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 June 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 July 25, 2011:

PG&E Corporation	402,245,202
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 JUNE 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	58
	Environmental Matters	62
	Legal Matters	63
	Risk Management Activities	63
	Critical Accounting Policies	65
	Accounting Standards Issued But Not Yet Adopted	65
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	66
ITEM 4.	CONTROLS AND PROCEDURES	66
PART II.	OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	67
ITEM 1A.	RISK FACTORS	68
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	71
ITEM 5.	OTHER INFORMATION	71
ITEM 6.	EXHIBITS	72
SIGNATURES		74

1

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

		000000000000		000000000000		000000000000		000000000000
	(Unaudited)
	Three Months Ended June  30,				Six Months Ended June  30,
(in millions, except per share amounts)	2011		2010		2011		2010
Operating Revenues
Electric		$ 2,889		$ 2,515		$ 5,506		$ 5,025
Natural gas		795		717		1,775		1,682
Total operating revenues		3,684		3,232		7,281		6,707
Operating Expenses
Cost of electricity		906		863		1,794		1,783
Cost of natural gas		258		247		766		742
Operating and maintenance		1,237		959		2,463		1,950
Depreciation, amortization, and decommissioning		591		468		1,082		919
Total operating expenses		2,992		2,537		6,105		5,394
Operating Income		692		695		1,176		1,313
Interest income		3		2		5		4
Interest expense		(174)		(175)		(351)		(343)
Other income (expense), net		21		2		38		(4)
Income Before Income Taxes		542		524		868		970
Income tax provision		176		187		300		372
Net Income		366		337		568		598
Preferred stock dividend requirement of subsidiary		4		4		7		7
Income Available for Common Shareholders		$ 362		$ 333		$ 561		$ 591
Weighted Average Common Shares Outstanding, Basic		399		373		397		372
Weighted Average Common Shares Outstanding, Diluted		400		390		399		389
Net Earnings Per Common Share, Basic		$ 0.91		$ 0.88		$ 1.41		$ 1.56
Net Earnings Per Common Share, Diluted		$ 0.91		$ 0.86		$ 1.41		$ 1.54
Dividends Declared Per Common Share	$	0.46	$	0.46	$	0.91	$	0.91

See accompanying Notes to the Condensed Consolidated Financial Statements.

2

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

		000000000000000		000000000000000
	(Unaudited)
	Balance At
(in millions)	June 30, 2011		December 31, 2010
ASSETS
Current Assets
Cash and cash equivalents		$ 350		$ 291
Restricted cash ($35 and $38 related to energy recovery bonds at June 30, 2011 and December 31, 2010, respectively)		367		563
Accounts receivable
Customers (net of allowance for doubtful accounts of $79 and $81 at June 30, 2011 and December 31, 2010, respectively)		894		944
Accrued unbilled revenue		691		649
Regulatory balancing accounts		1,490		1,105
Other		864		794
Regulatory assets		644		599
Inventories
Gas stored underground and fuel oil		143		152
Materials and supplies		213		205
Income taxes receivable		175		47
Other		291		193
Total current assets		6,122		5,542
Property, Plant, and Equipment
Electric		34,454		33,508
Gas		11,675		11,382
Construction work in progress		1,547		1,384
Other		15		15
Total property, plant, and equipment		47,691		46,289
Accumulated depreciation		(15,564)		(14,840)
Net property, plant, and equipment		32,127		31,449
Other Noncurrent Assets
Regulatory assets ($550 and $735 related to energy recovery bonds at June 30, 2011 and December 31, 2010, respectively)		5,905		5,846
Nuclear decommissioning trusts		2,069		2,009
Income taxes receivable		489		565
Other		606		614
Total other noncurrent assets		9,069		9,034
TOTAL ASSETS		$ 47,318		$ 46,025

See accompanying Notes to the Condensed Consolidated Financial Statements.

3

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

		000000000000000		000000000000000
	(Unaudited)
	Balance At
(in millions, except share amounts)	June 30, 2011		December 31, 2010
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings		$ 1,210		$ 853
Long-term debt, classified as current		50		809
Energy recovery bonds, classified as current		413		404
Accounts payable
Trade creditors		1,103		1,129
Disputed claims and customer refunds		674		745
Regulatory balancing accounts		529		256
Other		426		379
Interest payable		827		862
Income taxes payable		149		77
Deferred income taxes		134		113
Other		1,507		1,558
Total current liabilities		7,022		7,185
Noncurrent Liabilities
Long-term debt		11,466		10,906
Energy recovery bonds		223		423
Regulatory liabilities		4,654		4,525
Pension and other postretirement benefits		2,317		2,234
Asset retirement obligations		1,582		1,586
Deferred income taxes		5,945		5,547
Other		2,068		2,085
Total noncurrent liabilities		28,255		27,306
Commitments and Contingencies (Note 10)
Equity
Shareholders’ Equity
Preferred stock		-		-
Common stock, no par value, authorized 800,000,000 shares, 401,657,362 shares outstanding at June 30, 2011 and 395,227,205 shares outstanding at December 31, 2010		7,171		6,878
Reinvested earnings		4,802		4,606
Accumulated other comprehensive loss		(184)		(202)
Total shareholders’ equity		11,789		11,282
Noncontrolling Interest – Preferred Stock of Subsidiary		252		252
Total equity		12,041		11,534
TOTAL LIABILITIES AND EQUITY		$ 47,318		$ 46,025

See accompanying Notes to the Condensed Consolidated Financial Statements.

4

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

		00000000000		00000000000
	(Unaudited)
	Six Months Ended June 30,
(in millions)	2011		2010
Cash Flows from Operating Activities
Net income		$ 568		$ 598
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,198		1,038
Allowance for equity funds used during construction		(41)		(57)
Deferred income taxes and tax credits, net		397		(3)
Other		22		-
Effect of changes in operating assets and liabilities:
Accounts receivable		(82)		(47)
Inventories		1		(20)
Accounts payable		162		7
Income taxes receivable/payable		66		458
Other current assets and liabilities		(202)		(275)
Regulatory assets, liabilities, and balancing accounts, net		(324)		(263)
Other noncurrent assets and liabilities		140		(63)
Net cash provided by operating activities		1,905		1,373
Cash Flows from Investing Activities
Capital expenditures		(1,897)		(1,786)
Decrease in restricted cash		198		50
Proceeds from sales and maturities of nuclear decommissioning trust investments		1,007		685
Purchases of nuclear decommissioning trust investments		(969)		(696)
Other		(44)		4
Net cash used in investing activities		(1,705)		(1,743)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities		150		30
Repayments under revolving credit facilities		(75)		-
Net issuances of commercial paper, net of discount of $2 in 2011 and $1 in 2010		265		693
Proceeds from issuance of long-term debt, net of discount and issuance costs of $2 in 2011 and $5 in 2010		298		295
Short-term debt matured		-		(500)
Long-term debt matured		(500)		-
Energy recovery bonds matured		(191)		(182)
Common stock issued		257		89
Common stock dividends paid		(349)		(320)
Other		4		3
Net cash provided by (used in) financing activities		(141)		108
Net change in cash and cash equivalents		59		(262)
Cash and cash equivalents at January 1		291		527
Cash and cash equivalents at June 30		$ 350		$ 265
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized		$ (330)		$ (309)
Income taxes, net		8		36
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid		$ 183		$ 178
Capital expenditures financed through accounts payable		229		209
Noncash common stock issuances		12		253

See accompanying Notes to the Condensed Consolidated Financial Statements.

5

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

		000000000000		000000000000		000000000000		000000000000
	(Unaudited)
	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2011		2010		2011		2010
Operating Revenues
Electric		$ 2,888		$ 2,515		$ 5,504		$ 5,025
Natural gas		795		717		1,775		1,682
Total operating revenues		3,683		3,232		7,279		6,707
Operating Expenses
Cost of electricity		906		863		1,794		1,783
Cost of natural gas		258		247		766		742
Operating and maintenance		1,228		958		2,454		1,948
Depreciation, amortization, and decommissioning		592		468		1,082		919
Total operating expenses		2,984		2,536		6,096		5,392
Operating Income		699		696		1,183		1,315
Interest income		2		2		4		4
Interest expense		(169)		(164)		(340)		(320)
Other income (expense), net		16		1		33		(5)
Income Before Income Taxes		548		535		880		994
Income tax provision		189		196		320		391
Net Income		359		339		560		603
Preferred stock dividend requirement		4		4		7		7
Income Available for Common Stock		$ 355		$ 335		$ 553		$ 596

See accompanying Notes to the Condensed Consolidated Financial Statements.

6

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

		0000000000000000000		0000000000000000000
	(Unaudited)
	Balance At
(in millions)	June 30,     2011		December 31,     2010
ASSETS
Current Assets
Cash and cash equivalents		$ 110		$ 51
Restricted cash ($35 and $38 related to energy recovery bonds at June 30, 2011 and December 31, 2010, respectively)		367		563
Accounts receivable
Customers (net of allowance for doubtful accounts of $79 and $81 at June 30, 2011 and December 31, 2010, respectively)		894		944
Accrued unbilled revenue		691		649
Regulatory balancing accounts		1,490		1,105
Other		864		856
Regulatory assets		644		599
Inventories
Gas stored underground and fuel oil		143		152
Materials and supplies		213		205
Income taxes receivable		233		48
Other		285		190
Total current assets		5,934		5,362
Property, Plant, and Equipment
Electric		34,454		33,508
Gas		11,675		11,382
Construction work in progress		1,547		1,384
Total property, plant, and equipment		47,676		46,274
Accumulated depreciation		(15,550)		(14,826)
Net property, plant, and equipment		32,126		31,448
Other Noncurrent Assets
Regulatory assets ($550 and $735 related to energy recovery bonds at June 30, 2011 and December 31, 2010, respectively)		5,905		5,846
Nuclear decommissioning trusts		2,069		2,009
Income taxes receivable		487		614
Other		338		400
Total other noncurrent assets		8,799		8,869
TOTAL ASSETS		$ 46,859		$ 45,679

See accompanying Notes to the Condensed Consolidated Financial Statements.

7

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

		0000000000000000000		0000000000000000000
	(Unaudited)
	Balance At
(in millions, except share amounts)	June 30,     2011		December 31,     2010
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings		$ 1,135		$ 853
Long-term debt, classified as current		50		809
Energy recovery bonds, classified as current		413		404
Accounts payable
Trade creditors		1,103		1,129
Disputed claims and customer refunds		674		745
Regulatory balancing accounts		529		256
Other		434		390
Interest payable		823		857
Income taxes payable		158		116
Deferred income taxes		142		118
Other		1,307		1,349
Total current liabilities		6,768		7,026
Noncurrent Liabilities
Long-term debt		11,117		10,557
Energy recovery bonds		223		423
Regulatory liabilities		4,654		4,525
Pension and other postretirement benefits		2,255		2,174
Asset retirement obligations		1,582		1,586
Deferred income taxes		6,068		5,659
Other		2,003		2,008
Total noncurrent liabilities		27,902		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 June 30, 2011 and December 31, 2010		1,322		1,322
Additional paid-in capital		3,496		3,241
Reinvested earnings		7,290		7,095
Accumulated other comprehensive loss		(177)		(195)
Total shareholders’ equity		12,189		11,721
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$ 46,859		$ 45,679

See accompanying Notes to the Condensed Consolidated Financial Statements.

