CPUC guidelines as described in the resolution, and (3) other applicable reductions and increases in revenue requirements as defined in the resolution. The memorandum account will be applicable to CPUC-jurisdictional assets only; however, it is expected to exclude investments that have separate ratemaking treatment such as the Utility’s program to install an advanced metering system. The net benefits of the Tax Relief Act related to those excluded investments will automatically flow to customers under existing balancing account mechanisms. The memorandum account will be in effect for capital investments (other than those related to natural gas transmission operations) until 2014, the test year of the Utility’s next GRC. The memorandum account will be in effect for capital investments related to natural gas transmission operations until 2015, the test year for the Utility’s next GT&S rate case. In each rate case, the CPUC will determine the disposition of the memorandum account.

Deployment of SmartMeter^TM Technology

The CPUC has authorized the Utility’s program to install approximately 10 million advanced electric and gas meters throughout the Utility’s service territory. The CPUC has authorized the Utility to recover $2.3 billion in estimated project costs. Absent CPUC authorization, costs that exceed $2.3 billion will not be recoverable through rates. As of September 30, 2011, the Utility has installed 8.6 million meters and incurred costs of $2.2 billion. The Utility has recorded a provision of $36 million as of September 30, 2011 and December 31, 2010, representing the current forecast of capital-related costs that are expected to exceed the CPUC-authorized cost cap and that therefore are not currently recoverable through rates. The Utility will update its forecasts as the project continues and may incur additional non-recoverable costs.

On March 24, 2011, the Utility filed an application with the CPUC seeking approval of the Utility’s proposal to provide residential customers the option to turn off the radios in their gas and electric SmartMeter™ devices to disable the radio frequency (“RF”) communications used in the wireless meters. The Utility requested that the CPUC authorize electric and gas revenue requirements totaling $84 million through 2013 to recover the Utility’s estimated costs to provide the “radio-off” option which would be collected through fees charged to customers who choose the radio-off option. PG&E Corporation and the Utility are unable to predict whether the CPUC will approve the Utility’s proposal. Additionally, the CPUC is considering SmartMeter™ alternatives raised by other parties, including an analog meter, a digital meter without a radio, and a wired meter. PG&E Corporation and the Utility are uncertain whether the CPUC will approve the Utility’s radio-off proposal or an alternative SmartMeter™ opt-out proposal.

On April 11, 2011, the Kern County Superior Court in Bakersfield, California dismissed the pending class action complaint that had alleged that the SmartMeter™ system generated inaccurate bills and led to overcharges, among other allegations. The plaintiff filed an appeal of the dismissal on August 26, 2011. The Utility expects the appeal to be heard and decided by the California Courts of Appeal before the end of 2012.

Diablo Canyon Nuclear Power Plant

The NRC operating license for Diablo Canyon Unit 1 expires in November 2024 and the NRC operating license for Diablo Canyon Unit 2 expires in August 2025. On November 24, 2009, the Utility filed an application to request the NRC to renew each of the operating licenses for Diablo Canyon for 20 years, until November 2044 for Unit 1 and August 2045 for Unit 2. The license renewal process is expected to take several years as the NRC holds public hearings and conducts safety and environmental analyses and site audits. The Utility’s application has been challenged by local environmental and anti-nuclear power organizations. On October 24, 2011, the NRC ruled that one of the challengers’ contentions should be admitted for hearing. This contention argues that the environmental report submitted by the Utility in November 2009 in

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support of its renewal application was inadequate because it did not include an analysis of the newly discovered earthquake fault that is located offshore from Diablo Canyon (the “Shoreline Fault”). In 2010, the Utility performed additional analyses that considered seismic information about the Shoreline Fault and these additional analyses did not change the overall results of the Utility’s severe accident mitigation alternative analysis that had originally been submitted with the renewal application. The Utility intends to present this additional information to respond to the contention at the NRC hearing that will be held in the future. As discussed below, the NRC has agreed to delay the licensing renewal process, including any hearings.

As part of the renewal application process, the NRC will issue an environmental impact report and a safety evaluation report. In May 2011, the NRC agreed to delay issuing its environmental impact report until the Utility completes additional seismic studies. These studies are not expected to be completed until 2015 or 2016. In early June 2011, the NRC issued its safety evaluation report and concluded that the Utility’s safety plan and processes meet federal requirements for the longer-term operation of the plant. The NRC stated that its report may change depending on the results of the Utility’s additional seismic studies. PG&E Corporation and the Utility are unable to predict when and whether the NRC will approve the license renewal application.

Following the March 2011 earthquake and tsunami that caused significant damage to nuclear facilities in Japan, the NRC appointed a task force to develop recommendations about how to improve safety at U.S. nuclear power plants and upgrade protection against earthquakes, floods and power losses. The twelve safety recommendations were released in July 2011 and have been reviewed by the NRC staff. In October 2011, the NRC directed its staff to begin immediately implementing seven of the recommendations through the NRC’s rulemaking process. It is expected that the NRC will adopt regulations or issue orders requiring nuclear power plants to implement some of the near-term recommendations within the next year. Although the Utility has already taken significant action at Diablo Canyon to address concerns raised by the events in Japan, the Utility could incur additional costs to comply with new regulations or orders that may be adopted by the NRC to implement the task force’s recommendations.

Finally, in early August 2011, the NRC found that a report submitted by the Utility to the NRC on January 7, 2011 to provide updated seismological information did not conform to the requirements of the current Diablo Canyon operating license. On October 21, 2011, the Utility filed a request that the NRC amend the operating license to address this issue. If the NRC does not approve the request the Utility could be required to perform additional analyses of Diablo Canyon’s seismic design which could indicate that modifications to Diablo Canyon would be required to address seismic design issues. The NRC could order the Utility to cease operations until the modifications were made or the Utility could voluntarily cease operations if it determined that the modifications were not economical or feasible.

