10-Q

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 March 31, 2012

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 1-2348	PG&E Corporation Pacific Gas and Electric Company	California California	94-3234914 94-0742640
Pacific Gas and Electric Company 77 Beale Street P.O. Box 770000 San Francisco, California 94177		PG&E Corporation 77 Beale Street P.O. Box 770000 San Francisco, California 94177
________________________________________		______________________________________
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 April 24, 2012:
PG&E Corporation	422,320,110
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 MARCH 31, 2012

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 Statements of Comprehensive Income	3
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Cash Flows	6
	Pacific Gas and Electric Company
	Condensed Consolidated Statements of Income	7
	Condensed Consolidated Statements of Comprehensive Income	8
	Condensed Consolidated Balance Sheets	9
	Condensed Consolidated Statements of Cash Flows	11
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1: Organization and Basis of Presentation	12
	NOTE 2: Significant Accounting Policies	12
	NOTE 3: Regulatory Assets, Liabilities, and Balancing Accounts	15
	NOTE 4: Debt	18
	NOTE 5: Equity	19
	NOTE 6: Earnings Per Share	20
	NOTE 7: Derivatives	20
	NOTE 8: Fair Value Measurements	23
	NOTE 9: Resolution of Remaining Chapter 11 Disputed Claims	28
	NOTE 10: Commitments and Contingencies	29
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	47
	Contractual Commitments	52
	Capital Expenditures	52
	Natural Gas Matters	52
	Regulatory Matters	56
	Environmental Matters	58
	Off-Balance Sheet Arrangements	60
	Contingencies	60
	Risk Management Activities	60
	Critical Accounting Policies	62
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	63
ITEM 4.	CONTROLS AND PROCEDURES	63
PART II.	OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	64
ITEM 1A.	RISK FACTORS	65
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	65
ITEM 5.	OTHER INFORMATION	66
ITEM 6.	EXHIBITS	67
SIGNATURES		68

1

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	(Unaudited)
	Three Months Ended March 31,
(in millions, except per share amounts)	2012			2011
Operating Revenues
Electric		$ 2,772			$ 2,617
Natural gas		869			980
Total operating revenues		3,641			3,597
Operating Expenses
Cost of electricity		859			888
Cost of natural gas		343			508
Operating and maintenance		1,368			1,226
Depreciation, amortization, and decommissioning		584			491
Total operating expenses		3,154			3,113
Operating Income		487			484
Interest income		1			2
Interest expense		(174	)		(177	)
Other income, net		26			17
Income Before Income Taxes		340			326
Income tax provision		104			124
Net Income		236			202
Preferred stock dividend requirement of subsidiary		3			3
Income Available for Common Shareholders		$ 233			$ 199
Weighted Average Common Shares Outstanding, Basic		414			396
Weighted Average Common Shares Outstanding, Diluted		416			397
Net Earnings Per Common Share, Basic		$ 0.56			$ 0.50
Net Earnings Per Common Share, Diluted		$ 0.56			$ 0.50
Dividends Declared Per Common Share		$ 0.46			$ 0.46

See accompanying Notes to the Condensed Consolidated Financial Statements.

2

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2012			2011
Net Income		$ 236			$ 202
Other comprehensive income
Pension and other postretirement benefit plans
Unrecognized prior service credit (net of income tax of $5 in 2012 and 2011)		6			10
Unrecognized net gain (net of income tax of $11 and $6 in 2012 and 2011, respectively)		21			7
Unrecognized net transition obligation (net of income tax of $2 in 2012 and 2011)		4			4
Transfer to regulatory account (net of income tax of $15 and $8 in 2012 and 2011, respectively)		(21	)		(12	)
Other comprehensive income		10			9
Comprehensive income		246			211
Preferred stock dividend requirement of subsidiary		3			3
Comprehensive income attributable to common shareholders		$ 243			$ 208

See accompanying Notes to the Condensed Consolidated Financial Statements.

3

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
(in millions)	March 31, 2012			December 31, 2011
ASSETS
Current Assets
Cash and cash equivalents		$ 257			$ 513
Restricted cash ($56 and $51 related to energy recovery bonds at March 31, 2012 and December 31, 2011)		385			380
Accounts receivable
Customers (net of allowance for doubtful accounts of $80 and $81 at March 31, 2012 and December 31, 2011)		926			992
Accrued unbilled revenue		614			763
Regulatory balancing accounts		1,425			1,082
Other		817			839
Regulatory assets ($227 and $336 related to energy recovery bonds at March 31, 2012 and December 31, 2011)		1,024			1,090
Inventories
Gas stored underground and fuel oil		97			159
Materials and supplies		273			261
Income taxes receivable		154			183
Other		194			218
Total current assets		6,166			6,480
Property, Plant, and Equipment
Electric		36,329			35,851
Gas		12,015			11,931
Construction work in progress		2,011			1,770
Other		1			15
Total property, plant, and equipment		50,356			49,567
Accumulated depreciation		(16,107	)		(15,912	)
Net property, plant, and equipment		34,249			33,655
Other Noncurrent Assets
Regulatory assets		6,565			6,506
Nuclear decommissioning trusts		2,134			2,041
Income taxes receivable		412			386
Other		662			682
Total other noncurrent assets		9,773			9,615
TOTAL ASSETS		$ 50,188			$ 49,750

See accompanying Notes to the Condensed Consolidated Financial Statements.