8

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

		000000000000		000000000000
	(Unaudited)
	Six Months Ended June 30,
(in millions)	2011		2010
Cash Flows from Operating Activities
Net income		$ 560		$ 603
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,175		1,016
Allowance for equity funds used during construction		(41)		(57)
Deferred income taxes and tax credits, net		408		(1)
Other		22		-
Effect of changes in operating assets and liabilities:
Accounts receivable		(1)		(81)
Inventories		1		(20)
Accounts payable		140		4
Income taxes receivable/payable		66		475
Other current assets and liabilities		(186)		(265)
Regulatory assets, liabilities, and balancing accounts, net		(324)		(263)
Other noncurrent assets and liabilities		(114)		(29)
Net cash provided by operating activities		1,934		1,382
Cash Flows from Investing Activities
Capital expenditures		(1,897)		(1,786)
Decrease in restricted cash		198		50
Proceeds from sales and maturities of nuclear decommissioning trust investments		1,007		685
Purchases of nuclear decommissioning trust investments		(969)		(696)
Other		11		11
Net cash used in investing activities		(1,650)		(1,736)
Cash Flows from Financing Activities
Net issuances of commercial paper, net of discount of $2 in 2011 and $1 in 2010		265		693
Proceeds from issuance of long-term debt, net of discount and issuance costs of $2 in 2011 and $5 in 2010		298		295
Short-term debt matured		-		(500)
Long-term debt matured		(500)		-
Energy recovery bonds matured		(191)		(182)
Preferred stock dividends paid		(7)		(7)
Common stock dividends paid		(358)		(358)
Equity contribution		255		130
Other		13		9
Net cash provided by (used in) financing activities		(225)		80
Net change in cash and cash equivalents		59		(274)
Cash and cash equivalents at January 1		51		334
Cash and cash equivalents at June 30		$110		$60
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized		$ (319)		$ (287)
Income taxes, net		6		34
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable		$ 229		$ 209

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 six months ended June 30, 2011 and 2010 were as follows:

	Pension Benefits				Other Benefits
	Three Months Ended June 30,				Three Months Ended June 30,
(in millions)	2011		2010		2011		2010
Service cost for benefits earned		$ 82		$ 69		$ 11		$ 9
Interest cost		164		161		23		23
Expected return on plan assets		(167)		(156)		(20)		(18)
Amortization of transition obligation		-		-		6		6
Amortization of prior service cost		9		13		6		6
Amortization of unrecognized loss		12		11		1		1
Net periodic benefit cost		100		98		27		27
Less: transfer to regulatory account (1)		(36)		(58)		-		-
Total		$ 64		$ 40		$ 27		$ 27

⁽¹⁾ The Utility recorded $36 million and $58 million for the three month periods ended June 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
	Six Months Ended June 30,				Six Months Ended June 30,
(in millions)	2011		2010		2011		2010
Service cost for benefits earned		$ 164		$ 139		$ 22		$ 19
Interest cost		328		322		46		46
Expected return on plan assets		(334)		(312)		(40)		(36)
Amortization of transition obligation		-		-		12		12
Amortization of prior service cost		18		27		12		12
Amortization of unrecognized loss		24		21		2		2
Net periodic benefit cost		200		197		54		55
Less: transfer to regulatory account (1)		(72)		(115)		-		-
Total		$ 128		$ 82		$ 54		$ 55

⁽¹⁾ The Utility recorded $72 million and $115 million for the six month periods ended June 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 six months ended June 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 and 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 June 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 $703 million at June 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 $637 million at June 30, 2011 and consisted of liabilities related to energy recovery bonds, which are included in current and noncurrent liabilities in the

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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 June 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. The majority of these amounts are recorded in other noncurrent assets – other in PG&E Corporation’s Condensed Consolidated Balance Sheets. As of June 30, 2011, PG&E Corporation had made total payments of $251 million under these tax equity agreements and received $99 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 June 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.

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.

The Utility uses regulatory balancing accounts to accumulate differences between actual billed and unbilled revenues and the Utility’s authorized revenue requirements for the period. The Utility also uses regulatory balancing accounts to accumulate differences between incurred costs and actual billed and unbilled revenues, as well as 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 June 30, 2011 and December 31, 2010, the Utility had current regulatory assets of $644 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 June 30, 2011, current regulatory assets included the current portion of the Utility’s undepreciated conventional electromechanical meters regulatory asset, which represents the net book value of electromechanical meters that have been replaced with SmartMeter™ devices, which are being recovered from customers over the next six years.

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

		December 31, 2010		December 31, 2010
	Balance at
(in millions)	June 30, 2011		December 31, 2010
Pension benefits		$ 1,790		$ 1,759
Deferred income taxes		1,333		1,250
Utility retained generation		644		666
Energy recovery bonds		550		735
Environmental compliance costs		462		450
Price risk management		307		424
Undepreciated conventional electromechanical meters		272		-
Unamortized loss, net of gain, on reacquired debt		170		181
Other		377		381
Total long-term regulatory assets		$ 5,905		$ 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 12 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. The Utility expects to fully recover these costs by 2016.

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 June 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; costs incurred in relation to the Utility’s plan of reorganization under Chapter 11 that became effective in April 2004; and removal costs associated with the replacement of conventional electromechanical meters with SmartMeter™ devices.

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 June 30, 2011 and December 31, 2010, the Utility had current regulatory liabilities of $103 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:

		December 31, 2010		December 31, 2010
	Balance at
(in millions)	June 30, 2011		December 31, 2010
Cost of removal obligation		$ 3,344		$ 3,229
Recoveries in excess of ARO		668		600
Public purpose programs		502		573
Other		140		123
Total long-term regulatory liabilities		$ 4,654		$ 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

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programs designed to encourage the manufacture, design, distribution, and customer use of energy 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 June 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

		December 31, 2010		December 31, 2010
	Receivable (Payable)
	Balance at
(in millions)	June 30, 2011		December 31, 2010
Utility generation		$ 460		$ 303
Distribution revenue adjustment mechanism		378		145
Public purpose programs		129		164
Hazardous substance		57		38
Gas fixed cost		(23)		56
Energy recovery bonds		(126)		(34)
Energy procurement		(137)		(25)
Other		223		202
Total regulatory balancing accounts, net	$	961	$	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 independent, or “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 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 clean up costs through the CPUC-approved ratemaking mechanism that authorizes the Utility to recover 90% of hazardous waste remediation costs. The current balance represents eligible remediation costs incurred by the Utility during 2010 that are expected to be recovered through an annual true-up filing with the CPUC in January 2012. (See Note 10 below.)

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

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from the volume of sales. During the colder months of winter there is generally an over-collection in this balancing account due to higher natural gas sales. During the warmer months of summer there is generally an under-collection due to lower natural gas sales.

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 June 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 June 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, as amended by the Amendment and Limited Consent Agreement, dated as of 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, as amended by the Amendment and Limited Consent Agreement, dated as of 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. PG&E Corporation and the Utility have the right to replace any lender who does not agree to an extension under the respective agreements.

The revolving credit facilities will be used primarily for working capital and other corporate purposes, including commercial paper back-up. The revolving credit facilities include sublimits for the issuance of standby and commercial letters of credit of $100 million for PG&E Corporation and $1.0 billion for the Utility. The revolving credit facilities also include commitments for swingline loans (loans that are made available on a same-day basis and are repayable in full within seven days) of $100 million for PG&E Corporation and $300 million for the Utility.

Subject to obtaining commitments from existing or new lenders and satisfaction of other specified conditions, 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 June 30, 2011, PG&E Corporation and the Utility were in compliance with all covenants under each of the revolving credit facilities.

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At June 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 1.37%.

At June 30, 2011, the Utility had no cash borrowings and $319 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 June 30, 2011, the Utility had $870 million of commercial paper outstanding.

Utility

Senior Notes

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

Other Short-term Borrowings

At June 30, 2011, the interest rate on the Utility’s $250 million principal amount of Floating Rate Senior Notes, due October 11, 2011, was 0.87%. The interest rate for the Floating Rate Senior Notes is equal to the three-month LIBOR plus 0.58% and resets quarterly. On July 11, 2011, the interest rate was reset to 0.83%.

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 $636 million at June 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 six months ended June 30, 2011 were as follows:

		Shareholders' Equity		Shareholders' Equity
	PG&E Corporation		Utility
(in millions)	Total Equity		Total   Shareholders’ Equity
Balance at December 31, 2010		$ 11,534		$ 11,721
Net income		568		560
Common stock issued		269		-
Share-based compensation expense		24		-
Common stock dividends declared		(365)		(358)
Preferred stock dividend requirement		-		(7)
Preferred stock dividend requirement of subsidiary		(7)		-
Other comprehensive income		18		18
Equity contribution		-		255
Balance at June 30, 2011		$ 12,041		$ 12,189

For the six months ended June 30, 2011, PG&E Corporation issued 3,853,288 shares of common stock upon the exercise of employee stock options and under its 401(k) plan and Dividend Reinvestment and Stock Purchase Plan.

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 six months ended June 30, 2011, PG&E Corporation issued 2,354,062 shares of common stock under the Equity Distribution Agreement for cash proceeds of $103 million, net of fees and commissions paid of $1 million.

For the six months ended June 30, 2011, PG&E Corporation contributed equity of $255 million to the Utility in order to maintain the 52% common equity ratio authorized by the CPUC and to ensure that the Utility has adequate capital to fund its capital expenditures.

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 six months ended June 30, 2011 and 2010 was as follows:

	PG&E Corporation
	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2011		2010		2011		2010
Net income		$ 366		$ 337		$ 568		$ 598
Employee benefit plan adjustment, net of tax (1)		9		8		18		(72)
Comprehensive Income		$ 375		$ 345		$ 586		$ 526

⁽¹⁾ These balances are net of income tax expense of $6 million for the three months ended June 30, 2011 and 2010, respectively. For the six months ended June 30, 2011 and 2010, the income tax expense was $12 million and the income tax benefit was $49 million, respectively.

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

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NOTE 6: EARNINGS PER SHARE

For the three and six months ended June 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 six months ended June 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 June 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 six months ended June 30, 2011:

	Three Months Ended June  30,				Six Months Ended June  30,
(in millions, except per share amounts)	2011		2010		2011		2010
Basic
Income available for common shareholders		$   362		$ 333		$  561		$ 591
Less: distributed earnings to common shareholders		-		178		-		347
Undistributed earnings		$     -(2)		$ 155		$     -(2)		$ 244
Allocation of undistributed earnings to common shareholders
Distributed earnings to common shareholders		$       -		$ 178		$       -		$ 347
Undistributed earnings allocated to common shareholders		-		149		-		234
Total common shareholders earnings		$     -(2)		$ 327		$   -(2)		$ 581
Weighted average common shares outstanding, basic		399		373		397		372
Convertible subordinated notes		-		15		-		16
Weighted average common shares outstanding and participating securities		399		388		397		388
Net earnings per common share, basic
Distributed earnings, basic (1)		-(2)		$ 0.48		-(2)		$ 0.93
Undistributed earnings, basic		-(2)		0.40		-(2)		0.63
Total		$  0.91		$ 0.88		$ 1.41		$ 1.56

⁽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.

⁽²⁾ EPS for 2011 was calculated by dividing the income available for common shareholders by the weighted average number of common 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 six months ended June 30, 2011:

(in millions, except per share amounts)	Three Months Ended   June 30, 2011		Six Months Ended   June 30, 2011
Diluted
Income available for common shareholders		$  362		$  561
Weighted average common shares outstanding, basic		399		397
Add incremental shares from assumed conversions:
Employee share-based compensation		1		2
Weighted average common shares outstanding, diluted		400		399
Total earnings per common share, diluted		$  0.91		$  1.41

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 six months ended June 30, 2010:

(in millions, except per share amounts)	Three Months Ended   June 30, 2010		Six Months Ended   June 30, 2010
Diluted
Income available for common shareholders		$  333		$  591
Add earnings impact of assumed conversion of participating securities:
Interest expense on convertible subordinated notes, net of tax		4		8
Income available for common shareholders and assumed conversion		$  337		$  599
Weighted average common shares outstanding, basic		373		372
Add incremental shares from assumed conversions:
Convertible subordinated notes		15		16
Employee share-based compensation		2		1
Weighted average common shares outstanding, diluted		390		389
Total earnings per common share, diluted		$  0.86		$  1.54

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.

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.

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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-related price risk-related 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 derivative instruments related to price risk for commodities 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-related 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 obtains electricity from a diverse mix of resources, including third-party power purchase agreements, amounts allocated to the Utility’s customers under power purchase contracts that have been entered into by the California Department of Water Resources (“DWR”), and its own electricity generation facilities. The amount of electricity the Utility needs to procure to meet the demands of customers is subject to change for a number of reasons, including:

_• periodic expirations or terminations of existing electricity purchase contracts, including the DWR’s contracts;

_• the execution of new electricity purchase contracts;

_• the amount of electricity generated by the Utility’s two nuclear generation units at the Diablo Canyon power plant (“Diablo Canyon”) which can be affected by planned and unplanned outages, the availability of nuclear fuel, and regulatory or legislative actions that requires the temporary or permanent curtailment or cessation of nuclear operations;

_• fluctuation in the output of hydroelectric and other renewable energy resource facilities owned or under contract;

_• changes in the Utility’s customers’ electricity demands due to customer and economic growth or decline, weather, implementation of new energy efficiency and demand response programs, direct access, and community choice aggregation;

_• the acquisition, retirement, or closure of generation facilities owned by the Utility or others; and

_• changes in market prices that make it more economical to purchase power in the market rather than use the Utility’s existing or contracted resources to generate power.

The Utility enters into third-party power purchase agreements to ensure sufficient 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 the volatility in customer rates, the Utility has entered into financial swap contracts to effectively fix the price of future purchases and reduce the cash flow variability associated with fluctuating electricity prices under some of those power purchase agreements. 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

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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 the Utility-owned natural gas generating facilities, tolling agreements, and natural gas-indexed electricity procurement contracts. In order to reduce the volatility in customer rates, the Utility purchases financial instruments such as swaps and options to reduce future cash flow variability associated with fluctuating natural gas prices. These financial instruments are considered derivative instruments.

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 June 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		334,357,146		260,860,000		11,140,000		-
	Options		238,196,542		269,857,756		31,200,000		-
Electricity (Megawatt-hours)	Forwards and Swaps		4,918,603		6,089,912		2,914,999		4,316,760
	Options		3,284		64,584		264,348		331,560
	Congestion Revenue Rights		58,509,308		72,571,815		72,649,100		80,367,091

⁽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 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.

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

		Netting (2)		Netting (2)		Netting (2)		Netting (2)
	Gross Derivative     Balance  (1)		Netting (2)		Cash     Collateral (2)		Total Derivative     Balances
(in millions)	Commodity Risk (PG&E Corporation and the Utility)
Current assets – other		56		(41)		204		219
Other noncurrent assets – other		139		(104)		-		35
Current liabilities – other		(367)		41		145		(181)
Noncurrent liabilities – other		(411)		104		29		(278)
Total commodity risk		(583)		-		378		(205)

⁽¹⁾ See Note 8 of the Notes to the Condensed Consolidated Financial Statements for a discussion of the valuation techniques used to calculate the fair
value of these instruments.