The Utility has previously requested that the CPUC authorize the Utility to recover approximately $85 million for costs estimated to be incurred during the lengthy NRC relicensing process. In April 2011, a motion to dismiss the Utility’s application was filed but the CPUC has not yet ruled on this motion. On September 23, 2011, the Utility also requested that the CPUC authorize the Utility to recover an additional $47 million to complete the additional seismic studies that the Utility is conducting. The Utility is uncertain when and whether the CPUC will approve the Utility’s requests for authorization. Actual costs may be higher than estimates depending on environmental permitting processes and required environmental mitigation.

(See the discussion about risks related to the Utility’s nuclear operations in the 2010 Annual Report under Item 1A. Risk Factors, below.)

Other Matters

In addition to the ongoing investigations, proceedings, and litigation related to the Utility’s gas pipeline system (see “Natural Gas Pipeline Matters” above), the CPUC is considering the following matters:

On June 10, 2011, the CPUC commenced an investigation to determine whether the Utility should be penalized for failing to comply with the CPUC’s resource adequacy requirements for March, April, and July 2010. The CPSD recommends that the Utility be fined $7 million for these violations, as calculated in accordance with the penalty provisions previously adopted by the CPUC. On September 23, 2011, the Utility submitted testimony to the CPSD contending that it had complied with the CPUC’s resource adequacy program. PG&E Corporation and the Utility are unable to predict the outcome of this investigation.

On June 10, 2011, the CPUC also issued an order to investigate whether the Utility failed to comply with the CPUC’s November 9, 2009 decision granting the Utility’s request for a permit to construct a substation when the Utility removed an almond tree orchard to prepare the site for construction. On September 26, 2011, the Utility and the CPSD filed a settlement agreement with the CPUC under which the Utility will pay $100,000 in penalties and contribute $50,000 to an environmental group.

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Additionally, on October 14, 2011, the Utility filed a supplemental report with the CPUC detailing the results of the Utility’s re-inspection of its underground facilities (used to house electric distribution equipment) in the San Jose division and other areas of the Utility’s service territory. The supplemental report was prompted by the Utility’s earlier report that it had determined that some underground electric facilities had not been inspected as reported by some employees and contractors. The Utility has completed the re-inspections of these facilities and has taken steps to improve its inspection verification procedures and increase inspection audits. In addition, the Utility has committed to re-inspect approximately 16,000 additional overhead electric facilities. The Utility will report the results to the CPUC by April 30, 2012.

PG&E Corporation and the Utility are unable to predict how the above matters will affect the other regulatory proceedings and current investigations involving the Utility, or whether additional proceedings or investigations will be commenced that could result in further regulatory orders or the imposition of fines or penalties on the Utility.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. (See “Risk Factors” in the 2010 Annual Report.) These laws and requirements relate to a broad range of the Utility’s activities, including the discharge of pollutants into the air, water, and soil; the transportation, handling, storage, and disposal of spent nuclear fuel; remediation of hazardous wastes; and the reporting and reduction of carbon dioxide and other GHG emissions. Significant developments that have occurred since the 2010 Annual Report was filed with the SEC are discussed below.

Climate Change

The California Global Warming Solutions Act of 2006 (also known as Assembly Bill 32 or “AB 32”) requires the gradual reduction of GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2012. In December 2008, the California Air Resources Board (“CARB”) adopted a scoping plan that contains recommendations for achieving the maximum technologically feasible and cost-effective GHG reductions to meet the 2020 reduction target, including a proposed cap-and-trade program. After the San Francisco County Superior Court ruled that the CARB had failed to comply with the California Environmental Quality Act (“CEQA”), the CARB issued its proposed report on June 13, 2011 of its further review and analysis of alternatives to the scoping plan measures. The CARB again concluded that a cap-and-trade program continues to be the preferred alternative. While the CARB’s appeal of the Superior Court’s order is pending, the CARB proceeded with its rulemaking and approved the final cap and trade regulation on October 20, 2011. The cap-and-trade regulations are expected to become effective on January 1, 2012, but the program will be implemented on a delayed basis by requiring compliance with the initial emissions cap beginning on January 1, 2013 instead of January 1, 2012. During 2012, the CARB will conduct market simulations and additional cap-and-trade market design activities. It is uncertain when the CARB’s appeal will be decided and how the final decision will affect implementation of the cap-and-trade program.

Renewable Energy Resources

On April 12, 2011, the California Governor signed new legislation establishing a new renewable portfolio standard (“RPS”) that increases the amount of renewable energy that load-serving entities (“LSE’s”), such as the Utility, must deliver to their customers from at least 20% of their total retail sales, as required by the prior law, to 33% of their total retail sales. The legislation will become effective on December 10, 2011. (In response to the enactment of the new RPS law, the CARB abandoned its regulatory efforts to establish a 33% renewable energy standard.) The new RPS law requires that each LSE procure an average of 20% of its retail sales from renewable resources for the first compliance period of January 1, 2011 to December 31, 2013. The new law directs the CPUC to establish the RPS requirement for each succeeding multi-year compliance period (2014-2016 and 2017-2020) as well as reasonable progress targets for individual years in each compliance period, by January 1, 2012. (The Utility expects that the CPUC will use the reasonable yearly progress targets to establish the RPS requirement for the relevant compliance period.)