4

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
(in millions, except share amounts)	March 31, 2012			December 31, 2011
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings		$ 1,401			$ 1,647
Long-term debt, classified as current		50			50
Energy recovery bonds, classified as current		321			423
Accounts payable
Trade creditors		873			1,177
Disputed claims and customer refunds		658			673
Regulatory balancing accounts		641			374
Other		494			420
Interest payable		798			843
Income taxes payable		110			110
Deferred income taxes		160			196
Other		1,769			1,836
Total current liabilities		7,275			7,749
Noncurrent Liabilities
Long-term debt		11,767			11,766
Regulatory liabilities		4,927			4,733
Pension and other postretirement benefits		3,464			3,396
Asset retirement obligations		1,620			1,609
Deferred income taxes		6,190			6,008
Other		2,133			2,136
Total noncurrent liabilities		30,101			29,648
Commitments and Contingencies (Note 10)
Equity
Shareholders’ Equity
Preferred stock		—			—
Common stock, no par value, authorized 800,000,000 shares, 421,777,738 shares outstanding at March 31, 2012 and 412,257,082 shares outstanding at December 31, 2011		8,011			7,602
Reinvested earnings		4,752			4,712
Accumulated other comprehensive loss		(203	)		(213	)
Total shareholders’ equity		12,560			12,101
Noncontrolling Interest – Preferred Stock of Subsidiary		252			252
Total equity		12,812			12,353
TOTAL LIABILITIES AND EQUITY		$ 50,188			$ 49,750

See accompanying Notes to the Condensed Consolidated Financial Statements.

5

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2012			2011
Cash Flows from Operating Activities
Net income		$ 236			$ 202
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		584			491
Allowance for equity funds used during construction		(27	)		(20	)
Deferred income taxes and tax credits, net		146			99
Other		73			44
Effect of changes in operating assets and liabilities:
Accounts receivable		221			35
Inventories		50			65
Accounts payable		(213	)		182
Income taxes receivable/payable		29			34
Other current assets and liabilities		(70	)		(205	)
Regulatory assets, liabilities, and balancing accounts, net		(171	)		(10	)
Other noncurrent assets and liabilities		73			171
Net cash provided by operating activities		931			1,088
Cash Flows from Investing Activities
Capital expenditures		(1,094	)		(945	)
(Increase) decrease in restricted cash		(5	)		132
Proceeds from sales and maturities of nuclear decommissioning trust investments		351			726
Purchases of nuclear decommissioning trust investments		(370	)		(735	)
Other		25			(61	)
Net cash used in investing activities		(1,093	)		(883	)
Cash Flows from Financing Activities
Net (repayments) issuances of commercial paper, net of discount of $1 in 2012 and in 2011		(245	)		415
Long-term debt matured		—			(500	)
Energy recovery bonds matured		(102	)		(97	)
Common stock issued		387			82
Common stock dividends paid		(182	)		(174	)
Other		48			18
Net used in financing activities		(94	)		(256	)
Net change in cash and cash equivalents		(256	)		(51	)
Cash and cash equivalents at January 1		513			291
Cash and cash equivalents at March 31		$ 257			$ 240
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized		$ (204	)		$ (215	)
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid		$ 193			$ 181
Capital expenditures financed through accounts payable		276			174
Noncash common stock issuances		6			6
Terminated capital leases		136			-

See accompanying Notes to the Condensed Consolidated Financial Statements.

6

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2012			2011
Operating Revenues
Electric		$ 2,771			$ 2,616
Natural gas		869			980
Total operating revenues		3,640			3,596
Operating Expenses
Cost of electricity		859			888
Cost of natural gas		343			508
Operating and maintenance		1,366			1,226
Depreciation, amortization, and decommissioning		584			490
Total operating expenses		3,152			3,112
Operating Income		488			484
Interest income		1			2
Interest expense		(168	)		(171	)
Other income, net		23			17
Income Before Income Taxes		344			332
Income tax provision		113			131
Net Income		231			201
Preferred stock dividend requirement		3			3
Income Available for Common Stock		$ 228			$ 198

See accompanying Notes to the Condensed Consolidated Financial Statements.

7

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2012			2011
Net income		$ 231			$ 201
Other comprehensive income (loss)
Pension and other postretirement benefit plans
Unrecognized prior service credit (net of income tax of $5 in 2012 and 2011)		6			10
Unrecognized net gain (net of income tax of $11 and $6 in 2012 and 2011, respectively)		21			7
Unrecognized net transition obligation (net of income tax of $2 in 2012 and 2011)		4			4
Transfer to regulatory account (net of income tax of $15 and $8 in 2012 and 2011, respectively)		(21	)		(12	)
Other comprehensive income		10			9
Comprehensive income		$ 241			$ 210

See accompanying Notes to the Condensed Consolidated Financial Statements.

8

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	March 31,			December 31,
(in millions)	2012			2011
ASSETS
Current Assets
Cash and cash equivalents		$ 45			$ 304
Restricted cash ($56 and $51 related to energy recovery bonds at March 31, 2012 and December 31, 2011, respectively)		385			380
Accounts receivable
Customers (net of allowance for doubtful accounts of $80 and $81 at March 31, 2012 and December 31, 2011)		926			992
Accrued unbilled revenue		614			763
Regulatory balancing accounts		1,425			1,082
Other		821			840
Regulatory assets ($227 and $336 related to energy recovery bonds at March 31, 2012 and December 31, 2011, respectively)		1,024			1,090
Inventories
Gas stored underground and fuel oil		97			159
Materials and supplies		273			261
Income taxes receivable		212			242
Other		188			213
Total current assets		6,010			6,326
Property, Plant, and Equipment
Electric		36,329			35,851
Gas		12,015			11,931
Construction work in progress		2,011			1,770
Total property, plant, and equipment		50,355			49,552
Accumulated depreciation		(16,106	)		(15,898	)
Net property, plant, and equipment		34,249			33,654
Other Noncurrent Assets
Regulatory assets		6,565			6,506
Nuclear decommissioning trusts		2,134			2,041
Income taxes receivable		413			384
Other		330			331
Total other noncurrent assets		9,442			9,262
TOTAL ASSETS		$ 49,701			$ 49,242

See accompanying Notes to the Condensed Consolidated Financial Statements.