⁽²⁾ Positions and cash collateral, by counterparty, are netted where the intent and legal right to offset exist in accordance with master netting agreements.

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

	Gross Derivative     Balance  (1)		Netting (2)		Cash     Collateral (2)		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)

⁽¹⁾ See Note 8 of the Notes to the Condensed Consolidated Financial Statements for a discussion of the valuation techniques used to calculate the fair value of these instruments.

⁽²⁾ Positions and cash collateral, by counterparty, are netted where the intent and legal right to offset exist in accordance with master netting agreements.

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 June 30,				Six months ended June 30,
(in millions)	2011		2010		2011		2010
Unrealized gain/(loss) - regulatory assets and liabilities (1)		$ 21		$ 18		$ 158		$ (271)
Realized gain/(loss) - cost of electricity (2)		(122)		(175)		(258)		(281)
Realized gain/(loss) - cost of natural gas (2)		(6)		(5)		(61)		(44)
Total commodity risk instruments		$ (107)		$ (162)		$ (161)		$ (596)

⁽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 June 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

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post additional cash to fully collateralize its net liability derivative positions.

At June 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	$ (464)
Related derivatives in an asset position	4
Collateral posting in the normal course of business related to these derivatives	12
Net position of derivative contracts/additional collateral posting requirements (1)	$ (448)

⁽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.

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 June 30, 2011										At December 31, 2010
(in millions)	Level 1		Level 2		Level 3		Netting (3)		Total		Level 1		Level 2		Level 3		Netting (3)		Total
Assets:
Money market investments		$ 228		$ -		$ -		$ -		$ 228		$ 138		$ -		$ -		$ -		$ 138
Nuclear decommissioning trusts
U.S. equity securities (1)		863		11		-		-		874		1,029		7		-		-		1,036
Non-U.S. equity securities		365		-		-		-		365		349		-		-		-		349
U.S. government and agency securities		681		145		-		-		826		584		40		-		-		624
Municipal securities		-		103		-		-		103		-		119		-		-		119
Other fixed-income securities		-		101		-		-		101		-		66		-		-		66
Total nuclear decommissioning trusts (2)		1,909		360		-		-		2,269		1,962		232		-		-		2,194
Price risk management instruments (Note 7)
Electric		1		-		184		58		243		6		2		119		63		190
Gas		-		-		10		1		11		-		-		6		5		11
Total price risk management instruments		1		-		194		59		254		6		2		125		68		201
Rabbi trusts
Fixed-income securities		-		25		-		-		25		-		24		-		-		24
Life insurance contracts		-		66		-		-		66		-		65		-		-		65
Total rabbi trusts		-		91		-		-		91		-		89		-		-		89
Long-term disability trust
U.S. equity securities (1)		4		16		-		-		20		11		24		-		-		35
Non-U.S. equity securities		-		12		-		-		12		-		-		-		-		-
Corporate debt securities (1)		-		137		-		-		137		-		150		-		-		150
Total long-term disability trust		4		165		-		-		169		11		174		-		-		185
Total assets		$ 2,142		$ 616		$ 194		$ 59		$ 3,011		$ 2,117		$ 497		$ 125		$ 68		$2,807
Liabilities:
Price risk management instruments (Note 7)
Electric		$ 200		$ 66		$ 468		$ (282)		$ 452		$ 235		$ 73		$ 475		$ (315)		$ 468
Gas		37		1		6		(37)		7		41		1		49		(41)		50
Total liabilities		$237		$ 67		$ 474		$ (319)		$ 459		$ 276		$ 74		$ 524		$ (356)		$ 518

⁽¹⁾  Level 2 balances include commingled funds, which are composed primarily of securities traded publicly on exchanges. Price quotes for the assets held by the funds are readily observable and available.

⁽²⁾  Excludes $200 million and $185 million at June 30, 2011 and December 31, 2010, respectively, primarily related to deferred taxes on appreciation of investment value.

(3) Includes the effect of netting and collateral.

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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 investments primarily include investments in common stock and commingled funds composed of equity securities across multiple industry sectors in the U.S. and other regions of the world. Equity securities are generally valued based on unadjusted prices in active markets for identical transactions and are classified as Level 1.

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 as 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 and 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 when market data is available.

All energy-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 auction prices 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 three and six months ended June 30, 2011.

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Level 3 Reconciliation

The following tables present reconciliations for assets and liabilities measured and recorded at fair value on a recurring basis for PG&E Corporation and the Utility (money market investments and dividend participation rights are held by PG&E Corporation and not the Utility), using significant unobservable inputs (Level 3), for the three months ended June 30, 2011 and 2010, respectively:

		00000000000000000000000000
(in millions)	Price Risk Management               Instruments
Asset (liability) balance as of March 31, 2011		$ (312)
Realized and unrealized gains (losses):
Included in earnings		23
Included in regulatory assets and liabilities or balancing accounts		(82)
Purchases		57
Issuances		-
Sales		-
Settlements		34
Transfers into Level 3		-
Transfers out of Level 3		-
Asset (liability) balance as of June 30, 2011		$ (280)

		000000000000		000000000000		000000000000		000000000000
(in millions)	Dividend Participation Rights		Price Risk Management Instruments		Other Liabilities		Total
Asset (liability) balance as of March 31, 2010		$ (7)		$ (424)		$ (1)		$ (432)
Realized and unrealized gains (losses):
Included in earnings		-		7		-		7
Included in regulatory assets and liabilities or balancing accounts		-		(169)		(1)		(170)
Purchases, issuances, sales and settlements		7		116		-		123
Transfers into Level 3		-		-		-		-
Transfers out of Level 3		-		-		-		-
Asset (liability) balance as of June 30, 2010		$ -		$ (470)		$ (2)		$ (472)

The following tables present the reconciliation for Level 3 assets and liabilities for the six months ended June 30, 2011 and 2010, respectively:

		00000000000000000000000000
(in millions)	Price Risk Management               Instruments
Asset (liability) balance as of December 31, 2010		$ (399)
Realized and unrealized gains (losses):
Included in earnings		15
Included in regulatory assets and liabilities or balancing accounts		(118)
Purchases		99
Issuances		-
Sales		-
Settlements		123
Transfers into Level 3		-
Transfers out of Level 3		-
Asset (liability) balance as of June 30, 2011		$ (280)

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		000000000000		000000000000		000000000000		000000000000		000000000000
(in millions)	Money Market		Dividend Participation Rights		Price Risk Management Instruments		Other Liabilities		Total
Asset (liability) balance as of December 31, 2009		$ 4		$ (12)		$ (250)		$ (3)		$ (261)
Realized and unrealized gains (losses):
Included in earnings		-		-		(36)		-		(36)
Included in regulatory assets and liabilities or balancing accounts		-		-		(392)		1		(391)
Purchases, issuances, sales and settlements		(4)		12		208		-		216
Transfers into Level 3		-		-		-		-		-
Transfers out of Level 3		-		-		-		-		-
Asset (liability) balance as of June 30, 2010		$ -		$ -		$ (470)		$ (2)		$ (472)

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 and 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 June 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 June 30, 2011 and December 31, 2010.

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):

		0000000000		0000000000		0000000000		0000000000
	At June 30, 2011				At December 31, 2010
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Debt (Note 4)
PG&E Corporation		$349		$386		$349		$383
Utility		10,245		11,096		10,444		11,314
Energy recovery bonds (Note 4)		636		665		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.)

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

		00000000000		00000000000		00000000000		00000000000
(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value (1)
As of June 30, 2011
Equity securities
U.S.		$ 322		$ 554		$ (2)		$ 874
Non-U.S.		184		182		(1)		365
Debt securities
U.S. government and agency securities		766		61		(1)		826
Municipal securities		102		2		(1)		103
Other fixed-income securities		100		1		-		101
Total		$ 1,474		$800		$ (5)		$ 2,269
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 $200 million and $185 million at June 30, 2011 and December 31, 2010, respectively, primarily related to deferred taxes on appreciation of investment value.

The debt securities mature on the following schedule:

		00000000000000000000
(in millions)	As of June 30, 2011
Less than 1 year		$ 63
1–5 years		348
5–10 years		278
More than 10 years		341
Total maturities of debt securities		$ 1,030

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

		000000000000		000000000000		000000000000		000000000000
	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
(in millions)
Proceeds from sales and maturities of nuclear decommissioning trust investments		$ 281		$ 348		$ 1,007		$ 685
Gross realized gains on sales of securities held as available-for-sale		9		7		29		22
Gross realized losses on sales of securities held as available-for-sale		(3)		(1)		(6)		(6)

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

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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. At June 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.

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.

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

	00000000000000
(in millions)
Balance at December 31, 2010	$ 934
Interest accrued	14
Less: supplier settlements	(113)
Balance at June 30, 2011	$ 835

At June 30, 2011, the Utility’s net disputed claims liability was $835 million, consisting of $674 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 $655 million (classified on the Condensed 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 compliance and remediation, and tax matters.

Commitments

Utility

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.

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At June 30, 2011, the undiscounted future expected power purchase agreement payments were as follows:

(in millions)
2011	$ 1,419
2012	2,499
2013	3,043
2014	3,389
2015	3,545
Thereafter	54,337
Total	$ 68,232

Costs incurred by the Utility under power purchase agreements amounted to $1,145 million and $1,094 million for the six months ended June 30, 2011 and 2010, respectively.

Some of the power purchase agreements that the Utility entered into are treated as capital leases. The following table shows the future fixed capacity payments due under the contracts that are treated as capital leases. The fixed capacity payments are discounted to their present value in the table below using the Utility’s incremental borrowing rate at the inception of the leases. The amount of this discount is shown in the table below as the amount representing interest.

(in millions)
2011	$ 29
2012	50
2013	50
2014	42
2015	38
Thereafter	124
Total fixed capacity payments	333
Less: amount representing interest	(64)
Present value of fixed capacity payments	$ 269

Minimum lease payments associated with the lease obligation are included in cost of electricity on PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Income. The contracts that are treated as capital leases expire between April 2014 and September 2021.

At June 30, 2011 and December 31, 2010, current liabilities – other included $35 million and $34 million, and noncurrent liabilities – other included $234 million and $248 million, respectively. The corresponding assets at June 30, 2011 and December 31, 2010 of $269 million and $282 million including accumulated amortization of $139 million and $126 million, respectively are included in property, plant, and equipment on PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets.

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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 June 30, 2011, the Utility’s undiscounted expected future cash payments for natural gas purchases, natural gas transportation services, and natural gas storage were as follows:

(in millions)
2011	$ 481
2012	606
2013	251
2014	205
2015	194
Thereafter	1,126
Total (1)	$ 2,863

⁽¹⁾ Amounts above include firm transportation contracts for the Ruby Pipeline (a 1.5 billion cubic feet per day
(“bcf/d”) pipeline which is currently under construction and expected to become operational in the summer of
2011. The Utility has contracted for a capacity of approximately 0.4 bcf/d).

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage amounted to $929 million and $912 million for the six months ended June 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 June 30, 2011, the undiscounted obligations under nuclear fuel agreements were as follows:

(in millions)
2011	$46
2012	83
2013	125
2014	143
2015	200
Thereafter	1,065
Total	$ 1,662

Payments for nuclear fuel amounted to $47 million and $95 million for the six months ended June 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.

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Utility

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.

It is uncertain whether an incentive ratemaking mechanism for the 2010 through 2012 energy efficiency program cycle and future program years will continue. Although a proposed decision was issued on November 15, 2010 that recommended modifications to the mechanism for the 2010 through 2012 program cycle, the proposed decision was withdrawn from the CPUC’s consideration on April 13, 2011. On July 28, 2011, the CPUC issued a decision to extend the statutory deadline for addressing modifications to the mechanism to October 13, 2011.

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 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. 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 ($2.75 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 $42 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.

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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 Matters

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 lawsuits. In addition, PG&E Corporation and the Utility can incur penalties for failure to comply with federal, state, or local laws and regulations.

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 reviewed 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 assessing 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 liability claims related to the San Bruno accident and penalties related to the Rancho Cordova accident as discussed below) totaled $60 million at June 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 June 30, 2011.

Explosion and Fire in San Bruno, California

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. The National Transportation Safety Board (“NTSB”) has issued several public statements regarding its investigation of the San Bruno accident but has not yet made a final determination of the probable cause of the pipeline rupture. The CPUC initiated an investigation pertaining to safety recordkeeping for the Utility’s gas transmission pipeline that ruptured in San Bruno, as well as for its entire gas transmission system. Additionally, the Utility has received notification that a criminal investigation is being conducted in connection with the San Bruno accident. (See below.)

In addition to these investigations, approximately 90 tort lawsuits on behalf of approximately 320 plaintiffs, including two class action lawsuits, have been filed against PG&E Corporation and the Utility. The lawsuits seek compensation for personal injury, property damage, and other relief. The Utility recorded a provision of $220 million in 2010 for estimated third-party claims related to the San Bruno accident. During the quarter ended June 30, 2011, the Utility recorded an additional $59 million provision for third-party claims, reflecting the outcome of settlements and changes in estimates and assumptions regarding these claims.