The new RPS law creates three distinct categories of renewable energy products and imposes minimum or maximum procurement targets for each of these product categories for each compliance period. With certain exceptions, these categorical requirements will only apply to renewable energy contracts that are entered into after June 1, 2010. The new law also (1) limits the use of certain types of unbundled renewable energy credits (“RECs”) and (2) restricts the ability to carry forward (or “bank”) RPS volumes from certain types of short-term contracts, to satisfy compliance obligations.

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The CPUC has opened a new rulemaking proceeding to develop and adopt regulations to implement the new RPS law, including the establishment of an RPS requirement for each compliance period and determining how different types of renewable energy products will qualify toward meeting the compliance obligations. In addition, the CPUC is expected to determine whether to change the penalty provisions established under the former RPS law, which permitted a maximum penalty of $25 million per year on each LSE that had an unexcused failure to meet its compliance obligation. Until the CPUC adopts regulations to implement the new law, it is uncertain how the CPUC’s regulations and decisions issued pursuant to the former 20% RPS statute, including the penalty provisions, will apply to the new RPS requirements.

The costs incurred by the Utility under third-party contracts to meet RPS requirements are tracked in a balancing account and recovered through rates. The costs of Utility-owned renewable generation projects will be recoverable through traditional cost-of-service ratemaking mechanisms provided that costs do not exceed the maximums authorized by the CPUC for the respective project.

The CEC, which continues under the new RPS law to have responsibility for certifying the eligibility of renewable resources and verifying LSE compliance with the RPS program, has also initiated a proceeding to implement the new RPS law and expects to issue a draft regulation addressing certain implementation issues by the end of 2011.

Water Quality

Section 316(b) of the federal Clean Water Act requires that cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, reflect the best technology available to minimize adverse environmental impacts. On April 20, 2011, the U.S. Environmental Protection Agency (“EPA”) published draft regulations that propose specific reductions for impingement (which occurs when larger organisms are caught on water filter screens) and provide a case-by-case site specific assessment to establish compliance requirements for entrainment (which occurs when organisms are drawn through the cooling water system). The proposed site specific assessment allows for the consideration of a variety of factors including social costs and benefits, energy reliability, land availability, and non-water quality adverse impacts. The draft regulations are subject to public comment and final regulations are not expected until July 2012.

The California Water Resources Control Board (“Control Board”) also has adopted a policy on once-through cooling. The policy, effective October 1, 2010, generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities by at least 85%. However, with respect to the state’s nuclear power generation facilities, the policy allows other compliance measures to be taken if the costs to install cooling towers are “wholly out of proportion” to the costs considered by the Control Board in developing its policy or if the installation of cooling towers would be “wholly unreasonable” after considering non-cost factors such as engineering and permitting constraints and adverse environmental impacts. The Utility believes that the costs to install cooling towers at Diablo Canyon, which could be as much as $4.5 billion, will meet the “wholly out of proportion” test. The Utility also believes that the installation of cooling towers at Diablo Canyon would be “wholly unreasonable.” If the Control Board disagreed and if the installation of cooling towers at Diablo Canyon were not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge. Assuming the Control Board does not require the installation of cooling towers at Diablo Canyon, the Utility could incur significant costs to comply with alternative compliance measures or to make payments to support various environmental mitigation projects. The Utility would seek to recover such costs in rates. The Utility’s Diablo Canyon operations must be in compliance with the Control Board’s policy by December 31, 2024.

Remediation

The Utility has been, and may be, required to pay for environmental remediation costs at sites where it is identified as a potentially responsible party under federal and state environmental laws. These sites include former manufactured gas plant (“MGP”) sites, current and former power plant sites, former gas gathering and gas storage sites, sites where natural gas compressor stations are located, current and former substations, service center and general construction yard sites, and sites currently and formerly used by the Utility for the storage, recycling, or disposal of hazardous substances. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site.

Hinkley Natural Gas Compressor Site

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor station located near Hinkley, California. The Utility is also required to take measures to abate the effects of the contamination on the environment. The Utility’s remediation and abatement efforts are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region (“Water Board”). The Utility has been working with the Water Board for several years to implement interim remedial measures to

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both reduce the mass of the underground plume of hexavalent chromium and to monitor and control movement of the plume. In addition, the Utility has been providing bottled water to affected residents as part of the Utility’s abatement efforts.

In August 2010, the Utility filed a comprehensive feasibility study with the Water Board that included an evaluation of possible alternatives for a final groundwater remediation plan. The Utility filed several addendums to its feasibility study based on additional analyses of remediation alternatives and correspondence with the Water Board. The Utility’s recommended alternative for a final remediation plan was submitted to the Water Board in September 2011 and involves a combination of using pumped groundwater from extraction wells to irrigate agricultural land and in-situ remediation. The Water Board stated that it anticipates it will consider certification of the final EIR, which will include the final approved remediation plan, in July 2012. The Water Board has indicated that it anticipates releasing a preliminary draft of the EIR for discussion in late 2011.

Additionally, on October 11, 2011, the Water Board issued an amended cleanup and abatement order (“CAO”) to require the Utility to provide an interim and permanent replacement water system for certain properties located near the underground plume of hexavalent chromium. The CAO requires the Utility to propose a method to perform an initial and quarterly evaluation of wells in the affected area to determine if detectable levels of hexavalent chromium that are lower than the background level but higher than the new public health goal, represent background conditions, or are more likely than not, partially or completely caused by the Utility’s discharge of waste. On October 25, 2011, the Utility filed a petition with the Control Board and requested that the Control Board determine that the Utility is not required to comply with these provisions of the CAO, in part, because the Utility believes that it is not feasible to implement the ordered actions and that the ordered actions are not supported by California law.