9

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	March 31,			December 31,
(in millions, except share amounts)	2012			2011
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings		$ 1,401			$ 1,647
Long-term debt, classified as current		50			50
Energy recovery bonds, classified as current		321			423
Accounts payable
Trade creditors		873			1,177
Disputed claims and customer refunds		658			673
Regulatory balancing accounts		641			374
Other		522			417
Interest payable		788			838
Income taxes payable		118			118
Deferred income taxes		165			199
Other		1,562			1,628
Total current liabilities		7,099			7,544
Noncurrent Liabilities
Long-term debt		11,418			11,417
Regulatory liabilities		4,927			4,733
Pension and other postretirement benefits		3,391			3,325
Asset retirement obligations		1,620			1,609
Deferred income taxes		6,347			6,160
Other		2,071			2,070
Total noncurrent liabilities		29,774			29,314
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 March 31, 2012 and December 31, 2011		1,322			1,322
Additional paid-in capital		4,181			3,796
Reinvested earnings		7,259			7,210
Accumulated other comprehensive loss		(192	)		(202	)
Total shareholders’ equity		12,828			12,384
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$ 49,701			$ 49,242

See accompanying Notes to the Condensed Consolidated Financial Statements.

10

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Three Months Ended
	March 31,
(in millions)	2012			2011
Cash Flows from Operating Activities
Net income		$ 231			$ 201
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		584			490
Allowance for equity funds used during construction		(27	)		(20	)
Deferred income taxes and tax credits, net		153			99
Other		57			29
Effect of changes in operating assets and liabilities:
Accounts receivable		218			69
Inventories		50			65
Accounts payable		(182	)		190
Income taxes receivable/payable		30			34
Other current assets and liabilities		(69	)		(196	)
Regulatory assets, liabilities, and balancing accounts, net		(171	)		(10	)
Other noncurrent assets and liabilities		75			144
Net cash provided by operating activities		949			1,095
Cash Flows from Investing Activities
Capital expenditures		(1,094	)		(945	)
(Increase) decrease in restricted cash		(5	)		132
Proceeds from sales and maturities of nuclear decommissioning trust investments		351			726
Purchases of nuclear decommissioning trust investments		(370	)		(735	)
Other		3			7
Net cash used in investing activities		(1,115	)		(815	)
Cash Flows from Financing Activities
Net (repayments) issuances of commercial paper, net of discount of $1 in 2012 and in 2011		(245	)		415
Long-term debt matured		-			(500	)
Energy recovery bonds matured		(102	)		(97	)
Preferred stock dividends paid		(3	)		(4	)
Common stock dividends paid		(179	)		(179	)
Equity contribution		385			65
Other		51			21
Net cash used in financing activities		(93	)		(279	)
Net change in cash and cash equivalents		(259	)		1
Cash and cash equivalents at January 1		304			51
Cash and cash equivalents at March 31		$ 45			$ 52
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized		$ (204	)		$ (215	)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable		$ 276			$ 174
Terminated capital leases		136			-

See accompanying Notes to the Condensed Consolidated Financial Statements.

11

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

PG&E Corporation is a holding company that conducts its business 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 statements 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, 2011 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 2011 Annual Report on Form 10-K filed with the SEC on February 16, 2012. PG&E Corporation’s and the Utility’s combined 2011 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 “2011 Annual Report.” This quarterly report should be read in conjunction with the 2011 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, legal and regulatory contingencies, environmental remediation liabilities, asset retirement obligations (“ARO”), and pension and other postretirement benefit plans 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: NEW AND SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies used by PG&E Corporation and the Utility are discussed in Note 2 of the Notes to the Consolidated Financial Statements in the 2011 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”) and 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 have elected that certain of the trusts underlying these plans be treated under the Internal Revenue Code (“Code”) as qualified trusts. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain Code limitations. PG&E Corporation and the Utility use a December 31 measurement date for all plans.

12

Net periodic benefit cost as reflected in PG&E Corporation’s Condensed Consolidated Statements of Income for the three months ended March 31, 2012 and 2011 is as follows:

	Pension Benefits						Other Benefits
	Three Months Ended March 31,						Three Months Ended March 31,
(in millions)	2012			2011			2012			2011
Service cost for benefits earned	$	99		$	82		$	12		$	11
Interest cost		164			164			21			23
Expected return on plan assets		(149	)		(167	)		(19	)		(20	)
Amortization of transition obligation		-			-			6			6
Amortization of prior service cost		5			9			6			6
Amortization of unrecognized loss		31			12			1			1
Net periodic benefit cost		150			100			27			27
Less: transfer to regulatory account (1)		(75	)		(36	)		-			-
Total	$	75		$	64		$	27		$	27

⁽¹⁾  The Utility recorded $75 million and $36 million for the three months ended March 31, 2012 and 2011, 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 and the Utility for the information disclosed above.

Variable Interest Entities

PG&E Corporation and the Utility evaluate whether any entity is a variable interest entity (“VIE”) that could require consolidation. PG&E Corporation and the Utility use a qualitative approach to determine who has a controlling financial interest in a VIE and perform ongoing assessments of whether an entity is the primary beneficiary of a VIE.

PG&E Corporation and the Utility are required to consolidate any entities that they control. In most cases, control can be determined based on majority ownership or voting interests. However, for certain entities, control is difficult to discern based on ownership or voting interests alone. These entities are referred to as VIEs. A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise has a controlling financial interest if it has the obligation to absorb expected losses or receive expected gains that could potentially be significant to a VIE and the power to direct the activities that are most significant to a VIE’s economic performance. An enterprise that has a controlling financial interest is known as the VIE’s primary beneficiary and is required to consolidate the VIE.

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. In determining whether the Utility has a controlling financial interest in a VIE, the Utility assesses whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns, as a result of the power purchase agreement. This assessment includes an evaluation of how the risks and rewards associated with the power plant’s activities are absorbed by variable interest holders, as well as an analysis of the variability in the VIE’s gross margin and the impact of the power purchase agreement on the gross margin. For each variable interest, the Utility assesses whether it has the power to direct the activities of the power plant that most directly impact the VIE’s economic performance.

The Utility can hold a variable interest in entities that own power plants that generate electricity for sale to the Utility under power purchase agreements. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility utilizing various technologies such as natural gas, wind, solar photovoltaic, solar thermal, and hydroelectric. Under each of these power purchase agreements, the Utility is obligated to purchase electricity or capacity, or both, from the VIE. The Utility does not provide any other support to these VIEs, and the Utility’s financial exposure is limited to the amount it pays for delivered electricity and capacity. (See Note 10 below.) The Utility does not have the power to direct the activities that are most significant to these VIE’s economic performance. This assessment considers 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. As a result, the Utility does not have a controlling financial interest in any of these VIEs. Therefore, at March 31, 2012, the Utility was not the primary beneficiary of, and did not consolidate, any of these VIEs.