As of June 30, 2011 and December 31, 2010, $211 million and $214 million, respectively, was accrued for third-party claims related to the San Bruno accident 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:

(in millions)
Balance at September 30, 2010	$ 220
Less: Payments	(6)
Balance at December 31, 2010	214
Additional costs accrued	59
Less: Payments	(62)
Balance at June 30, 2011	$ 211

The Utility estimates that it may record as much as an additional $121 million for third-party claims, for a total possible loss of $400 million. As more information becomes known, including information resulting from the pending investigations and settlement of claims, estimates and assumptions regarding the amount of third-party liability incurred in connection with the San Bruno accident may change. It is possible that a change in estimate, and any penalties resulting from the investigations discussed below, could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.

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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. During the quarter ended June 30, 2011, the Utility submitted insurance claims to certain insurers for the lower (or “primary”) layers and recognized $60 million for insurance recoveries that have been deemed probable under applicable accounting standards. As of June 30, 2011, $60 million was recorded as a receivable for insurance recoveries in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. As of December 31, 2010, no receivable for insurance recoveries was recorded. 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 (“OII”) 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. The CPUC stated that in deciding to issue the OII, it had relied on the NTSB’s public preliminary reports issued in connection with its investigation of the San Bruno accident, the NTSB’s January 3, 2011 urgent safety recommendations regarding the importance of accurate pipeline records in calculating maximum safe operating pressures, and other NTSB statements. After the NTSB has completed its investigation and issued a final report, the CPUC also will consider other possible violations of law, besides recordkeeping, associated with the Utility’s transmission lines and with Line 132 in particular.

During the quarter ended June 30, 2011, the Utility provided extensive information to the CPUC to comply with the directives contained in the OII. 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.

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 will cooperate fully 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 Investigation Regarding Rancho Cordova Accident

The CPUC also is 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 February 17, 2011, the Utility submitted a report to the CPUC in which the Utility stated that it agreed with the NTSB’s conclusions about the probable cause of the accident. On June 20, 2011, the Utility and the CPUC’s Consumer Protection and Safety Division (“CPSD”) requested that the CPUC approve a stipulated resolution of the CPUC’s investigation. Under the stipulation, the Utility has admitted to violations of law and has agreed to pay a penalty of $26 million to the State General Fund within twenty days after CPUC approval. The Utility also agreed to pay the CPSD’s expenses and other costs incurred in connection with the investigation and that it will not seek to recover the penalty or the amounts paid to the CPSD from customers. On July 29, 2011, a hearing was held before a CPUC administrative law judge regarding the reasonableness of the stipulation between the Utility and the CPSD. The administrative law judge will issue a decision to approve or reject the stipulation within 60 days.

As of June 30, 2011, approximately $26 million was accrued as a liability for penalties associated with the Rancho Cordova accident in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets.

Environmental Matters

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

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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 Utility had an undiscounted and gross environmental remediation liability of $677 million at June 30, 2011 and $612 million at December 31, 2010. 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	94
Amounts not recoverable from customers	35
Less: Payments	(64)
Balance at June 30, 2011	$ 677

The $677 million accrued at June 30, 2011 consisted of the following:

_• $54 million for remediation at the Utility’s natural gas compressor site located near Hinkley, California;

_• $179 million for remediation at the Utility’s natural gas compressor site located on the California border, near Topock, Arizona;

_• $83 million related to remediation at divested generation facilities;

_• $141 million related to remediation costs for the Utility’s generation and other facilities and for third-party disposal sites;

_• $158 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

_• $62 million related to remediation costs for fossil fuel decommissioning sites.

Of the $677 million environmental remediation liability, the Utility expects to recover $365 million through the CPUC-approved ratemaking mechanism that authorizes the Utility to recover 90% of hazardous waste remediation costs from customers without a reasonableness review (excluding any remediation associated with the Hinkley natural gas compressor site) and $135 million through the ratemaking mechanism that authorizes the Utility to recover 100% of 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 also recovers its 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.

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 $1.3 billion 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. Recovery of these amounts from customers would be subject to CPUC approval.

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 issues 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. While the IRS approved PG&E Corporation’s request for a change in method, the IRS will audit the methodology to determine the proper deduction. This audit has not progressed significantly because the IRS is working with the utility industry to resolve this matter in a consistent manner for all utilities before completing the audits for individual companies.

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PG&E Corporation and the Utility expect the IRS to release new guidance clarifying the treatment of deductible repairs 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 December 2010, the IRS accepted PG&E Corporation’s 2009 tax return. The IRS has not completed the CAP audits for 2010 and 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 June 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 Matters Related to the Utility’s Natural Gas Pipeline System. 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 National Transportation Safety Board (“NTSB”) is continuing its investigation of the San Bruno accident, but has not made a final determination of the probable cause. Additionally, several related investigations and proceedings are pending as discussed below in “Natural Gas Pipeline Matters.” The Utility estimates that it will incur costs associated with its natural gas pipeline system ranging from $350 million to $550 million in 2011, of which $126 million has been incurred during the six months ended June 30, 2011. PG&E Corporation and the Utility are uncertain what portion of these pipeline-related costs will ultimately be recoverable through rates. The Utility has recorded a cumulative provision of $279 million for third-party claims in connection with the San Bruno accident, and estimates that it may record as much as an additional $121 million, for a total possible loss of $400 million. The Utility continues to expect that a significant portion of these costs will be recovered through its insurance and recorded $60 million for insurance recoveries during the quarter ended June 30, 2011. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.) Finally, the CPUC is considering a stipulation between the Utility and the CPUC enforcement staff that would impose a fine of $26 million on the Utility to resolve the CPUC’s investigation of a natural gas explosion and fire that occurred on December 24, 2008 in a house located in Rancho Cordova, California (the “Rancho Cordova accident”). The resolutions of these foregoing 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, or cash flows.

_• The Timing and Outcome of Ratemaking and Other Regulatory Proceedings. The majority of the Utility’s base revenue requirements are determined in various rate cases by the CPUC and the FERC. On April 14, 2011, the CPUC issued a decision in the Utility’s 2011 Gas Transmission and Storage rate case (“GT&S”) that authorized the Utility to collect increased revenue

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requirements from January 1, 2011. On May 5, 2011, the CPUC issued a final decision in the Utility’s 2011 General Rate Case (“GRC”) that authorized an increase in revenue requirements from January 1, 2011. (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.)

_• 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 the opportunity 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 forecasts, or the Utility may incur significant unanticipated costs, such as costs related to storms, outages, catastrophic events, or costs incurred to comply with regulatory orders or legislation. Differences in the amount or timing of forecasted or authorized and actual costs can 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 as described in the 2010 Annual Report. 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. 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 the level of future debt financing which will depend on various factors, including the timing and amount of its capital expenditures. The Utility’s equity needs also will be affected by the amount of costs the Utility incurs in connection with the matters discussed below under “Natural Gas Pipeline Matters” to the extent the Utility is unable to conclude that the incurred costs are probable of recovery through rates. 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 Six Months Ended June 30, 2011

PG&E Corporation’s income available for common shareholders for the three months ended June 30, 2011 increased by $29 million, or 9%, to $362 million, compared to $333 million for the same period in 2010. For the six months ended June 30, 2011, income available for common shareholders decreased by $30 million, or 5%, to $561 million, compared to $591 million for the same period in 2010. The following table is a summary reconciliation of the key changes in income available for common shareholders and earnings per common share for the three and six months ended June 30, 2011:

	Three Months Ended June 30,				Six Months Ended June 30,
	Earnings		Earnings Per Common Share (Diluted)		Earnings		Earnings Per Common Share (Diluted)
(in millions)
Income Available for Common Shareholders – June 30, 2010		$333		$0.86		$591		$1.54
Natural gas pipeline matters (1)
Pipeline-related costs		(45)		(.11)		(76)		(.19)
Third-party liability claims		(35)		(.09)		(35)		(.09)
Insurance recoveries		36		.09		36		.09
Litigation and regulatory matters (2)		(3)		(.01)		(28)		(.07)
Nuclear refueling outage (3)		(24)		(.06)		(26)		(.06)
Storm and outage expenses (4)		(5)		(.01)		(23)		(.06)
Gas transmission revenues (5)		(6)		(.02)		(18)		(.05)
Increase in rate base earnings (6)		68		.17		82		.21
2011 GRC and GT&S expense recovery (7)		27		.07		-		-
Statewide ballot initiative (8)		20		.05		45		.12
Federal healthcare law (9)		-		-		20		.05
Other (10)		(4)		-		(7)		(.02)
Increase in shares outstanding (11)		-		(.03)		-		(.06)
Income Available for Common Shareholders – June 30, 2011		$362		$0.91		$561		$1.41

__________________________________________

⁽¹⁾   During the three and six months ended June 30, 2011, the Utility incurred costs of $44 million and $75 million, respectively, after-tax, associated with its natural gas pipeline system. This included pipeline-related costs to review records, validate operating pressures, conduct hydrostatic pressure tests, inspect pipelines, and perform other activities associated with the Utility’s natural gas pipeline system. These costs also included an increase in the provision for third-party liability claims related to the San Bruno accident, reflecting settlements and changes in estimates and assumptions regarding these claims. Costs incurred were partially offset by insurance recoveries that have been deemed probable under applicable accounting standards as of June 30, 2011.

⁽²⁾   During the three and six months ended June 30, 2011, the Utility incurred costs of $3 million and $28 million, respectively, after-tax, related to litigation and regulatory matters, which included amounts related to the Rancho Cordova accident.

⁽³⁾   During the three and six months ended June 30, 2011, the Utility incurred higher expenses of $24 million and $26 million, respectively, after-tax, in connection with a scheduled refueling outage at Diablo Canyon.

⁽⁴⁾   During the three and six months ended June 30, 2011, the Utility incurred higher expenses of $5 million and $23 million, respectively, after-tax, due to more severe storms as compared to the same period in 2010.

⁽⁵⁾   During the three and six months ended June 30, 2011, the Utility recognized lower gas transmission revenues of $6 million and $18 million, respectively, after-tax, as compared to the same periods in 2010, primarily due to a decrease in natural gas storage revenues.

⁽⁶⁾   During the three and six months ended June 30, 2011, the Utility recognized earnings of $68 million and $82 million, respectively, after-tax, attributable to the ROE on higher authorized capital investments authorized by the CPUC’s final decisions in the 2011 GRC and GT&S rate cases.

⁽⁷⁾   During the three months ended June 30, 2011, the Utility recognized earnings of $27 million, after-tax, that offsets the unfavorable variance that occurred during the quarter ended March 31, 2011 as the Utility incurred costs before the CPUC issued its final decisions in the 2011 GRC and GT&S rate case.

⁽⁸⁾   During the three and six months ended June 30, 2010, PG&E Corporation incurred $20 million and $45 million, respectively, to support Proposition 16 - The Taxpayers Right to Vote Act.

⁽⁹⁾   During the six months ended June 30, 2010, the Utility recorded a charge of $20 million, triggered by the elimination of the tax deductibility of Medicare Part D federal subsidies.

⁽¹⁰⁾  During the six months ended June 30, 2011, the Utility incurred higher costs for other operating and maintenance expenses, including environmental remediation.