For the three and nine months ended September 30, 2011, the Utility increased its provision for environmental remediation liabilities associated with the Hinkley site by $106 million and $132 million, respectively. The increase resulted primarily from changes in costs estimates and assumptions associated with the above developments. As of September 30, 2011 and December 31, 2010, $150 million and $45 million, respectively, were accrued in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets for estimated undiscounted future costs for environmental remediation. Actual costs will depend on many factors, including the certification of a final remediation plan, the extent of the groundwater chromium plume, the levels of hexavalent chromium used as the standard for remediation, and the scope of requirements to provide a permanent water replacement system to affected residents. The Utility is unable to recover remediation costs for the Hinkley site through customer rates. As a result, future increases to the Utility’s provision for its remediation liability will impact PG&E Corporation’s and the Utility’s financial results.

(See Note 10 of the Notes to the Condensed Consolidated Financial Statements for a discussion of estimated environmental remediation liabilities and Legal Proceedings of Part II, Item 1 for discussion of related proceedings.)

LEGAL MATTERS

In addition to the provision made for claims related to the San Bruno accident and the Rancho Cordova accident, PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements also include provisions for claims and lawsuits that have arisen in the ordinary course of business, regulatory proceedings, and other legal matters. See “Legal and Regulatory Contingencies” in Note 10 of the Notes to the Condensed Consolidated Financial Statements.

RISK MANAGEMENT ACTIVITIES

The Utility and PG&E Corporation, mainly through its ownership of the Utility, are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. PG&E Corporation and the Utility face market risk associated with their operations; their financing arrangements; the marketplace for electricity, natural gas, electric transmission, natural gas transportation, and storage; other goods and services; and other aspects of their businesses. PG&E Corporation and the Utility categorize market risks as “price risk” and “interest rate risk.” The Utility is also exposed to “credit risk,” the risk that counterparties fail to perform their contractual obligations.

The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes. The Utility’s risk management activities include the use of energy and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases.

On July 21, 2010, President Obama signed into law new federal financial reform legislation, the Dodd-Frank Wall Street Reform and Consumer Protection Act. PG&E Corporation and the Utility are evaluating the new legislation, and will

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review future regulations to assess compliance requirements as well as potential impacts on the Utility’s procurement activities and risk management programs.

Price Risk

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities, including the procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers. As long as the Utility can conclude that it is probable that its reasonably incurred wholesale electricity procurement costs and natural gas costs are recoverable, fluctuations in electricity and natural gas prices will not affect earnings but may impact cash flows. The Utility’s natural gas transportation and storage costs for core customers are also fully recoverable through a ratemaking mechanism.

The Utility’s natural gas transportation and storage costs for non-core customers may not be fully recoverable. The Utility is subject to price and volumetric risk for the portion of intrastate natural gas transportation and storage capacity that has not been sold under long-term contracts providing for the recovery of all fixed costs through the collection of fixed reservation charges. The Utility sells most of its capacity based on the volume of gas that the Utility’s customers actually ship, which exposes the Utility to volumetric risk.

The Utility uses value-at-risk to measure its shareholders’ exposure to price and volumetric risks resulting from variability in the price of, and demand for, natural gas transportation and storage services that could impact revenues due to changes in market prices and customer demand. Value-at-risk measures this exposure over a rolling 12-month forward period and assumes that the contract positions are held through expiration. This calculation is based on a 95% confidence level, which means that there is a 5% probability that the impact to revenues on a pre-tax basis, over the rolling 12-month forward period, will be at least as large as the reported value-at-risk. Value-at-risk uses market data to quantify the Utility’s price exposure. When market data is not available, the Utility uses historical data or market proxies to extrapolate the required market data. Value-at-risk as a measure of portfolio risk has several limitations, including, but not limited to, inadequate indication of the exposure to extreme price movements and the use of historical data or market proxies that may not adequately capture portfolio risk.

The Utility’s value-at-risk calculated under the methodology described above was approximately $7 million at September 30, 2011. The Utility’s approximate high, low, and average values-at-risk during the 12 months ended September 30, 2011 were $15 million, $7 million, and $10 million, respectively. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements for further discussion of price risk management activities.)

Interest Rate Risk

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At September 30, 2011, if interest rates changed by 1% for all current PG&E Corporation and Utility variable rate and short-term debt and investments, the change would affect net income for the next 12 months by $11 million, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

Credit Risk

The Utility conducts business with counterparties mainly in the energy industry, including other California investor-owned electric utilities, municipal utilities, energy trading companies, financial institutions, and oil and natural gas production companies located in the United States and Canada. If a counterparty fails to perform on its contractual obligation to deliver electricity or gas, then the Utility may find it necessary to procure electricity or gas at current market prices, which may be higher than the contract prices.

The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored periodically. The Utility ties many energy contracts to master commodity enabling agreements that may require security (referred to as “Credit Collateral” in the table below). Credit Collateral may be in the form of cash or letters of credit. The Utility may accept other forms of performance assurance in the form of corporate guarantees of acceptable credit quality or other eligible securities (as deemed appropriate by the Utility). Credit Collateral or performance assurance may be required from counterparties when current net receivables and replacement cost exposure exceed contractually specified limits.

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The following table summarizes the Utility’s net credit risk exposure to its counterparties, as well as the Utility’s credit risk exposure to counterparties accounting for greater than 10% net credit exposure, as of September 30, 2011 and December 31, 2010:

(in millions)	Gross Credit     Exposure Before Credit Collateral (1)		Credit   Collateral		Net Credit   Exposure (2)		Number of Wholesale Customers or   Counterparties   >10%		Net Credit Exposure to Wholesale Customers or   Counterparties   >10%
September 30, 2011		$  213		$  12		$  201		2		$  156
December 31, 2010		269		17		252		2		187

⁽¹⁾ Gross credit exposure equals mark-to-market value on physically and financially settled contracts, notes receivable, and net receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value or liquidity.