13

The Utility continued to consolidate PG&E Energy Recovery Funding LLC (“PERF”) at March 31, 2012, as the Utility is the primary beneficiary of PERF. In 2005, PERF was formed as a wholly owned subsidiary of the Utility to issue energy recovery bonds (“ERB”s) in connection with the settlement agreement entered into between PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the remaining disputed claims made by electricity suppliers in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11 Settlement Agreement”). The Utility has a controlling financial interest in PERF since 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, which was an activity that was significant to PERF’s economic performance. The assets of PERF were $382 million at March 31, 2012 and primarily consisted of assets related to ERBs, which are included in other current assets – regulatory assets in the Condensed Consolidated Balance Sheets. The liabilities of PERF were $321 million at March 31, 2012 and consisted of ERBs, which are included in current liabilities in the Condensed Consolidated Balance Sheets. (See Note 4 below.)

As of March 31, 2012, PG&E Corporation 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 $396 million to these companies in exchange for the right to receive benefits from local rebates, federal 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 March 31, 2012, PG&E Corporation had made total payments of $360 million under these agreements and received $160 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 March 31, 2012. 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 agreements is generally limited to its lease payments and investment contributions to these companies.

Adoption of New Accounting Standards

Amendments to Fair Value Measurement Requirements

On January 1, 2012, PG&E Corporation and the Utility adopted an accounting standards update (“ASU”) that requires additional fair value measurement disclosures. For fair value measurements that use significant unobservable inputs, quantitative disclosures of the inputs and qualitative disclosures of the valuation processes are required. For items not measured at fair value in the balance sheet but whose fair value is disclosed, disclosures of the fair value hierarchy level, the fair value measurement techniques used, and the inputs used in the fair value measurements are required. In addition, the ASU permits 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 ASU refines when an entity should, and should not, apply certain premiums and discounts to a fair value measurement. The adoption of the ASU is reflected in Note 8 below and did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

Presentation of Comprehensive Income

On January 1, 2012, PG&E Corporation and the Utility adopted ASUs that require an entity to present either (1) a single statement of comprehensive income or loss or (2) a separate statement of comprehensive income or loss that follows a statement of income or loss. A single statement of comprehensive income or loss is 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 separate statement of comprehensive income or loss immediately follows a statement of income or loss and is comprised of net income or loss, other comprehensive income and losses, total other comprehensive income or loss, and total comprehensive income or loss. Furthermore, the ASUs prohibit an entity from presenting other comprehensive income and losses in a statement of equity only. The adoption of the ASUs resulted in the addition of the Condensed Consolidated Statements of Comprehensive Income to PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.

14

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 regulatory assets, 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 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 records differences between customer billings and the Utility’s authorized revenue requirements since a significant portion of recovery is independent, or “decoupled,” from the volume of electricity and natural gas sales. The Utility also records differences between incurred costs and customer billings or authorized revenue requirements meant to recover those costs. To the extent these differences are probable of recovery or refund, the Utility records a regulatory balancing account asset or liability, respectively.

To the extent that portions of the Utility’s operations cease to be subject to cost-of-service rate regulation, or recovery is no longer probable as a result of changes in regulations or other reasons, the related regulatory assets and liabilities are written-off.

Regulatory Assets

Current Regulatory Assets

At March 31, 2012 and December 31, 2011, the Utility had current regulatory assets of $1,024 million and $1,090 million, respectively, primarily consisting of price risk management regulatory assets, the Utility’s retained generation regulatory assets, the electromechanical meters regulatory asset, and the ERB regulatory asset. The current portion of price risk management regulatory assets of $488 million represents the expected future recovery of unrealized losses related to price risk management derivative instruments over the next 12 months. (See Note 7 below.) The Utility expects to recover these losses as part of its energy procurement costs as they are realized over the next 12 months. The current portion of the Utility’s retained generation regulatory assets of $62 million represents the amortization of the underlying generation facilities expected to be recovered over the next 12 months. (See “Long-Term Regulatory Assets” below.) The current portion of the electromechanical meters regulatory asset of $50 million represents the net book value of electromechanical meters expected to be recovered over the next 12 months. (See “Long-Term Regulatory Assets” below). The ERB regulatory asset of $227 million represents the refinancing of a regulatory asset provided for in the Chapter 11 Settlement Agreement. (See Note 4 below.) The Utility expects to fully recover this asset by the end of 2012, when the ERBs mature.

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

	Balance at
(in millions)	March 31, 2012		December 31, 2011
Pension benefits	$	2,939	$	2,899
Deferred income taxes		1,483		1,444
Utility retained generation		598		613
Environmental compliance costs		535		520
Price risk management		354		339
Electromechanical meters		234		247
Unamortized loss, net of gain, on reacquired debt		157		163
Other		265		281
Total long-term regulatory assets	$	6,565	$	6,506

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 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 2011 Annual Report.)

15

The regulatory asset for deferred income taxes represents 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. Based on current regulatory ratemaking and income tax laws, the Utility expects to recover the regulatory asset over the average plant depreciation lives of 1 to 44 years.

In connection with the 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 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 environmental compliance costs represents 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.)

The regulatory asset for price risk management represents the expected future recovery of unrealized losses related to price risk management derivative instruments beyond the next 12 months. The Utility expects to recover these losses as they are realized over the next 10 years. (See Note 7 below.)

The regulatory asset for electromechanical meters represents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter™ devices. The Utility expects to recover the regulatory asset over the next four years.

The regulatory asset for unamortized loss, net of gain, on reacquired debt represents the expected future recovery of 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 14 years, which is the remaining amortization period of the reacquired debt. The Utility expects to fully recover these costs by 2026.