⁽¹¹⁾  Represents the impact of a higher number of shares outstanding at June 30, 2011, compared to the number of shares outstanding at June 30, 2010, to maintain the Utility’s 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

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This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements 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 Utility’s ability to efficiently manage capital expenditures and its operating and maintenance expenses within authorized levels and timely recover its costs through rates;

_• the outcome of pending and future regulatory, legislative, or other proceedings or investigations related to the San Bruno accident, the results of the Utility’s system-wide review of the class location designations for its natural gas transmission, and the safety of the Utility’s natural gas transmission pipelines in its northern and central California service territory; whether the CPUC approves the proposed resolution of the investigation of the Rancho Cordova accident; whether the Utility incurs civil or criminal penalties as a result of these proceedings or investigations; the ultimate amount of costs the Utility incurs in connection with its natural gas pipeline system that the Utility is unable to recover through rates or insurance; and whether the Utility incurs third-party liabilities or other costs in connection with electric or natural gas service disruptions caused by pressure reductions in the Utility’s natural gas pipeline system;

_• the outcome of future investigations or proceedings 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;

_• reputational harm that PG&E Corporation and the Utility may suffer depending on the outcome of the various regulatory proceedings and investigations of the San Bruno accident and natural gas pipeline matters including the findings of the CPUC’s independent review panel; 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, 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, 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;

_• 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 risks at nuclear facilities to avoid the type of damage sustained by nuclear facilities in Japan following the March 2011

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earthquake, or to address the operations, decommissioning, storage of spent nuclear fuel, security, safety, cooling water intake, or other operational or licensing matters associated with Diablo Canyon and whether the Utility is able to comply with such new orders, legislation, or regulations;

_• whether the Utility earns incentive revenues or incurs obligations under incentive ratemaking mechanisms, such as the CPUC’s incentive ratemaking mechanism relating to energy savings achieved through implementation of the utilities’ customer energy efficiency programs;

_• the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies;

_• whether the Utility can successfully complete its program to install advanced meters for its electric and natural gas customers, allay customer concerns about the new metering technology, and integrate the new meters with its customer billing and other systems while also implementing the system design changes necessary to accommodate retail electric rates based on dynamic pricing (i.e., electric rates that can vary with the customer’s time of use and are more closely aligned with wholesale electricity prices);

_• how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company and the extent to which the interpretation or enforcement of these conditions has a material impact on PG&E Corporation;

_• 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;

_• 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 laws and regulations addressing the reduction of carbon dioxide and other greenhouse gases, water, the remediation of hazardous waste, and other matters, and whether the Utility is able to recover the costs of compliance with such laws, including the cost of emission allowances and offsets that the Utility may incur under federal or state cap and trade regulations;

_• 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 six months ended June 30, 2011 and 2010:

	Three Months Ended June  30,				Six Months Ended June  30,
(in millions)	2011		2010		2011		2010
Utility
Electric operating revenues		$2,888		$2,515		$5,504		$5,025
Natural gas operating revenues		795		717		1,775		1,682
Total operating revenues		3,683		3,232		7,279		6,707
Cost of electricity		906		863		1,794		1,783
Cost of natural gas		258		247		766		742
Operating and maintenance		1,228		958		2,454		1,948
Depreciation, amortization, and decommissioning		592		468		1,082		919
Total operating expenses		2,984		2,536		6,096		5,392
Operating Income		699		696		1,183		1,315
Interest income		2		2		4		4
Interest expense		(169)		(164)		(340)		(320)
Other income (expense), net		16		1		33		(5)
Income Before Income Taxes		548		535		880		994
Income tax provision		189		196		320		391
Net Income		359		339		560		603
Preferred stock dividend requirement		4		4		7		7
Income Available for Common Stock		$355		$335		$553		$596
PG&E Corporation, Eliminations, and Other(1)
Operating revenues		$1		$-		$2		$-
Operating expenses		8		1		9		2
Operating Loss		(7)		(1)		(7)		(2)
Interest income		1		-		1		-
Interest expense		(5)		(11)		(11)		(23)
Other income, net		5		1		5		1
Loss Before Income Taxes		(6)		(11)		(12)		(24)
Income tax benefit		(13)		(9)		(20)		(19)
Net Income (Loss)		$7		$(2)		$8		$(5)
Consolidated Total
Operating revenues		$3,684		$3,232		$7,281		$6,707
Operating expenses		2,992		2,537		6,105		5,394
Operating Income		692		695		1,176		1,313
Interest income		3		2		5		4
Interest expense		(174)		(175)		(351)		(343)
Other income (expense), net		21		2		38		(4)
Income Before Income Taxes		542		524		868		970
Income tax provision		176		187		300		372
Net Income		366		337		568		598
Preferred stock dividend requirement of subsidiary		4		4		7		7
Income Available for Common Shareholders		$362		$333		$561		$591

__________________________________________

  ⁽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 six months ended June 30, 2011 and 2010. These operating results reflect the increase in authorized revenues from January 1, 2011 that were approved by the CPUC during the quarter ended June 30, 2011 in the 2011 GRC and the 2011 GT&S rate case, of which $126 million pertains to the three month period ended March 31, 2011. (See “Regulatory Matters” below.)

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. In addition, a portion of the Utility’s customers’ load is satisfied by electricity provided under long-term contracts between the California Department of Water Resources (“DWR”) and various power suppliers. The costs and associated revenues to recover the costs allocated to the Utility by the DWR are not included in the Condensed Consolidated Statements of Income.

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

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2011		2010		2011		2010
Revenues excluding pass-through costs		$1,738		$1,472		$3,261		$2,915
Revenues for recovery of passed-through costs		1,150		1,043		2,243		2,110
Total electric operating revenues		$2,888		$2,515		$5,504		$5,025

The Utility’s total electric operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $373 million, or 15%, in the three months ended June 30, 2011, and by $479 million, or 10%, in the six months ended June 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 $107 million and $133 million in the three and six months ended June 30, 2011, respectively, as compared to the same periods in 2010, primarily due to increases in the cost of public purpose programs, pension contributions, and the cost of electricity procurement (see “Cost of Electricity” below). Electric operating revenues, excluding costs passed through to customers, increased by $266 million and $346 million in the three and six months ended June 30, 2011, respectively, as compared to the same periods in 2010. The increase for both the three and six month periods ended June 30, 2011 consists primarily of additional base revenues that were authorized by the CPUC in the 2011 GRC on May 5, 2011, of which approximately $100 million pertains to the quarter ended March 31, 2011. (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 are also expected to be impacted by the FERC’s final decision to be issued in the transmission owner (“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 June 30,				Six Months Ended June 30,
(in millions)	2011		2010		2011		2010
Cost of purchased power		$857		$811		$1,678		$1,653
Fuel used in own generation facilities		49		52		116		130
Total cost of electricity		$906		$863		$1,794		$1,783
Average cost of purchased power per kWh (1)		$0.088		$0.084		$0.088		$0.083
Total purchased power (in millions of kWh)		9,709		9,708		19,137		19,825

__________________________________________

      ⁽¹⁾ Kilowatt-hour

The Utility’s total cost of electricity increased by $43 million, or 5%, in the three months ended June 30, 2011 and $11 million, or 1%, in the six months ended June 30, 2011 as compared to the same periods in 2010, primarily due to an increase in the price of purchased power.

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 federal or state legislation or rules that may be adopted to regulate 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 June 30,				Six Months Ended June 30,
(in millions)	2011		2010		2011		2010
Revenues excluding pass-through costs		$454		$416		$858		$830
Revenues for recovery of passed-through costs		341		301		917		852
Total natural gas operating revenues		$795		$717		$1,775		$1,682

The Utility’s natural gas operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $78 million, or 11%, and by $93 million, or 6%, in the three and six months ended June 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 $40 million and $65 million in the three and six months ended June 30, 2011, respectively, as compared to the same periods in 2010, primarily due to an increase in the costs of natural gas procurement, public purpose programs, and pension contributions. (See “Cost of Natural Gas” below.) Natural gas operating revenues, excluding costs passed through to customers, increased by $38 million and $28 million in the three and six months ended June 30, 2011, respectively. The increase for both the three and six month periods ended June 30, 2011 was primarily due to $54 million in additional base revenues, which was partially offset by a decrease in natural gas storage revenues. The additional base revenues were authorized by the CPUC in the 2011 GT&S rate case on April 14, 2011 and the GRC on May 5, 2011, and included approximately $27 million pertaining to the quarter ended March 31, 2011. (See “Regulatory Matters” below.)

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

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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.)

Cost of Natural Gas

The Utility’s cost of natural gas includes the purchase costs of natural gas, transportation costs on interstate pipelines, and gas storage costs, but excludes the transportation costs on intrastate pipelines for core and non-core customers, which are 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 June 30,				Six Months Ended June 30,
(in millions)	2011		2010		2011		2010
Cost of natural gas sold		$213		$204		$674		$654
Transportation cost of natural gas sold		45		43		92		88
Total cost of natural gas		$258		$247		$766		$742
Average cost per Mcf of natural gas sold		$3.80		$3.58		$4.27		$4.63
Total natural gas sold (in millions of Mcf) (1)		56		57		158		152

__________________________________________

      ⁽¹⁾ One thousand cubic feet

The Utility’s total cost of natural gas increased by $11 million, or 4%, in the three months ended June 30, 2011 as compared to the same period in 2010. The increase was primarily due to an increase in the market price of natural gas, partially offset by a decrease in procurement costs associated with lower demand caused by warmer weather during the period.

The Utility’s total cost of natural gas increased by $24 million, or 3%, in the six months ended June 30, 2011 as compared to the same period in 2010. The increase was primarily due to the absence of a $49 million refund the Utility received in the first quarter of 2010 for pass through to customers as part of a litigation settlement. This was partially offset by a decrease in procurement costs resulting from a decline in the average market price of natural gas purchased during the first quarter of 2011.

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 $270 million, or 28%, in the three months ended June 30, 2011, as compared to the same period in 2010. Costs that are passed through to customers and do not impact net income increased by $64 million, 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 $206 million. This increase was attributable to a number of factors, including $69 million for labor and other maintenance-related costs, the majority of which is associated principally with the scheduled refueling outage at Diablo Canyon and more severe storms in 2011; $17 million for higher environmental remediation costs, primarily related to the Utility’s natural gas compressor site located near Hinkley, California; and increases in other expenses. Additionally, the Utility incurred costs of $74 million in connection with matters described below in “Natural Gas Pipeline Matters.” This amount included $75 million of pipeline-related costs to review records, validate operating pressures, conduct hydrostatic pressure tests, inspect pipelines, and perform other activities associated with the Utility’s natural gas pipeline system; a $59 million increase to the provision for third-party liability claims related to the San Bruno accident, reflecting the outcome of settlements and changes in estimates and

46

assumptions regarding these claims; partially offset by $60 million for insurance recoveries related to third-party liability costs. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.)

The Utility’s operating and maintenance expenses (including costs currently passed through to customers) increased by $506 million, or 26%, in the six months ended June 30, 2011, as compared to the same period in 2010. Costs that are passed through to customers and do not impact net income increased by $134 million, primarily due to in the cost of public purpose programs and pension plan contributions. Excluding costs currently passed through to customers, operating and maintenance expenses increased by $372 million. This increase was attributable to a number of factors, including $118 million in labor and other maintenance-related costs, the majority of which is associated with the scheduled refueling outage at Diablo Canyon and more severe storms in 2011; $31 million for legal and regulatory matters, primarily related to the Rancho Cordova accident (see “CPUC Investigation Regarding Rancho Cordova Accident” below); $22 million for higher environmental remediation costs, primarily related to the Utility’s natural gas compressor site located near Hinkley, California; and increases in other expenses. Additionally, the Utility incurred costs of $125 million in connection with matters described below in “Natural Gas Pipeline Matters.” This amount included $126 million of pipeline-related costs associated with the Utility’s natural gas pipeline system as described above; a $59 million increase to the provision for third-party liability claims related to the San Bruno accident, reflecting the outcome of settlements and changes in estimates and assumptions regarding these claims; partially offset by $60 million for insurance recoveries related to third-party liability costs. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.)

The Utility currently estimates that it will incur costs associated with its natural gas pipeline system ranging from $350 million to $550 million in 2011, of which it has incurred $126 million as of June 30, 2011. The Utility estimates that it will incur costs during the remaining six months of the year, primarily to perform 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 to perform other activities related to the safety of its gas pipeline system. These cost estimates could change depending on the results of the Utility’s records review, the scope and timetable of the Utility’s implementation plan that it must file with the CPUC by August 26, 2011 (see “CPUC Rulemaking Proceeding” below), the outcome of the regulatory proceedings and investigations discussed below under “Natural Gas Pipeline Matters,” and new state or federal requirements that may be imposed on operators of natural gas transmission pipelines. PG&E Corporation and the Utility are uncertain what portion of these pipeline-related costs that the Utility may incur would be recoverable through rates and the timing of any such recovery.

Future operating and maintenance expenses also may be affected by the amount of third-party liability the Utility incurs as a result of the San Bruno accident. (See “Natural Gas Pipeline Matters” below and Note 10 of the Notes to the Condensed Consolidated Financial Statements.) Although the Utility considers it likely that a significant portion of the costs the Utility incurs for third-party claims will be recovered through insurance, it is unable to predict the amount and timing of additional insurance recoveries. Finally, the Utility may be required to pay fines or penalties as a result of the pending investigations discussed below under “Natural Gas Pipeline Matters” which may have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.

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 $124 million, or 26%, in the three months ended June 30, 2011, and $163 million, or 18%, in the six months ended June 30, 2011, as compared to the same period in 2010, primarily due to an increase in authorized 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 six months ended June 30, 2011, the Utility’s interest income increased by less than $1 million, respectively, as compared to the same periods in 2010, due to fluctuations in various regulatory balancing accounts.

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.)

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Interest Expense

In the three and six months ended June 30, 2011, the Utility’s interest expense increased by $5 million, or 3%, and $20 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

In the three and six months ended June 30, 2011, the Utility’s other income (expense), net, increased by $15 million, and $38 million, respectively, as compared to the same periods in 2010 when the Utility incurred costs to support a California ballot initiative that appeared on the June 2010 ballot. The increases were partially offset by decreases in allowance for equity funds used during construction as the average balances of construction work in progress were lower as compared to the same periods in 2010.

Income Tax Provision

The Utility’s income tax provision decreased by $7 million, or 4%, for the three months ended June 30, 2011, and $71 million, or 18% for the six months ended June 30, 2011, as compared to the same periods in 2010. The effective tax rates for the three months ended June 30, 2011 and 2010 were 34% and 37%, respectively. The effective tax rates for the six months ended June 30, 2011 and 2010 were 36% and 39%, respectively. The effective tax rates decreased in the three and six months ended June 30, 2011, as compared to the same periods in 2010 when the Utility incurred non tax-deductible lobbying expenses associated with a ballot initiative and reversed 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.