⁽²⁾ Net credit exposure is the Gross Credit Exposure Before Credit Collateral minus Credit Collateral (cash deposits and letters of credit). For purposes of this table, parental guarantees are not included as part of the calculation.

CRITICAL ACCOUNTING POLICIES

The preparation of Condensed Consolidated Financial Statements in accordance with U.S. generally accepted accounting principles involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ materially from these estimates and assumptions. PG&E Corporation and the Utility consider their accounting policies for regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal matters, asset retirement obligations, and pension plan and other postretirement plan obligations, to be critical accounting policies, due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. These policies and their key characteristics are discussed in detail in the 2010 Annual Report. In addition, management has made significant estimates and assumptions about accruals related to the San Bruno accident. (See Note 10 to the Condensed Consolidated Financial Statements.)

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

See Note 2 of the Notes to the Condensed Consolidated Financial Statements.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PG&E Corporation’s and the Utility’s primary market risk results from changes in energy prices. PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates (See the section above entitled “Risk Management Activities” in Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A).)

ITEM 4. CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of September 30, 2011, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities Exchange Act of 1934 (“1934 Act”) is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the 1934 Act is accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal control over financial reporting that occurred during the quarter ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In addition to the following legal proceedings, PG&E Corporation and the Utility are involved in various legal proceedings in the ordinary course of their business. For more information regarding PG&E Corporation’s and the Utility’s liability for legal and regulatory contingencies, see Note 10 of the Notes to the Condensed Consolidated Financial Statements, which discussion is incorporated into this Item 1 by reference.

Diablo Canyon Power Plant

On April 20, 2011, the EPA published draft regulations under Section 316(b) of the Clean Water Act, which requires that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. Final regulations are expected to be issued in mid-2012, and could affect future negotiations between the Central Coast Regional Water Quality Control Board (“Central Coast Board”) and the Utility regarding the status of the 2003 settlement agreement concerning a proposed draft Cease and Desist Order issued by the Central Coast Board against the Utility. For more information about the proposed settlement agreement and federal and state water quality regulations affecting Diablo Canyon, see the 2010 Annual Report.

PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material impact on the Utility’s financial condition or results of operations.

Hinkley Natural Gas Compressor Station

As previously disclosed, groundwater at the Utility’s Hinkley natural gas compressor station contains hexavalent chromium as a result of the Utility’s past operating practices. At the Hinkley site, the Utility is cooperating with the regional Water Board to evaluate and remediate the chromium groundwater plume. Measures have been implemented to control movement of the plume, while full-scale on-site treatment systems operate to reduce the mass of the plume. An evaluation of the performance of these interim remedy measures, as well as possible future measures, is underway as part of the development of a final remediation plan. In March 2011, the Water Board advised the Utility that it is considering assessing administrative penalties of up to $5,000 per day due to the Utility’s alleged violation of an administrative order issued in 2008 requiring the Utility to control the spread of the chromium groundwater plume beyond boundaries described in the order. The Utility does not believe it is in violation of the order.

For more information about the Utility’s remediation activities at the Hinkley site, see the section of MD&A entitled “Environmental Matters” above and Note 10 of the Notes to the Condensed Consolidated Financial Statements above.

San Bruno Accident

Litigation Related to the San Bruno Accident

Approximately 100 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, have been filed against PG&E Corporation and the Utility on behalf of approximately 370 plaintiffs. The lawsuits seek compensation for these third-party claims and other relief, including punitive damages. Another lawsuit was filed in San Mateo County Superior Court as a purported shareholder derivative lawsuit to seek recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims. All of these cases have been coordinated and assigned to one judge in the San Mateo County Superior Court. On October 6, 2011, the judge overseeing the consolidated San Bruno litigation set a trial date of July 23, 2012 for the first of the personal injury and property damage cases. The court left open for future hearings which cases will be tried first. The judge has ordered that proceedings in the derivative lawsuit be delayed until further order of the court.

Criminal Investigation Regarding the San Bruno Accident

On June 9, 2011, the Utility was notified that representatives from the U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo County District Attorney’s Office, are conducting an investigation of the San Bruno accident. The Utility is fully cooperating with the investigation. The investigation is in the early stages and PG&E Corporation and the Utility are unable to estimate a possible loss or range of loss associated with any criminal fines or penalties that may be imposed on the Utility.

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For more information regarding the San Bruno accident and the related NTSB and CPUC investigations, see the section of MD&A entitled “Natural Gas Pipeline Matters” above and Note 10 of the Notes to the Condensed Consolidated Financial Statements above.

CPUC Investigation Regarding Substation Construction Permit

On June 10, 2011, the CPUC issued an order to investigate whether the Utility failed to comply with the CPUC’s November 9, 2009 decision granting the Utility’s request for a permit to construct a substation when the Utility removed an almond tree orchard to prepare the site for construction. It is alleged that the Utility (1) failed to notify the CPUC’s Energy Division before the orchard removal began, (2) failed to utilize a qualified biologist expert to provide environmental awareness training to Utility employees and contractor personnel, and (3) sent completed biological surveys to environmental agencies 10 days before orchard removal began instead of the required minimum of 14 days. The Utility believes it was not required to provide notice and that it complied with the environmental training requirements. The Utility’s biological surveys documented that there were no protected species that could be harmed by the orchard removal. To the extent a technical violation occurred when the Utility began orchard removal 10 days, rather than 14 days, after it sent the completed biological surveys to environmental agencies, the Utility believes it was a minor violation. In September 2011, the Utility entered into a settlement with the CPSD under which the Utility will pay $100,000 in penalties and will contribute $50,000 to an environmental group. The Utility and the CPSC have filed a joint motion seeking CPUC approval of the settlement. If the settlement is not approved, and if the CPUC determines that the Utility violated applicable requirements, the CPUC could impose penalties on the Utility of up to $20,000 per day, per violation. PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material impact on the Utility’s financial condition or results of operations.