At March 31, 2012 and December 31, 2011, “other” primarily consisted of regulatory assets related to ARO expenses for the decommissioning of the Utility’s fossil fuel-fired generation facilities that are probable of future recovery through rates, costs that the Utility incurred in terminating a 30-year power purchase agreement that are amortized and collected in rates through September 2014, and costs incurred related to the Utility’s plan of reorganization under Chapter 11 that became effective in April 2004 and are amortized and collected in rates through April 2034.

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

Regulatory Liabilities

Current Regulatory Liabilities

At March 31, 2012 and December 31, 2011, the Utility had current regulatory liabilities of $83 million and $161 million, respectively, primarily consisting of amounts that the Utility expects to refund to customers under electricity supplier settlement agreements. (See Note 9 below.) Current regulatory liabilities are included within current liabilities – other in the Condensed Consolidated Balance Sheets.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

	Balance at
(in millions)	March 31, 2012		December 31, 2011
Cost of removal obligations		$ 3,524		$ 3,460
Recoveries in excess of AROs		707		611
Public purpose programs		526		499
Other		170		163
Total long-term regulatory liabilities		$ 4,927		$ 4,733

The regulatory liability for cost of removal obligations represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.

16

The regulatory liability for recoveries in excess of AROs represents the cumulative differences between ARO expenses and amounts collected in rates primarily for the decommissioning of the Utility’s nuclear power facilities. Decommissioning costs recovered through rates are primarily placed in nuclear decommissioning trusts. The regulatory liability also represents the deferral of realized and unrealized gains and losses on the nuclear decommissioning trust investments. (See Note 8 below.)

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, primarily related to energy efficiency programs designed to encourage the manufacture, design, distribution, and customer-use of energy efficient appliances and other energy-using products, the California Solar Initiative program to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties, and the Self-Generation Incentive program to promote distributed generation technologies installed on the customer’s side of the utility meter.

At March 31, 2012 and December 31, 2011, “other” 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 and price risk management regulatory liabilities representing the expected future refund to customers 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 collected from or refunded to customers through authorized rate adjustments over the next 12 months. Regulatory balancing accounts that the Utility does not expect to collect or refund over the next 12 months are included in other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Condensed Consolidated Balance Sheets.

Current Regulatory Balancing Accounts, Net

	Receivable (Payable)
	Balance at
(in millions)	March 31, 2012			December 31, 2011
Distribution revenue adjustment mechanism		$ 422			$ 223
Utility generation		412			241
Public purpose programs		96			97
Hazardous substance		56			57
Gas fixed cost		(101	)		16
Energy recovery bonds		(108	)		(105	)
Energy procurement		(129	)		(48	)
Other		136			227
Total regulatory balancing accounts, net		$ 784			$ 708

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 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 recovery of these revenue requirements is decoupled from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers fluctuates 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 a lower volume of electricity sales and lower rates. During the warmer months of summer, there is generally an over-collection due to a higher volume of electricity sales and higher rates.

The public purpose programs balancing accounts are primarily used to record and recover 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 energy efficiency programs, low-income energy efficiency programs, research, development, and demonstration programs, and renewable energy programs.

17

The hazardous substance balancing accounts are used to record and recover hazardous substance remediation costs. A CPUC-approved ratemaking mechanism authorizes the Utility to recover 90% of such costs for certain sites. The balance represents eligible costs incurred by the Utility that are expected to be recovered over the next 12 months. (See Note 10 below.)

The gas fixed cost balancing account is used to record and recover authorized gas distribution revenue requirements and certain other gas distribution-related authorized costs. Similar to the utility generation and the distribution revenue adjustment mechanism balancing accounts discussed above, the recovery of these revenue requirements is decoupled from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers fluctuates depending on the volume of gas sales. During the colder months of winter, there is generally an over-collection in this balancing account primarily due to higher natural gas sales. During the warmer months of summer, there is generally an under-collection primarily due to lower natural gas sales.

The ERBs balancing account is used to record and refund to customers the net refunds, claim offsets, and other credits received by the Utility from electricity suppliers related to the Chapter 11 disputed claims and to record and recover authorized ERB servicing costs. (See Note 9 below.)

The Utility is generally authorized to recover 100% of its prudently incurred 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 over the following year. The Utility’s electric rates are set to recover such expected costs.

At March 31, 2012 and December 31, 2011, “other” consisted of various balancing accounts, such as the SmartMeter^TM advanced metering project balancing account, which tracks the recovery of the related authorized revenue requirements and costs, and balancing accounts that track the recovery of authorized meter reading costs.

NOTE 4: DEBT

Revolving Credit Facilities – PG&E Corporation and the Utility

At March 31, 2012, PG&E Corporation had neither cash borrowings nor letters of credit outstanding under its $300 million revolving credit facility.

At March 31, 2012, the Utility had no cash borrowings and $367 million of letters of credit outstanding under its $3.0 billion revolving credit facility.

At March 31, 2012, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

Utility

Senior Notes

On April 16, 2012, the Utility issued $400 million principal amount of 4.45% Senior Notes due April 15, 2042.

Pollution Control Bonds

At March 31, 2012, the interest rates on the $614 million principal amount of pollution control bonds Series 1996 C, E, F, and 1997 B and the related loan agreements ranged from 0.19% to 0.22%. At March 31, 2012, the interest rates on the $309 million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements ranged from 0.12% to 0.17%.

On April 2, 2012, the Utility repurchased all of the $50 million principal amount of pollution control bonds Series 2010 E that were subject to mandatory tender on that same date. The Utility will hold the bonds until they are remarketed to investors or retired.

Commercial Paper Program

At March 31, 2012, the Utility had $1.1 billion of commercial paper outstanding.

18

Other Short-Term Borrowings

At March 31, 2012, the interest rate on the Utility’s $250 million principal amount of Floating Rate Senior Notes, due November 20, 2012, was 0.94%.

Energy Recovery Bonds

In 2005, PERF issued two separate series of ERBs in the aggregate amount of $2.7 billion to refinance a regulatory asset provided for in the Chapter 11 Settlement Agreement. The proceeds of the ERBs were used by PERF to purchase from the Utility the right (known as “recovery property”) to be paid a specified amount from a dedicated rate component (“DRC”) to be collected from the Utility’s electricity customers. DRC charges are authorized by the CPUC under state legislation and will be paid by the Utility’s electricity customers until the ERBs are fully retired. Under the terms of a recovery property servicing agreement, DRC charges are collected by the Utility and remitted to PERF for payment of principal, interest, and miscellaneous expenses associated with the ERBs.