PG&E Corporation, Eliminations, and Other

Operating Revenues and Expenses

PG&E Corporation’s revenues consist mainly of billings to its affiliates for services rendered, all of which are eliminated in consolidation. PG&E Corporation’s operating expenses consist mainly of employee compensation and payments to third parties for goods and services. Generally, PG&E Corporation’s operating expenses are allocated to affiliates. These allocations are made without mark-up and are eliminated in consolidation. PG&E Corporation’s interest expense relates to its 5.8% Senior Notes, and is not allocated to affiliates.

There were no material changes to PG&E Corporation’s operating income in the three and six months ended June 30, 2011, as compared to the same periods in 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 and natural gas, 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.

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Revolving Credit Facilities

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

(in millions)	Termination Date		Facility Limit			Letters of Credit Outstanding		Cash Borrowings		Commercial Paper Backup		Availability
PG&E Corporation		May 2016		$300	(1)		$-		$75		$-		$225
Utility		May 2016		3,000	(2)		319		-		870		1,811
Total revolving credit facilities				$3,300			$319		$75		$870		$2,036

__________________________________________

⁽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 six months ended June 30, 2011, the average outstanding commercial paper balance was $838 million and the maximum outstanding balance during the quarter was $1.2 billion. In addition, for the six months ended June 30, 2011, the average outstanding borrowings on PG&E Corporation’s revolving credit facility was $32 million and the maximum outstanding balance during the quarter was $75 million. There were no cash borrowings on the Utility’s revolving credit facility in the six months ended June 30, 2011.

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, as amended by the Amendment and Limited Consent Agreement, dated as of 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, as amended by the Amendment and Limited Consent Agreement, dated as of 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. PG&E Corporation and the Utility have the right to replace any lender who does not agree to an extension under the respective agreements.

Subject to obtaining commitments from existing or new lenders and satisfaction of other specified conditions, 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 June 30, 2011, PG&E Corporation and the Utility were in compliance with all covenants under each of the revolving credit facilities.

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2011 Financings

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 six months ended June 30, 2011, PG&E Corporation issued 2,354,062 shares of common stock under the Equity Distribution Agreement for cash proceeds of $103 million, net of fees and commissions paid of $1 million. The proceeds from these issuances were used for general corporate purposes.

In addition, during the six months ended June 30, 2011, PG&E Corporation issued 3,853,288 shares of common stock upon the exercise of employee stock options and under its 401(k) plan and Dividend Reinvestment and Stock Purchase Plan, generating $154 million of cash.

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.

During the six months ended June 30, 2011, the Utility received cash contributions of $255 million from PG&E Corporation to ensure that the Utility had adequate capital to maintain the 52% common equity ratio authorized by the CPUC and to fund its capital expenditures.

Future Financing Needs

The amount and timing of the Utility’s future debt and equity financings will depend on various factors, including:

_• 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;

_• the timing and amount of payments made to third parties in connection with the San Bruno accident, and the timing and amount of related insurance recoveries;

_• the timing and amount of costs associated with the Utility’s natural gas pipeline system (see “Operating and Maintenance” above and “Natural Gas Pipeline Matters” below);

_• the amount and timing of any fines or penalties imposed on the Utility in connection with the various regulatory proceedings and investigations related to the San Bruno accident and the Utility’s natural gas pipeline system;

_• 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. (See Notes 9 and 10 of the Notes to the Condensed Consolidated Financial Statements.)

PG&E Corporation’s future financing needs depend primarily on the timing and amount of contributions made to the Utility to maintain the Utility’s 52% common equity ratio authorized by the CPUC. PG&E Corporation anticipates issuing equity in the future to meet the Utility’s additional equity needs as it incurs costs associated with the matters discussed below under “Natural Gas Pipeline Matters.” PG&E Corporation also may issue debt or equity in the future to fund future tax equity investments to the extent that internally generated funds are not sufficient. (See “PG&E Corporation” below.)

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Dividends

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

(in millions)
PG&E Corporation
Common stock dividends paid	$349
Utility
Common stock dividends paid	$358
Preferred stock dividends paid	7

On June 15, 2011, the Board of Directors of PG&E Corporation declared dividends of $0.455 per share, totaling $183 million, of which $177 million was paid on July 15, 2011 to shareholders of record on June 30, 2011. The remaining $6 million was reinvested under the Dividend Reinvestment and Stock Purchase Plan.

On June 15, 2011, the Board of Directors of the Utility declared a dividend on its outstanding series of preferred stock, payable on August 15, 2011, to shareholders of record on July 29, 2011.

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 six months ended June 30, 2011 and 2010 were as follows:

	Six months ended June 30,
(in millions)	2011		2010
Net income		$560		$603
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,175		1,016
Allowance for equity funds used during construction		(41)		(57)
Deferred income taxes and tax credits, net		408		(1)
Other		22		-
Effect of changes in operating assets and liabilities:
Accounts receivable		(1)		(81)
Inventories		1		(20)
Accounts payable		140		4
Income taxes receivable/payable		66		475
Other current assets and liabilities		(186)		(265)
Regulatory assets, liabilities, and balancing accounts, net		(324)		(263)
Other noncurrent assets and liabilities		114		(29)
Net cash provided by operating activities		$1,934		$1,382

In the six months ended June 30, 2011, net cash provided by operating activities increased by $552 million compared to the same period in 2010 primarily due to a decrease of $279 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 remaining changes in cash flows from operating activities consisted of fluctuations in activities within the normal course of business such as power purchases and customer billings.

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

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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 costs associated with the Utility’s natural gas pipeline system. (See “Operating and Maintenance” above and “Natural Gas Pipeline Matters” below.)

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

	Six months ended June  30,
(in millions)	2011		2010
Capital expenditures		$(1,897)		$(1,786)
Decrease in restricted cash		198		50
Proceeds from sales and maturities of nuclear decommissioning trust investments		1,007		685
Purchases of nuclear decommissioning trust investments		(969)		(696)
Other		11		11
Net cash used in investing activities		$(1,650)		$(1,736)

Net cash used in investing activities decreased by $86 million in the six months ended June 30, 2011 compared to the same period in 2010. This decrease was primarily due to $191 million in restricted cash that was released from escrow in the six months ended June 30, 2011 for settled or withdrawn Chapter 11 disputed claims with no similar release in 2010. This decrease was partially offset by an increase in capital expenditures that was primarily due to the timing of payments.

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 six months ended June 30, 2011 and 2010 were as follows:

	Six months ended June  30,
(in millions)	2011		2010
Net issuances of commercial paper, net of discount of $2 in 2011 and $1 in 2010		$265		$693
Proceeds from issuance of long-term debt, net of discount and issuance costs of $2 in 2011 and $5 in 2010		298		295
Short-term debt matured		-		(500)
Long-term debt matured		(500)		-
Energy recovery bonds matured		(191)		(182)
Preferred stock dividends paid		(7)		(7)
Common stock dividends paid		(358)		(358)
Equity contribution		255		130
Other		13		9
Net cash provided by (used in) financing activities		$(225)		$80

In the six months ended June 30, 2011, net cash used in financing activities increased by $305 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

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the level of cash provided by or used in operating activities and the level of cash provided by or used 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 June 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 of local rebates, federal investment tax credits or grants, and a share of the customer payments made to these companies. As of June 30, 2011, PG&E Corporation had made total payments of $251 million under these tax equity agreements and received $99 million in benefits and customer payments. On April 14, 2011, PG&E Corporation borrowed $75 million under its $187 million revolving credit facility to 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 six months ended June 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, a 586-megawatt (“MW”) generation facility being constructed in Oakley, California.

In addition, 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.

Proposed Oakley Generation Facility

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. Under the CPUC’s decision, if the Utility acquires the facility from the developer before January 1, 2016, the Utility’s associated costs cannot be recovered through rates until after January 1, 2016. Instead, the Utility’s ability to recover its costs before January 1, 2016 would depend on the amount of electric generation revenues produced by the facility. If the Utility acquires the facility after January 1, 2016, the Utility’s associated costs would be recoverable through rates. Under the current purchase and sale agreement the Utility could be required

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to acquire the facility before January 1, 2016. The Utility and the developer are negotiating an amendment to the agreement to delay the acquisition until January 1, 2016 or later and to reflect the possibility that the facility may be operated before the acquisition. The Utility is uncertain whether and when the proposed amendment will be executed.

On May 20, 2011, the California Energy Commission (“CEC”) authorized the developer to construct the facility and construction began in late June. Various environmental groups have filed an appeal of the CEC’s decision with the California Supreme Court. On May 26, 2011, the CPUC denied various applications for rehearing that had been filed with respect to the CPUC’s December 2010 decision. The CPUC’s denial of the rehearing applications has been appealed to both the California Supreme Court and the California Court of Appeal. The Utility is unable to predict the outcome of these appeals.

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

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 of these matters as well as new developments are summarized here and described more fully below:

_• The NTSB began its formal investigation of the San Bruno accident on September 10, 2010. The NTSB is responsible for investigating the San Bruno accident, determining the probable cause of the pipeline rupture, and making recommendations to prevent similar accidents from occurring. The NTSB has issued several public statements and reports and held fact-finding hearings in Washington, D.C. in early March but has not made a final determination of the probable cause of the pipeline rupture. The NTSB has stated that it expects to issue its report by September 30, 2011. PG&E Corporation and the Utility are currently unable to predict the outcome of the investigation.

_• The CPUC appointed an independent review panel to investigate the San Bruno accident. On June 8, 2011, the independent review panel issued its report containing the panel’s findings and recommendations to ensure such an accident is not repeated. (See “Report of CPUC’s Independent Review Panel” below.)

_• In November 2010, the CPUC also began an investigation of the Rancho Cordova accident that occurred on December 24, 2008. On June 20, 2011, the Utility and the CPUC’s Consumer Protection and Safety Division (“CPSD”) requested that the CPUC approve a stipulation to resolve the investigation including a proposal that the Utility pay a $26 million penalty. (See “CPUC Investigation Regarding Rancho Cordova Accident” below.)

_• On February 24, 2011, the CPUC initiated a formal investigation into the adequacy of the Utility’s gas transmission pipeline recordkeeping practices for its gas transmission system, and in particular for the pipeline involved in the San Bruno accident. During the quarter ended June 30, 2011, the Utility submitted extensive information to the CPUC about the Utility’s pipeline records. (See “CPUC Investigation Regarding Utility’s Facilities Records for its Natural Gas Pipelines” below.)

_• On February 24, 2011, the CPUC also opened a rulemaking proceeding in order to develop and adopt safety-related changes to its regulation of natural gas transmission and distribution pipelines in California. On June 9, 2011, the CPUC ordered each California natural gas transmission pipeline operator to submit an implementation plan by August 26, 2011 that describes the operator’s plan to either pressure test or replace those pipeline segments that have never been pressure tested or that lack sufficient detail related to the performance of a test. (See “CPUC Rulemaking Proceeding” below.)

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_• 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.)

_• In June 2011, the CPSD informed the Utility that it had hired an independent consulting firm to conduct an audit of costs incurred by the Utility since 1996 on its natural gas transmission 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 or may have an MAOP higher than appropriate for their current class location designations. (See Part II, Item 1.A., Risk Factors, below.)

_• 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 claims and other damage claims. (See “Pending Lawsuits and Claims” below.)

_• Each of the Boards of Directors of PG&E Corporation and the Utility has appointed a special review committee, composed solely of independent directors, to review the natural gas transmission and distribution practices used in the industry and by the Utility, and such other matters as the committees deem appropriate. The committees’ reviews, which commenced in late 2010, are expected to be completed by the third quarter of 2011.

The Utility currently expects that it will incur a material amount of costs associated with its natural gas pipeline system. The resolutions of these foregoing 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 Operations” below.)

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 natural gas pipeline integrity management program had several shortcomings and questioned whether the Utility embraced the spirit of the pipeline integrity regulations. The panel recommended that the Utility commission an independent operations and management audit of the gas transmission and gas distribution functions. It also recommended that the Utility ensure all individuals in top management, who have direct responsibility for managing the operation of the natural gas system, have thorough knowledge of gas transmission and distribution operations.

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 18 formal 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.

There have been several recent management changes including the appointment of a new senior executive to lead the gas transmission and distribution function and the creation of a new senior executive position to lead the electric transmission and distribution function. Both of these executives report to the President of the Utility. In addition, PG&E Corporation is searching for a new chief executive officer following the retirement of Peter Darbee. (The executives who departed during the six months ended June 30, 2011 are entitled to certain payments which will not be recovered through rates.)

PG&E Corporation and the Utility are unable to predict how the CPUC will use the findings and recommendations contained in the report or whether additional investigations or proceedings will be commenced.

CPUC Investigation Regarding Rancho Cordova Accident

The CPUC also is investigating a natural gas explosion and fire that occurred on December 24, 2008 in a house located in Rancho Cordova, California. On February 17, 2011, the Utility submitted a report to the CPUC in which the Utility stated that it agreed with the NTSB’s conclusions about the probable cause of the accident. On June 20, 2011, the Utility and the CPSD

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requested that the CPUC approve a stipulated resolution of the CPUC’s investigation of the Rancho Cordova accident. Under the stipulation, the Utility has admitted to violations of law and has agreed to pay a penalty of $26 million to the State General Fund within twenty days after CPUC approval. The Utility also agreed to pay the CPSD’s expenses and other costs incurred in connection with the investigation and that it will not seek to recover the penalty or the amounts paid to the CPSD from customers. On July 29, 2011, a hearing was held before a CPUC administrative law judge regarding the reasonableness of the stipulation between the Utility and the CPSD. The administrative law judge will issue a decision to approve or reject the stipulation within 60 days.