ITEM 1A. RISK FACTORS

The risk factors appearing in the 2010 Annual Report under the headings set forth below are supplemented and updated as follows:

The ultimate amount of unrecoverable costs, penalties, and third–party liability the Utility incurs in connection with the San Bruno accident, the Rancho Cordova accident, and its natural gas operations has, and may continue to have, a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

Following the San Bruno accident on September 9, 2010, various regulatory proceedings, investigations, and civil lawsuits were commenced, as discussed in the 2010 Annual Report and above under the section of MD&A entitled “Natural Gas Pipeline Matters.” On August 30, 2011, the NTSB determined that the probable cause of the San Bruno accident was the Utility’s inadequate quality assurance and quality control in 1956 when the defective pipe section was installed and an inadequate pipeline integrity management program that failed to detect and repair or remove the defective pipe section. On the same date, the CPUC issued a press release stating that the results of its staff investigation into possible wrongdoing that led to the San Bruno accident could lead to significant fines and other sanctions. Any fines or penalties imposed on the Utility will not be recoverable from customers. On October 6, 2011, the judge in San Mateo County Superior Court overseeing the civil litigation related to the San Bruno accident set a trial date of July 23, 2012 for the first of the personal injury and property damage cases. During the quarter ended September 30, 2011, the Utility recorded an increase of $96 million to its accrual for third-party claims related to the San Bruno accident for a total cumulative provision of $375 through September 30, 2011. The Utility may make additional adjustments to its accrual which could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows. PG&E Corporation and the Utility are unable to estimate a possible loss or range of loss associated with any civil or criminal fines, penalties, or punitive damages that the Utility could be required to pay. If the Utility were required to pay a material amount, PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows would be materially affected.

The Utility will continue to incur costs for pipeline-related activities, including costs associated with the related regulatory proceedings and investigations, which it will not seek to recover from customers. In addition, actual costs could be materially higher than forecasts. Further, although the Utility has requested that the CPUC allow the Utility to recover costs it incurs in 2012 through 2014 under the Utility’s proposed natural gas transmission pipeline safety enhancement plan (with limited exceptions), it is uncertain what portion of the costs will ultimately be recovered. The ultimate amount of unrecoverable costs that shareholders may bear will depend on various factors, including when and whether the CPUC allows the Utility to recover plan-related costs incurred before the CPUC issues a final decision, when and whether the CPUC issues a final decision on the Utility’s proposed plan and cost allocation and ratemaking mechanisms, the scope and timing of the work to be performed under the plan as approved by the CPUC, and whether additional costs are incurred to comply with regulatory and legislative requirements. The Utility also may incur third-party liability related to service disruptions caused by changes in pressure on its natural gas transmission pipelines as work is performed under the plan. If the CPUC does not allow the Utility to recover a material portion of the pipeline-related costs for which the Utility has sought or intends to seek

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to recover through rates, PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows could be materially affected.

During the quarter ended September 30, 2011, the Utility continued to provide extensive financial and other information to an independent consulting firm that has been engaged by the CPUC to conduct an audit of costs incurred by the Utility since 1996 relating to its natural gas transmission pipeline operations. The Utility is uncertain when the results of the audit will be released and what action the CPUC may take in response to the audit. The Utility also is uncertain whether the CPUC will take action with respect to the Utility’s June 30, 2011 report showing that some of the class location designations used to determine a pipeline’s MAOP under federal and state regulations indicated that some pipelines had an MAOP higher than appropriate for their current class location designations.

Further, several natural gas incidents that have recently occurred involve cracking in some of the Utility’s older natural gas distribution lines that are composed of plastic pipe. On August 31, 2011, a natural gas leak involving a cracked plastic pipe ignited a fire that damaged a condominium in Cupertino, California and on September 27, 2011 a natural gas leak involving a cracked plastic pipe buried underneath an intersection in Roseville, California ignited a fire that burned for several hours. The Utility has stated that it intends to replace over 1,200 miles of its natural gas distribution pipelines that are composed of this plastic pipe. Although the timing and estimated cost of replacement has not yet been determined, the Utility expects that it will take several years and that the cost will be material. It is unknown whether any regulatory action will be taken with respect to the use or replacement of this plastic pipe, the Utility’s natural gas distribution integrity management program, or some other aspect of the Utility’s natural gas distribution operations. If the CPUC does not authorize the Utility to fully recover from customers the costs incurred to replace plastic pipe, PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows could be materially affected depending on the timing of the replacement and actual costs incurred.

In addition, the Utility has agreed to pay a $38 million penalty associated with the proposed resolution of the CPUC’s investigation of the Rancho Cordova accident within twenty days after CPUC approval of the proposed resolution. Any penalty paid by the Utility will not be recoverable through rates. If the CPUC does not approve the proposed resolution, the investigation will continue and the Utility could ultimately incur a higher penalty that could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

If the CPUC determines that the Utility violated applicable rules and regulations in connection with the San Bruno accident, its gas system recordkeeping, or other natural gas transmission or distribution matters, the CPUC may impose penalties on the Utility. The CPUC is authorized by state law to impose penalties of up to $20,000 per day per violation. On January 1, 2012, the amount of potential penalties the CPUC may impose will increase to $50,000 per day per violation, although the Utility expects that this statutory amendment will only apply prospectively. If the CPUC imposed a material amount of fines or penalties, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows would be materially affected.