At March 31, 2012, the total amount of ERB principal outstanding was $321 million.

While PERF is a wholly owned consolidated 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.

NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the three months ended March 31, 2012 were as follows:

	PG&E Corporation			Utility
(in millions)	Total Equity			Total Shareholders’  Equity
Balance at December 31, 2011		$ 12,353			$ 12,384
Comprehensive income		246			241
Common stock issued		393			-
Share-based compensation expense		16			-
Common stock dividends declared		(193	)		(179	)
Preferred stock dividend requirement		-			(3	)
Preferred stock dividend requirement of subsidiary		(3	)		-
Equity contributions		-			385
Balance at March 31, 2012		$ 12,812			$ 12,828

During the three months ended March 31, 2012, PG&E Corporation issued 3,363,617 shares of its common stock under the Equity Distribution Agreement executed in November 2011, its 401(k) plan, its Dividend Reinvestment and Stock Purchase Plan, and upon exercises of employee stock options for total cash proceeds of $133 million, net of fees and commissions of $1 million. At March 31, 2012, PG&E Corporation had the ability to issue an additional $219 million of its common stock under the Equity Distribution Agreement.

On March 20, 2012, PG&E Corporation sold 5,900,000 shares of its common stock in an underwritten public offering for cash proceeds of $254 million, net of fees and commissions.

During the three months ended March 31, 2012, PG&E Corporation contributed equity of $385 million to the Utility to maintain its CPUC-authorized capital structure, which consists of 52% common equity and 48% debt and preferred stock.

19

NOTE 6: EARNINGS PER SHARE

PG&E Corporation’s basic earnings per common share (“EPS”) is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS:

	Three Months Ended
	March 31,
(in millions, except per share amounts)	2012		2011
Diluted
Income available for common shareholders	$	233	$	199
Weighted average common shares outstanding, basic		414		396
Add incremental shares from assumed conversions:
Employee share-based compensation		2		1
Weighted average common shares outstanding, diluted		416		397
Total earnings per common share, diluted	$	0.56	$	0.50

For each of the periods presented above, options and securities that were antidilutive were immaterial.

NOTE 7: DERIVATIVES

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 costs related to price risk management activities.

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 and option contracts that require payments from counterparties if market prices exceed a predetermined price.

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

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. As long as the current 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, in rates, all costs related to derivatives. 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 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 or refund to customers.

The Utility elects the normal purchase and sale exception for qualifying derivatives. Derivatives that require 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 derivatives that are eligible for the normal purchase and sales exception are not reflected in the Condensed Consolidated Balance Sheets.

20

Electricity Procurement

The Utility enters into third-party power purchase agreements for 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 derivatives. The Utility elects the normal purchase and sale exception for eligible derivatives.

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

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. The CAISO imposes congestion charges on market participants to manage transmission congestion. The revenue generated from congestion charges is allocated to holders of congestion revenue rights (“CRR”s). CRRs 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. CRRs are considered derivatives.

Natural Gas Procurement (Electric Fuels Portfolio)

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

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 natural 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 natural gas prices during peak winter months. These financial instruments are considered derivatives.

21

Volume of Derivative Activity

At March 31, 2012, the volumes of PG&E Corporation’s and the Utility’s outstanding derivatives 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		439,441,427		166,878,481		4,280,000		-
	Options		231,380,020		280,200,000		-		-
Electricity (Megawatt-hours)	Forwards and Swaps		4,141,223		4,696,221		2,009,505		3,421,832
	Options		1,248,000		140,510		239,233		218,013
	Congestion Revenue Rights		75,532,338		73,123,024		73,190,271		54,209,541

⁽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 2017 and 2022.

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

⁽⁴⁾ Million British Thermal Units.

Presentation of Derivative Instruments in the Financial Statements

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

At March 31, 2012, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

	Gross  Derivative Balance			Netting			Cash Collateral		Total  Derivative Balance
(in millions)	Commodity Risk (PG&E Corporation and the Utility)
Current assets – other		$ 42			$ (27	)		$ 97		$ 112
Other noncurrent assets – other		96			(43	)		-		53
Current liabilities – other		(515	)		27			318		(170	)
Noncurrent liabilities – other		(397	)		43			101		(253	)
Total commodity risk		$ (774	)		$ -			$ 516		$ (258	)

At December 31, 2011, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

		$0000.0			$0000.0			$0000.0		$0000.0
	Gross  Derivative Balance			Netting			Cash Collateral		Total  Derivative Balance
(in millions)	Commodity Risk (PG&E Corporation and the Utility)
Current assets – other		$ 54			$ (39	)		$ 103		$ 118
Other noncurrent assets – other		113			(59	)		-		54
Current liabilities – other		(489	)		39			274		(176	)
Noncurrent liabilities – other		(398	)		59			101		(238	)
Total commodity risk		$ (720	)		$ -			$ 478		$ (242	)

22

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

	Commodity Risk (PG&E  Corporation and Utility)
	Three months ended March 31,
(in millions)	2012			2011
Unrealized (loss) gain – regulatory assets and liabilities (1)		$ (54	)		$ 137
Realized loss – cost of electricity (2)		(151	)		(136	)
Realized loss – cost of natural gas (2)		(22	)		(55	)
Total commodity risk instruments		$ (227	)		$ (54	)

⁽¹⁾ Unrealized gains and losses on derivatives are deferred 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 recovered from customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.

Cash inflows and outflows associated with derivatives 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 derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. As of March 31, 2012, 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 post immediately additional cash to collateralize fully some of its net liability derivative positions.

At March 31, 2012, the additional cash collateral that the Utility would be required to post if the 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	$ (134	)
Related derivatives in an asset position	2
Collateral posting in the normal course of business related to these derivatives	33
Net position of derivative contracts/additional collateral posting requirements (1)	$ (99	)

⁽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.