As of June 30, 2011, approximately $26 million was accrued as a liability for penalties associated with the Rancho Cordova accident in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets.

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 (“OII”) 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 CPUC stated that in deciding to issue the OII, it had relied on the NTSB’s public preliminary reports issued in connection with its investigation of the San Bruno accident, the NTSB’s January 3, 2011 urgent safety recommendations regarding the importance of accurate pipeline records in calculating maximum safe operating pressures, and other NTSB statements. After the NTSB has completed its investigation and issued a final report, the CPUC also will consider other possible violations of law, besides recordkeeping, associated with the Utility’s transmission lines and with Line 132 in particular.

The first phase of the CPUC’s investigation is 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. The Utility has reviewed its records dating back to 1955 and has 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.

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 will cooperate fully 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

On June 9, 2011, the CPUC issued an order that requires each California natural gas transmission pipeline operator to develop an implementation plan to either pressure test or replace those pipeline segments that have never been pressure tested or that lack sufficient detail related to the performance of a test. The Utility’s implementation plan will supersede the Utility’s proposed Pipeline 2020 initiatives. (See the discussion of the proposed Pipeline 2020 program in the 2010 Annual Report.) The CPUC recognizes that the implementation plans will span several years and involve significant costs. The implementation plans are required to include:

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_• a priority-ranked schedule for pressure testing of pipeline segments based on risk assessment and maintaining service reliability;

_• interim safety enhancement measures, such as increased patrols and leak surveys or pressure reductions;

_• criteria on which pipeline segments are identified for replacement instead of pressure testing; and

_• consideration for retrofitting pipeline to allow for in-line inspection tools and improved shut-off valves.

Each implementation plan must include specific capital and expense estimates and anticipated rate impacts. In addition, the Utility’s plan must include a ratemaking proposal to allocate costs between ratepayers and shareholders. The Utility has filed a request in the rulemaking proceeding for permission to establish a memorandum account to track costs for potential future rate recovery. It is uncertain when the CPUC will rule on this request. Costs that the Utility incurs before the memorandum account has been established may not be recoverable through rates. The implementation plans must be filed with the CPUC by August 26, 2011. The procedural schedule calls for hearings to consider the implementation plans be held in November 2011. After the NTSB issues its report, a prehearing conference will be held to determine the schedule for the remainder of the proceeding.

Additionally, 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. As part of the proposed stipulation, the Utility and the CPSD had proposed a detailed compliance plan, including specific milestones, for the Utility to complete its records review and MAOP validation using an MAOP validation methodology that would supplement specific documentation with an engineering analysis, excavation and field testing, and assumptions about certain pipeline components, such as fittings and elbows, based on the material specifications at the time those materials were procured. In its June 9, 2011 order, the CPUC ordered the Utility to continue its efforts to determine the MAOP of its pipelines, as contemplated in the proposed compliance plan, while the Utility develops the more detailed implementation plan required to be submitted to the CPUC on August 26, 2011. Under the proposed stipulation the Utility would pay a penalty of $3 million. If there is an unexcused failure by the Utility to meet any of the milestones, the Utility would be required to pay additional penalties, up to $3 million, as the CPUC determines. The penalties would not be recoverable through rates. The proposed stipulation does not constitute an admission by the Utility of any fact alleged in the OSC or of any non-compliance or other violation of any order, rule, regulation or law.

Pending Lawsuits and Other Claims

In addition to the pending investigations and proceedings discussed above, approximately 90 tort lawsuits on behalf of approximately 320 plaintiffs, including two class action lawsuits, have been filed against PG&E Corporation and the Utility in connection with the San Bruno accident. The lawsuits seek compensation for personal injury, property damage, and other relief. The Utility has a recorded a total provision of $279 million ($220 million in 2010 and $59 million in 2011) for estimated third-party claims, and has made payments of $68 million as of June 30, 2011. The Utility estimates that it may record as much as an additional $121 million for third-party claims, for a total possible loss of $400 million. As more information becomes known, including information resulting from the pending investigations and the settlement of claims, estimates and assumptions regarding the amount of third-party liability incurred in connection with the San Bruno accident may change. (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. During the quarter ended June 30, 2011, the Utility submitted insurance claims to certain insurers for the lower (or “primary”) layers and recognized $60 million for insurance recoveries that have been deemed probable under applicable accounting standards. Although the Utility currently considers it likely that a significant portion of the costs incurred for third-party claims related to the San Bruno accident will ultimately be recovered through this 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 the parties not take any action with respect to the derivative lawsuit until further order of the court.

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

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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 Operations

The Utility estimates that it will incur costs associated with its natural gas pipeline system ranging from $350 million to $550 million in 2011. The Utility has incurred $75 million and $126 million for the three and six months ended June 30, 2011, and estimates that the remaining six months of the year will primarily include costs to perform 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 to perform other activities related to the safety of its gas pipeline system. These cost estimates could change depending on the scope and timetable of the final implementation plan approved by the CPUC in the rulemaking proceeding discussed above, the outcome of the regulatory proceedings and investigations discussed above, and new state or federal requirements that may be imposed on operators of natural gas transmission pipelines.

Additionally, as part of the implementation plan to be filed with the CPUC described above, the Utility is required to submit a proposal to allocate costs between shareholders and ratepayers to the CPUC to be considered in the CPUC’s rulemaking proceeding. PG&E Corporation and the Utility are uncertain what portion of the costs that the Utility incurs under the implementation plan or to respond to orders, recommendations, or new legislative requirements, would be recoverable through rates and the timing of any such recovery.

As described above, future operating and maintenance expenses also may be affected by the amount of third-party liability the Utility incurs as a result of the San Bruno accident. Although the Utility currently considers it likely that a significant portion of the costs incurred for third-party claims will ultimately be recovered through this insurance, it is unable to predict the amount and timing of additional insurance recoveries.

Finally, PG&E Corporation and the Utility may be required to pay fines or penalties which may have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.

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, The Utility Reform Network, Aglet Consumer Alliance, 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 8.1%, over the total 2010 authorized amount of $5.6 billion. The authorized increase for 2011 is comprised of $237 million for electric distribution, $47 million for gas distribution, and $166 million for electric generation. The authorized increase also includes $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 six months ended June 30, 2011 reflect the additional authorized base revenues from January 1, 2011. (See “Results of Operations” above.)

The CPUC decision also authorizes attrition increases of $180 million for 2012 and $185 million for 2013. Additionally, the final decision authorizes the Utility to request incremental revenue to recover state and federal income taxes related to the accelerated depreciation of the conventional meters. On July 7, 2011, the Utility filed its request for incremental revenue of $15 million over the 2011-2013 time period and expects the CPUC to act on its request later this year.

The CPUC decision also requires the Utility to file annual reports with the CPUC containing information about the Utility’s budgeted expense and capital expenditures, its recorded expenditures, and an explanation for differences between budgeted and recorded expenditures. In the Utility’s next GRC, expected to cover the period from January 1, 2014 through

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December 31, 2016, the Utility will be required to describe and justify the reprioritization of work activities and projects or the deferral of costs contemplated in the settlement agreement.

Additionally, on May 26, 2011, the CPUC adopted modifications for the electric residential service rate design portion of the Utility’s 2011 GRC proceeding. The decision changed the relative share of revenues billed and collected among lower-versus-higher usage customers, which is expected to result in lower bills and less volatility for customers in higher tiers and slightly higher bills for customer in lower tiers.

Electric Transmission Owner Rate Cases

On April 28, 2011, the Utility requested the FERC to approve an uncontested settlement of the Utility’s electric TO rate case. The settlement, if approved, will increase the annual retail revenue requirement from $875 million to $934 million with rates effective as of March 1, 2011. The Utility has recorded adequate 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. It is expected that the FERC will act on the settlement before the end of 2011.

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 six months ended June 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.

The decision also requires the Utility to file a semi-annual safety report, beginning October 1, 2011, 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. The reports will provide CPUC staff with the necessary details to: (1) monitor what storage and pipeline-related safety, reliability, and integrity capital projects and maintenance activities are being undertaken by the Utility and the amounts spent on such activities, (2) determine whether projects that have been identified by the Utility with high risk assessments are being carried out or whether other higher risk projects have been undertaken instead, (3) determine the Utility’s rationale for reprioritization of projects, and (4) monitor the status of the Utility’s compliance with federal regulations.

Finally, 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.

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 fiscal 2011 and 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. To address the shortfall that

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would result if the transfer to the General Fund is made, the utilities have requested that the CPUC permit the utilities to use unspent funds from prior program years and otherwise manage 2011 and 2012 program expenditures to absorb the shortfall. PG&E Corporation and the Utility are unable to predict how or when the CPUC may act on the utilities’ request but they do not expect that the implementation of SB 87 would have a material effect on their financial condition or results of operations.

Finally, it is uncertain whether an incentive ratemaking mechanism for the 2010 through 2012 energy efficiency program cycle and future program years will continue. Although a proposed decision was issued on November 15, 2010 that recommended modifications to the mechanism for the 2010 through 2012 program cycle, the proposed decision was withdrawn from the CPUC’s consideration on April 13, 2011. On July 28, 2011, the CPUC issued a decision to extend the statutory deadline for addressing modifications to the mechanism to October 13, 2011.

CPUC Resolution Regarding the Tax Relief Act

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 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.

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. As of June 30, 2011, the Utility has installed 8.2 million meters. 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 June 30, 2011, the Utility has incurred costs of $2.1 billion. The Utility has also recorded a provision of $36 million as of June 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 $84.4 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, 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.

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Diablo Canyon

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 and the NRC is considering whether to admit their contentions for further review in the renewal process.

Following the March 2011 earthquake and tsunami that caused significant damage to nuclear facilities in Japan, the Utility requested the NRC to delay taking final action on the Utility’s relicensing application until after the Utility completes additional seismic studies. On May 31, 2011, the NRC granted the Utility’s April 11, 2011 request to delay taking final action on the Utility’s renewal application until after the Utility completes additional seismic studies. The NRC stated that it would issue its safety evaluation report but that it would delay its environmental impact report until after the Utility completes additional seismic studies and submits a report to the NRC addressing the results of those studies. The seismic studies are expected to be completed in 2014 or 2015. 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 longer-term operation of the plant. The NRC stated that its report may change depending on the results of the seismic studies being conducted.

In addition, the NRC is considering the recommendations made by a task force the NRC appointed after the earthquake and tsunami in Japan 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 issue a report on the recommendations by January 2012. It is possible that the NRC will adopt additional regulations or issue orders to implement some of the task force’s recommendations.

PG&E Corporation and the Utility are unable to predict how long the NRC process will be delayed, whether the NRC will approve the license renewal application, whether the NRC will suspend the license renewal process, or whether the Utility will incur additional costs to comply with new regulations or orders before the NRC will approve license renewal.

Finally, in early August 2011, the NRC issued a letter finding that a report submitted by the Utility on January 7, 2011 to provide updated seismological information did not conform to current licensing standards. The Utility will shortly submit a license amendment request to address this omission. (See Item 1A. Risk Factors, below.)

Other Matters

In addition to the ongoing investigations and proceedings related to the Utility’s gas pipeline system (see “Natural Gas Pipeline Matters” above), the following investigations were initiated during the quarter ended June 30, 2011:

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. The Utility is reviewing the allegations and will provide a response to the CPUC.

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 (“PTC”) a substation when the Utility removed an almond tree orchard to prepare the site for construction. 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. (See Part II, Item 1, Legal Proceedings, below.)

PG&E Corporation and the Utility are unable to predict the outcome of these investigations.

Additionally, on July 1, 2011, the Utility filed a report with the CPUC regarding the inspection of underground enclosures where some of the Utility’s electric distribution equipment is located. The Utility filed the report as required by CPUC General Order 165 which sets the schedules for electric inspection cycles and reporting requirements. In its report, the Utility stated that an internal investigation of underground enclosure inspections determined that it was probable that some underground enclosures, primarily located in the San Jose division of the Utility’s service territory, had not been inspected as had been reported previously by Utility employees and contractors. The Utility expects to complete inspections of these underground enclosures by August 31, 2011.

PG&E Corporation and the Utility are unable to predict the outcome of these matters, how they 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.

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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 released its draft amended rules in July 2011 to implement the cap-and-trade program on a delayed basis by requiring compliance with the initial emissions cap beginning on January 1, 2013 instead of 2012.

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 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. The new legislation will become effective 90 days after the current special session of the California Legislature ends. In response to the enactment of the new RPS law, the CARB abandoned its regulatory efforts to establish a 33% renewable energy standard.