If the Utility cannot timely meet the applicable resource adequacy or renewable energy requirements, the Utility may be subject to penalties. Further, the CPUC may disallow costs incurred by the Utility under power purchase agreements it enters into to meet applicable resource adequacy and renewable energy requirements if the CPUC finds that the costs are unreasonably above-market in the future.

On April 12, 2011, the California Governor signed new legislation that increases the amount of renewable energy that retail sellers of electricity, such as the Utility, must deliver to their customers from at least 20% of their total retail sales by the end of 2010, as required by the prior law, to 33% of their total retail sales by the end of 2020. (See MD&A “Environmental Matters – Renewable Energy Resources” above.) In May 2011, the CPUC established a rulemaking proceeding to develop and adopt regulations to implement the new law. It is uncertain how the CPUC’s regulations and decisions issued pursuant to the former 20% renewable portfolio standard (“RPS”) statute will apply to the new RPS requirements, including whether the CPUC will continue to limit penalties for noncompliance to $25 million per year as had applied under the prior RPS regulatory program.

The Utility’s operations are subject to extensive environmental laws, including new state cap and trade regulations, and changes in or liabilities under these laws could adversely affect its financial condition and results of operations.

The Utility’s operations are subject to extensive federal, state, and local environmental laws and permits. Complying with these environmental laws has, in the past, required significant expenditures for environmental compliance, monitoring, and pollution control equipment, as well as for related fees and permits. The Utility has increased its provision for the undiscounted future costs it could incur for remediation and abatement activities at the Hinkley natural gas compressor site by $106 million, for a total provision of $150 million at September 30, 2011, reflecting recent regulatory actions, additional information on the range of alternative remedial measures, and the costs to comply with increasing

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regulatory requirements. Actual costs will depend on many factors, including the extent of the groundwater chromium plume, the levels of hexavalent chromium used as the standard for remediation, and the scope of the requirement to provide a permanent water replacement system for affected residents. The Utility is unable to recover remediation costs for the Hinkley site through customer rates. As a result, future increases to the Utility’s provision for its remediation liability at the Hinkley site will negatively impact PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flow. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements for a discussion of estimated environmental remediation liabilities and Legal Proceedings of Part II, Item 1 for discussion of related proceedings.)

On October 20, 2011, the CARB approved its final cap and trade regulations to help achieve the gradual reduction of GHG emissions in California as required by California law. The cap-and-trade regulations are expected to become effective on January 1, 2012, but the cap-and–trade program will be implemented on a delayed basis by requiring compliance with the initial emissions cap beginning on January 1, 2013 instead of January 1, 2012. (See MD&A “Environmental Matters – Climate Change” above for more information.)

The operation and decommissioning of the Utility’s nuclear power plants expose it to potentially significant liabilities and capital expenditures that it may not be able to recover from its insurance or other sources, adversely affecting its financial condition, results of operations, and cash flow.

As a result of the earthquake and tsunami that occurred in Japan that seriously damaged nuclear generation facilities, there has been increased legislative, regulatory, and public scrutiny of the safety of nuclear power plants in the United States. The NRC appointed a task force to develop recommendations about how to improve safety at U.S. nuclear power plants and upgrade protection against earthquakes, floods and power losses. The NRC is expected to propose additional regulations or issue orders requiring nuclear power plants to implement some of the recommendations within the next year.

There also has been increased public concern expressed about the safety of the Utility’s Diablo Canyon nuclear generation facilities. On October 24, 2011, the NRC ruled that a contention raised by parties that have opposed the Utility’s relicensing application should be considered. This contention argues that the environmental report submitted by the Utility in November 2009 in support of its renewal application was inadequate because it did not include an analysis of the Shoreline Fault. Additional seismological analyses the Utility performed in 2010 did not change the overall results of the Utility’s severe accident mitigation alternative analysis that had originally been submitted with the renewal application. The NRC will address this contention after the Utility completes other seismological studies. It is uncertain how the NRC will resolve this contention. (See MD&A “Regulatory Matters – Diablo Canyon Nuclear Power Plant.”) PG&E Corporation and the Utility are unable to predict when and whether the NRC will approve the license renewal application.

PG&E Corporation and the Utility also are uncertain when and whether the CPUC will authorize the Utility to recover its estimated costs to renew the operating license ($85 million) and complete the additional seismological studies ($47 million). The costs to complete the seismological studies could increase, depending on environmental permitting processes and required environmental mitigation.

Finally, in early August 2011, the NRC found that a report submitted by the Utility on January 7, 2011 to provide updated seismological information did not conform to the requirements of the current Diablo Canyon operating license. On October 21, 2011, the Utility filed a request that the NRC amend the operating license to address this issue. If the NRC does not approve the request, the Utility could be required to perform additional analyses of Diablo Canyon’s seismic design which could indicate that modifications to Diablo Canyon would be required to address seismic design issues. The NRC could order the Utility to cease its nuclear operations until the modifications were made or the Utility could voluntarily cease operations if it determined that the modifications were not economical or feasible.