23

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):

	Fair Value Measurements
	At March 31, 2012											At December 31, 2011
(in millions)	Level 1		Level 2		Level 3		Netting (1)			Total		Level 1		Level 2		Level 3		Netting (1)			Total
Assets:
Money market investments		$ 206		$ -		$ -		$ -			$ 206		$ 206		$ -		$ -		$ -			$ 206
Nuclear decommissioning trusts
U.S. equity securities		925		9		-		-			934		841		8		-		-			849
Non-U.S. equity securities		358		-		-		-			358		323		-		-		-			323
U.S. government and agency securities		734		138		-		-			872		744		156		-		-			900
Municipal securities		-		68		-		-			68		-		58		-		-			58
Other fixed-income securities		-		150		-		-			150		-		99		-		-			99
Total nuclear decommissioning trusts (2)		2,017		365		-		-			2,382		1,908		321		-		-			2,229
Price risk management instruments (Note 7)
Electricity		-		68		67		27			162		-		92		69		8			169
Gas		-		3		-		-			3		-		6		-		(3	)		3
Total price risk management instruments		-		71		67		27			165		-		98		69		5			172
Rabbi trusts
Fixed-income securities		-		26		-		-			26		-		25		-		-			25
Life insurance contracts		-		68		-		-			68		-		67		-		-			67
Total rabbi trusts		-		94		-		-			94		-		92		-		-			92
Long-term disability trust
U.S. equity securities		5		13		-		-			18		13		15		-		-			28
Non-U.S. equity securities		-		15		-		-			15		-		9		-		-			9
Fixed-income securities		-		142		-		-			142		-		145		-		-			145
Total long-term disability trust		5		170		-		-			175		13		169		-		-			182
Total assets		$ 2,228		$ 700		$ 67		$ 27			$ 3,022		$ 2,127		$ 680		$ 69		$ 5			$ 2,881
Liabilities:
Price risk management instruments (Note 7)
Electricity		$ 436		$ 284		$ 166		$ (471	)		$ 415		$ 411		$ 289		$ 143		$ (441	)		$ 402
Gas		15		11		-		(18	)		8		31		13		-		(32	)		12
Total liabilities		$ 451		$ 295		$ 166		$ (489	)		$ 423		$ 442		$ 302		$ 143		$ (473	)		$ 414

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

⁽²⁾ Excludes $248 million and $188 million at March 31, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value.

24

Valuation Techniques

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

Money Market Investments

PG&E Corporation invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, such as U.S. Treasury bills, U.S. 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 prices 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, debt securities, and life insurance policies. In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.

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

Debt securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market 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 ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

Price Risk Management Instruments

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

Power purchase agreements, forwards and swaps are valued using a discounted cash flow model. Exchange-traded forwards and swaps that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Forwards and swaps transacted in the over-the-counter market that are identical to exchange-traded forwards and swaps or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available.

Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. Over-the-counter options are classified as Level 3 and are valued using a standard option pricing model which includes forward prices for the underlying commodity, time value at a risk-free rate, and volatility. For periods where market data is not available, the Utility extrapolates observable data using internal models.

The Utility holds CRRs to hedge financial risk of CAISO-imposed congestion charges in the day-ahead market. CRRs are valued based on prices observed in the CAISO auction which are discounted at the risk free rate. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility uses models to forecast CRR prices for those periods not covered in the auctions. CRRs are classified as Level 3.

25

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 transfers between levels for the three months ended March 31, 2012.

Level 3 Measurements and Sensitivity Analysis

The Utility’s Market and Credit Risk Management department is responsible for determining the fair value of the Utility’s price risk management derivatives. Market and Credit Risk Management reports to the Chief Risk Officer of the Utility. Market and Credit Risk Management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments. These models use pricing inputs from brokers and historical data. The Market and Credit Risk Management department and the Controller’s organization collaborate to determine the appropriate fair value methodologies and classification for each derivative. Inputs used and fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness. Valuation models and techniques are reviewed periodically.

CRRs and power purchase agreements are valued using historical prices or significant unobservable inputs derived from internally-developed models. Unobservable inputs include forward electricity prices. Historical prices include CRR auction prices. Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. (See Note 7 above.)

(in millions)	Fair Value at March 31, 2012					Valuation Technique	Unobservable Input	Range
Fair Value Measurement	Assets		Liabilities
Congestion revenue rights		$ 67		$ (8	)	Market approach	CRR auction prices	$ (6.30) - $ 5.10
Power purchase agreements		$ -		$ (158	)	Discounted cash flow	Forward prices	$ 2.00 - $ 61.05

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the three months ended March 31, 2012 and 2011.

	Price Risk Management Instruments
(in millions)	2012			2011
Liability balance as of January 1		$ (74	)		$ (399	)
Realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)		(25	)		87
Liability balance as of March 31		$ (99	)		$ (312	)

⁽¹⁾ Price risk management activity is recoverable through customer rates. Therefore, net income was not impacted by realized amounts. Unrealized gains and losses are deferred in regulatory liabilities and assets.

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, 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 March 31, 2012 and December 31, 2011, 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 ERBs issued by PERF were based on quoted market prices at March 31, 2012 and December 31, 2011.

26

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):

	March 31, 2012				December 31, 2011
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation		$ 349		$ 382		$ 349		$ 380
Utility		10,546		12,412		10,545		12,543
Energy recovery bonds (Note 4)		321		327		423		433

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 does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, through customer rates. 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.)

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

(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Total Fair Value (1)
As of March 31, 2012
Equity securities
U.S.		$ 319		$ 616		$ (1	)		$ 934
Non-U.S.		197		162		(1	)		358
Debt securities
U.S. government and agency securities		787		86		(1	)		872
Municipal securities		66		3		(1	)		68
Other fixed-income securities		147		3		-			150
Total		$ 1,516		$ 870		$ (4	)		$ 2,382
As of December 31, 2011
Equity securities
U.S.		$ 334		$ 518		$ (3	)		$ 849
Non-U.S.		194		131		(2	)		323
Debt securities
U.S. government and agency securities		798		102		-			900
Municipal securities		56		2		-			58
Other fixed-income securities		96		3		-			99
Total		$ 1,478		$ 756		$ (5	)		$ 2,229

⁽¹⁾ Excludes $248 million and $188 million at March 31, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value.