Under the new RPS law the amount of electricity delivered from renewable energy resources must equal an average of 20% of total retail sales in 2011, 2012, and 2013; at least 25% of total retail sales by December 31, 2016; and at least 33% of total retail sales by December 31, 2020. The CPUC is authorized to set interim procurement targets for all other intervening years to reflect reasonable progress toward the statutory goals. The CPUC must determine by no later than January 1, 2012, the total procurement requirement (expressed as a percentage of total retail sales) for each retail seller, including the Utility, in each future compliance period (i.e., 2011-2013, 2014-2016, 2017-2020, and each year thereafter). The CPUC opened a new rulemaking proceeding in May 2011 to begin the implementation of the new RPS law. The Utility expects that the CPUC’s rulemaking will more definitively establish the Utility’s RPS compliance obligations, including a cap on the Utility’s total mandated RPS compliance expenditures.

The new RPS legislation creates three distinct categories of renewable energy products and imposes minimum or maximum procurement targets for each of these product categories that must be met in each future compliance period. With certain exceptions, these categorical requirements will only apply to contracts that are entered into after June 1, 2010. The new law imposes limits on the types of tradable renewable energy credits (“REC”s) that can be used to satisfy the categorical requirements and contains new restrictions on the Utility’s ability to carry forward (or “bank”) RPS volumes from contracts with terms of less than ten years. The new legislation requires that the CPUC approve applications for utility-owned renewable generation up to a certain energy-based cap, provided that the CPUC finds that the cost of the application is reasonable and meets other conditions. The costs of utility-owned renewable generation projects will be subject to traditional cost-of-service ratemaking treatment.

Under the new RPS law, the CPUC must waive enforcement of the RPS requirements as to any particular retail seller if it finds that certain specified circumstances beyond the control of the retail seller will prevent compliance and the retail seller has met certain other conditions, including demonstrating that the retail seller has taken all reasonable actions under its control to achieve full compliance.

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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 will apply to the new RPS requirements.

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 (“Water 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 Water 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 Water 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 Water 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 Water 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. (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 legal proceedings.)

LEGAL MATTERS

In addition to the provision made for claims related to the San Bruno 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 Matters” 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 risks 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

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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 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 the 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 $11 million at June 30, 2011. The Utility’s high, low, and average values-at-risk during the 12 months ended June 30, 2011 were $20 million, $8 million, and $12 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 June 30, 2011, if interest rates changed by 1% for all current PG&E Corporation and the 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

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counterparties when current net receivables and replacement cost exposure exceed contractually specified limits.

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 June 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%
June 30, 2011		$288		$16		$272		2		$200
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. 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. Actual results may differ materially from these estimates and assumptions.

For the six months ended June 30, 2011, there were no changes in the methodology for computing critical accounting estimates and no material changes to the important assumptions underlying the critical accounting estimates.

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

Amendments to Fair Value Measurement and Disclosure 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 how to adopt the accounting standards update.

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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 Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) “Risk Management Activities” above).

ITEM 4. CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of June 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 June 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 matters, see Note 10 of the Notes to the 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 California Water Board and the Utility regarding the status of the 2003 settlement agreement concerning a proposed draft Cease and Desist Order issued by the Water 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 Quality Control Board (“RWQCB”) 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 RWQCB 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. In June 2011, the RWQCB issued a draft clean up and abatement order to require the Utility to provide replacement water supplies to all residences near the chromium plume (within one mile of the plume or potentially farther away, depending on whether the residential well water exceeds the current public health goal for chromium levels). The Utility opposes the draft order because the water supplies for all of the residences in question comply with current California and federal drinking water standards. Other interested parties, including the California Department of Public Health and the Association of California Water Agencies, also have submitted comments opposing the draft order. The RWQCB will consider the comments before deciding how to proceed. 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.

San Bruno Accident

Litigation Related to the San Bruno Accident

Approximately 90 tort lawsuits on behalf of approximately 320 plaintiffs, including two class action lawsuits, have been filed against PG&E Corporation and the Utility. These lawsuits seek compensation for personal injury and property damage and seek other relief. 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. The judge has ordered that the parties not take any action with respect to the derivative lawsuit 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 will cooperate fully 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 Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations (“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 (“PTC”) 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. 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 are supplemented and updated as follows:

The ultimate amount of costs, penalties, and third –party liability the Utility incurs in connection with the San Bruno accident and the natural gas transmission pipeline matters described above could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

In addition to the pending NTSB investigation of the San Bruno accident, on February 24, 2011, the CPUC initiated a formal investigation pertaining to safety recordkeeping for the Utility’s gas transmission pipeline that ruptured in San Bruno on September 9, 2010, as well as for its entire gas transmission system. If the CPUC determines that the Utility violated safety law standards with respect to its gas system recordkeeping, the CPUC may impose penalties on the Utility. If supported by the evidence, the CPUC stated that it will consider ordering daily fines for a significant period of time. (See MD&A “Natural Gas Pipeline Matters” above.)

On June 8, 2011, the independent review panel appointed by the CPUC to investigate the San Bruno accident issued its report. The panel’s report concludes that “the explosion of the pipeline at San Bruno was a consequence of multiple weaknesses in PG&E’s management and oversight of the safety of its gas transmission system.” The panel recommends that the Utility implement various organizational changes and take other steps to improve customer safety and enhance reliability. On June 9, 2011, the CPUC ordered the Utility to submit an implementation plan to validate the MAOP of its gas transmission pipelines through hydrostatic pressure tests or to replace pipelines. The plan must be filed by August 26, 2011 along with a proposal to allocate the costs between customers and the Utility’s shareholders. The Utility may be required to bear a material amount of the implementation costs. Costs may also be affected by new federal or state pipeline regulations that may be adopted. The Utility also may incur third-party liability related to service disruptions caused by pressure reductions on its natural gas transmission pipelines.

Also, 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. (See MD&A “Natural Gas Pipeline Matters” above.)

During the quarter ended June 30, 2011, the Utility provided extensive information to the CPUC about its natural gas transmission system including the records related to the San Bruno accident, records related to weld defects, and safety risk assessments. On June 30, 2011, the Utility submitted the results of its review of class location designations for its pipelines. Under federal and state regulations, the class location designation is used to determine the pipeline’s MAOP. This review of class location designations has indicated that some pipelines had or may have an MAOP higher than appropriate for their current class location designations.

PG&E Corporation and the Utility are unable to predict the outcome of these matters, whether the CPUC will commence additional proceedings or investigations of the Utility’s natural gas operations, and whether such additional proceedings or investigations will result in further regulatory orders or the imposition of fines or penalties on the Utility.

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The CPUC may not approve the proposed resolution of its investigation of the Rancho Cordova accident and the Utility could incur penalties that are higher than the amount included in the proposed resolution.

The CPUC is considering a proposed resolution of its investigation into the Rancho Cordova accident that provides that the Utility will pay a penalty of $26 million within twenty days after CPUC approval. (See MD&A “Natural Gas Pipeline Matters” above.) If the CPUC does not approve the 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 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. PG&E Corporation and the Utility are unable to predict how or when the CPUC may fully implement the requirements in the new law.

The CPUC also has opened an investigation into the Utility’s compliance with resource adequacy requirements for March, April, and July 2010 and stated that it may impose a penalty on the Utility. (See MD&A “Regulatory Matters – Other Matters” above.)

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 senior level agency task force to conduct a systematic review of NRC processes and regulations and evaluate whether enhancements or new regulations are needed. The NRC is reviewing the task force’s recommendations published on July 13, 2011. There has been increased public concern expressed about the safety of the Utility’s Diablo Canyon nuclear generation facilities located along the coastline in San Luis Obispo, California, which is in close proximity to active earthquake fault lines. On May 31, 2011, the NRC responded to the Utility’s request to defer taking final action on the Utility’s license renewal application by agreeing to delay issuance of the environmental impact report until after the Utility completes new seismic studies and submits the results to the NRC. The seismic studies are expected to be completed in 2014 or 2015. (See MD&A “Regulatory Matters – Diablo Canyon ” above.)

The Utility may be required to incur additional capital expenditures and other expenses to address any new seismic safety requirements, backup power requirements, or other requirements that the NRC may impose following its regulatory review or following the submission of the completed seismic studies for Diablo Canyon. The NRC may order the Utility to cease its nuclear operations until any safety concerns are addressed or the NRC may determine that the safety concerns cannot be addressed and order the Utility to cease operating Diablo Canyon. Alternatively, the Utility may determine that the safety concerns cannot be remedied in a feasible and economic manner and voluntarily cease operations at Diablo Canyon. The NRC has issued a letter finding that a Utility report analyzing seismological information did not conform to current licensing standards. The Utility will shortly submit a license amendment request to address this omission. PG&E Corporation and the Utility are uncertain how this issue will be resolved. The NRC could require the Utility to take additional action to address the non-conformance including ordering an assessment of whether it is safe to continue operating Diablo Canyon. Further, depending on the results of the license renewal process, the NRC could deny the license renewal applications requiring nuclear operations to cease when the current licenses expire.

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 determines that it cannot comply with such new laws or regulations in a feasible and economic manner it may voluntarily cease operations at Diablo Canyon.

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If the Utility is unable to recover costs it incurs to respond to safety concerns or if the Utility ceased its nuclear operations, PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows could be materially affected.

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

During the quarter ended June 30, 2011, PG&E Corporation made equity contributions totaling $190 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 June 30, 2011.

Issuer Purchases of Equity Securities

During the quarter ended June 30, 2011, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the quarter ended June 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 six months ended June 30, 2011 was 3.09. The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the six months ended June 30, 2011 was 3.02. 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 six months ended June 30, 2011 was 2.93. 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

4.1	Thirteenth Supplemental Indenture dated as of May 13, 2011, relating to the issuance of $300,000,000 Aggregate principal amount of Pacific Gas and Electric Company’s 4.25% Senior Notes due May 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 13, 2011 (File No. 1-2348, Exhibit 4.1)
10.1	Credit Agreement, dated May 31, 2011, among (1) PG&E Corporation, as borrower, (2) Bank of America, N.A. as administrative agent and a lender, (3) Citibank, N.A., and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank
10.2	Credit Agreement, dated May 31, 2011, among (1) Pacific Gas and Electric Company, as borrower, (2) Citibank, N.A., as administrative agent and lender, (3) JPMorgan Chase Bank, N.A., and Bank of America, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank
*10.3	Restricted Stock Unit Agreement between C. Lee Cox and PG&E Corporation dated May 12, 2011
*10.4	Restricted Stock Unit Agreement between Christopher P. Johns and PG&E Corporation dated May 9, 2011
*10.5	Severance Agreement between Pacific Gas and Electric Company and John S. Keenan dated April 5, 2011
*10.6	Settlement Agreement and Release between Pacific Gas and Electric Company and John S. Keenan dated April 5, 2011
*10.7	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Karen Austin dated April 29, 2011
*10.8	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Nick Stavropoulos dated April 29, 2011
*10.9	Form of Restricted Stock Unit Agreement for 2011 grants to directors under the PG&E Corporation 2006 Long-Term Incentive Plan
*10.10	PG&E Corporation 2006 Long-Term Incentive Plan, as amended through June 15, 2011
*10.11	PG&E Corporation 2005 Supplemental Retirement Savings Plan effective as of August 1, 2011
*10.12	Separation Agreement between Pacific Gas and Electric Company and Edward Salas as approved by the PG&E Corporation Compensation Committee on June 14, 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

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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.

*** Pursuant to Rule 406T of SEC Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under these sections.

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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

SARA A. CHERRY

Sara A. Cherry

Vice President, Finance and Chief Financial Officer

(duly authorized officer and principal financial officer)

Dated: August 4, 2011

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EXHIBIT INDEX

4.1	Thirteenth Supplemental Indenture dated as of May 13, 2011, relating to the issuance of $300,000,000 Aggregate principal amount of Pacific Gas and Electric Company’s 4.25% Senior Notes due May 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 13, 2011 (File No. 1-2348, Exhibit 4.1)
10.1	Credit Agreement, dated May 31, 2011, among (1) PG&E Corporation, as borrower, (2) Bank of America, N.A. as administrative agent and a lender, (3) Citibank, N.A., and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank
10.2	Credit Agreement, dated May 31, 2011, among (1) Pacific Gas and Electric Company, as borrower, (2) Citibank, N.A., as administrative agent and lender, (3) JPMorgan Chase Bank, N.A., and Bank of America, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank
*10.3	Restricted Stock Unit Agreement between C. Lee Cox and PG&E Corporation dated May 12, 2011
*10.4	Restricted Stock Unit Agreement between Christopher P. Johns and PG&E Corporation dated May 9, 2011
*10.5	Severance Agreement between Pacific Gas and Electric Company and John S. Keenan dated April 5, 2011
*10.6	Settlement Agreement and Release between Pacific Gas and Electric Company and John S. Keenan dated April 5, 2011
*10.7	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Karen Austin dated April 29, 2011
*10.8	Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Nick Stavropoulos dated April 29, 2011
*10.9	Form of Restricted Stock Unit Agreement for 2011 grants to directors under the PG&E Corporation 2006 Long-Term Incentive Plan
*10.10	PG&E Corporation 2006 Long-Term Incentive Plan, as amended through June 15, 2011
*10.11	PG&E Corporation 2005 Supplemental Retirement Savings Plan effective as of August 1, 2011
*10.12	Separation Agreement between Pacific Gas and Electric Company and Edward Salas as approved by the PG&E Corporation Compensation Committee on June 14, 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

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	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.

*** Pursuant to Rule 406T of SEC Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under these sections.

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