In addition to the estimated future costs discussed above that the Utility has sought to recover through rates, the Utility may be required to incur additional costs to comply with any new seismic safety or design requirements, backup power requirements, or other requirements that the NRC may impose based on the task force recommendations, following the submission of the completed seismic studies for Diablo Canyon, or in connection with the requested license amendment. In addition, the Utility may incur significant additional expenses to comply with more stringent laws or regulations that may be adopted by the NRC regarding the storage, handling, security, and disposal of radioactive materials, including spent nuclear fuel. If the Utility were unable to recover the costs it incurs in connection with these matters, PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows could be materially affected. Alternatively, if the Utility determines that it cannot comply with new requirements the NRC may impose in connection with the license renewal application or the requested license amendment, or that it cannot comply with new legislation, orders, rules or regulations that may be adopted in a feasible and economic manner, the Utility may voluntarily cease operations at Diablo Canyon. Further, the NRC could deny the license renewal application requiring nuclear operations to cease when the current licenses expire, the NRC could order the Utility to cease operations until any required modifications were made, or the NRC could order the Utility to cease operations permanently if the NRC determined that the Utility could not comply with such new

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requirements. If the Utility were to cease operations at Diablo Canyon, PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows could be materially affected.

The Utility is subject to penalties for failure to comply with federal, state, or local statutes and regulations. Changes in the political and regulatory environment could cause federal and state statutes, regulations, rules, and orders to become more stringent and difficult to comply with, and required permits, authorizations, and licenses may be more difficult to obtain, increasing the Utility’s expenses or making it more difficult for the Utility to execute its business strategy.

The Utility must comply in good faith with all applicable statutes, regulations, rules, tariffs, and orders of the CPUC, the FERC, the NRC, and other regulatory agencies relating to the aspects of its electricity and natural gas utility operations that fall within the jurisdictional authority of such agencies. These include customer billing, customer service, affiliate transactions, vegetation management, operating and maintenance practices, and safety and inspection practices. The Utility is subject to fines, penalties, and sanctions for failure to comply with applicable statutes, regulations, rules, tariffs, and orders. The CPUC has authority to impose penalties of up to $20,000 per day, per violation. In October 2011, the California Governor signed legislation that will increase the maximum penalty to $50,000 per day, per violation, effective January 1, 2012. Under the Energy Policy Act of 2005, the FERC can impose penalties (up to $1 million per day per violation) for failure to comply with mandatory electric reliability standards, including standards to protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches.

On September 30, 2011, the CPUC released a draft resolution that would delegate authority to the CPSD staff (and other staff as may be directed by the CPUC’s Executive Director) to levy citations and impose fines to enforce compliance with certain state and federal regulations related to the safety of natural gas facilities and utilities’ natural gas operating practices. The proposed resolution states that any citation issued by the staff must assess the maximum penalty that could be imposed by the CPUC under state law. (For a discussion of pending investigations and enforcement proceedings, see MD&A “Natural Gas Pipeline Matters” above.) If the Utility were ordered to pay a material amount of penalties or fines, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flow would be materially adversely affected.

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ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

During the quarter ended September 30, 2011, PG&E Corporation made equity contributions totaling $95 million to the Utility in order to maintain the 52% common equity component of its CPUC-authorized capital structure and to ensure that the Utility has adequate capital to fund its capital expenditures. Neither PG&E Corporation nor the Utility made any sales of unregistered equity securities during the quarter ended September 30, 2011.

Issuer Purchases of Equity Securities

During the quarter ended September 30, 2011, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the quarter ended September 30, 2011, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

ITEM 5. OTHER INFORMATION

Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends

The Utility’s earnings to fixed charges ratio for the nine months ended September 30, 2011 was 2.72. The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the nine months ended September 30, 2011 was 2.68. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and Exhibits into the Utility’s Registration Statement Nos. 33-62488 and 333-172394 relating to various series of the Utility’s first preferred stock and its senior notes, respectively.

PG&E Corporation’s earnings to fixed charges ratio for the nine months ended September 30, 2011 was 2.62. The statement of the foregoing ratio, together with the statement of the computation of the foregoing ratio filed as Exhibit 12.3 hereto, is included herein for the purpose of incorporating such information and Exhibit into PG&E Corporation’s Registration Statement No. 333-172393 relating to its senior notes.

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ITEM 6. EXHIBITS

3	Amended Bylaws of PG&E Corporation effective September 13, 2011
4.1	Fourteenth Supplemental Indenture dated as of September 12, 2011, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due September 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 12, 2011 (File No. 1-2348), Exhibit 4.1)
*10.1	Letter regarding Compensation Agreement between PG&E Corporation and Anthony F. Earley, Jr. dated August 8, 2011
*10.2	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011
*10.3	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011
*10.4	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011
*10.5	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011
*10.6	Separation Agreement between PG&E Corporation and Rand S. Rosenberg dated October 31, 2011
12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation
31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
**32.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
**32.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

* Management contract or compensatory agreement.

** Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this Quarterly Report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized.

PG&E CORPORATION

KENT M. HARVEY

Kent M. Harvey

Senior Vice President and Chief Financial Officer

(duly authorized officer and principal financial officer)

PACIFIC GAS AND ELECTRIC COMPANY

DINYAR B. MISTRY

Dinyar B. Mistry

Vice President, Controller and Chief Financial Officer

(duly authorized officer and principal financial officer)

Dated:  November 3, 2011

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EXHIBIT INDEX

3	Amended Bylaws of PG&E Corporation effective September 13, 2011
4.1	Fourteenth Supplemental Indenture dated as of September 12, 2011, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due September 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 12, 2011 (File No. 1-2348), Exhibit 4.1)
*10.1	Letter regarding Compensation Agreement between PG&E Corporation and Anthony F. Earley, Jr. dated August 8, 2011
*10.2	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011
*10.3	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011
*10.4	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011
*10.5	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011
*10.6	Separation Agreement between PG&E Corporation and Rand S. Rosenberg dated October 31, 2011
12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation
31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
**32.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
**32.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

* Management contract or compensatory agreement.

** Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

77