The debt securities mature on the following schedule:

(in millions)	As of March 31, 2012
Less than 1 year		$ 29
1–5 years		408
5–10 years		264
More than 10 years		389
Total maturities of debt securities		$ 1,090

27

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

	Three Months Ended
(in millions)	March 31, 2012			March 31, 2011
Proceeds from sales and maturities of nuclear decommissioning trust investments		$ 351			$ 726
Gross realized gains on sales of securities held as available-for-sale		7			20
Gross realized losses on sales of securities held as available-for-sale		(3	)		(4	)

NOTE 9: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

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

While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers. The Utility entered into a number of settlement agreements 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 settlement amounts, net of deductions for contingencies based on the outcome of the various refund offset and interest issues being considered by the FERC, are 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 electricity suppliers through resolution of the remaining disputed claims, either through settlement or the conclusion of the various FERC and judicial proceedings, will also be refunded to customers.

At March 31, 2012 and December 31, 2011, the Utility held $320 million in escrow, including interest earned, for payment of the remaining net disputed claims. These amounts are included within restricted cash on the Condensed Consolidated Balance Sheets.

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

(in millions)
Balance at December 31, 2011	$	848
Interest accrued		7
Less: electricity supplier settlements		(23	)
Balance at March 31, 2012	$	832

At March 31, 2012, the Utility’s remaining net disputed claims liability was $832 million, consisting of $658 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 $668 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).

On April 10, 2012, the PX and the Utility reached an agreement that provides the Utility with the legal right to offset the Utility’s remaining disputed claims with the Utility’s accounts receivable from the CAISO and the PX. In future periods, the Utility will present the net amount of these balances on the Condensed Consolidated Balance Sheets within accounts payable – disputed claims and customer refunds.

28

Interest accrues on the remaining net disputed claims liability 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 the remaining net disputed claims liability, 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 determined amounts with respect to the remaining net disputed claims liability and when such interest is paid.

NOTE 10: COMMITMENTS AND CONTINGENCIES

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

Commitments

Third-Party Power Purchase Agreements

As part of the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either gas or electricity at the date of purchase. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s development of new generation facilities to provide the power to be purchased by the Utility under these agreements. The table below excludes future expected payments related to agreements ranging from 10 to 25 years in length that are cancellable if the construction of a new generation facility have not met certain contractual milestones with respect to construction. Based on the Utility’s experience with these types of facilities, the Utility has determined that there is more than a remote chance that contracts could be cancelled until the generation facilities have commenced construction.

At March 31, 2012, the undiscounted future expected payment obligations were as follows:

(in millions)
2012	$ 1,810
2013	2,860
2014	3,010
2015	3,007
2016	2,917
Thereafter	32,120
Total	$ 45,724

Costs incurred by the Utility under power purchase agreements amounted to $435 million and $587 million for the three months ended March 31, 2012 and 2011, respectively.

Some of the power purchase agreements that the Utility entered into with independent power producers that are qualifying facilities are treated as capital leases. During the three months ended March 31, 2012, the Utility terminated several agreements with total minimum lease payments of approximately $136 million. As of March 31, 2012, future minimum lease payments associated with capital leases were approximately $115 million.

29

Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the U.S. 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, the U.S. Rocky Mountain supply area, and the southwestern U.S.) to the points at which the Utility’s natural gas transportation system begins. In addition, the Utility has contracted for natural gas storage services in northern California in order to better meet core customers’ winter peak loads.

At March 31, 2012, the Utility’s undiscounted future expected payment obligations were as follows:

(in millions)
2012	$ 475
2013	331
2014	196
2015	187
2016	153
Thereafter	974
Total	$ 2,316

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage amounted to $378 million and $433 million for the three months ended March 31, 2012 and 2011, 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 nuclear 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 March 31, 2012, the undiscounted future expected payment obligations were as follows:

(in millions)
2012	$ 67
2013	86
2014	127
2015	193
2016	147
Thereafter	1,011
Total	$ 1,631

Payments for nuclear fuel amounted to $19 million and $29 million for the three months ended March 31, 2012 and 2011, respectively.

Other Commitments

In March 2012, the Utility entered into a 10-year facility lease agreement for 250,000 square feet of office space in San Ramon, California. As of March 31, 2012, the future minimum commitment for this operating lease was approximately $67 million.

30

Contingencies

PG&E Corporation

PG&E Corporation retains a guarantee related to certain obligations of its former subsidiary, National Energy & Gas Transmission, Inc. (“NEGT”), that were issued to the purchaser of an NEGT subsidiary company in 2000. 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 if it were required to satisfy its obligations under this guarantee any required payments would not have a material impact on its financial condition, results of operations, or cash flows.

Utility

Spent Nuclear Fuel Storage Proceedings

Under federal law, the U.S. Department of Energy (“DOE”) was required to dispose of spent nuclear fuel and high-level radioactive waste from electric utilities with commercial nuclear power plants no later than January 31, 1998, in exchange for fees paid by the utilities. The DOE failed to meet its contractual obligation to dispose of nuclear waste from the Utility’s nuclear generating facility at Diablo Canyon and its retired facility at Humboldt Bay (“Humboldt Bay Unit 3”). As a result, the Utility constructed an interim 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 storage facilities. The Utility sought to recover $92 million of costs that it incurred through 2004. After several years of litigation, the U.S. Court of Federal Claims awarded the Utility $89 million on March 30, 2010. On February 21, 2012, the Federal Circuit Court of Appeals denied the DOE’s appeal from May 2010 and affirmed the $89 million award. The deadline for the DOE to petition for a rehearing of the Court’s decision is May 21, 2012. The Utility has not recorded any receivable for the award as of March 31, 2012.

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 refunded to customers.

Nuclear Insurance

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

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

31

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

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

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

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

Legal and Regulatory Contingencies

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits. In addition, 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 loss when it is both probable that a loss 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 losses and record a provision 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 (or reasonably possible losses in excess of the amounts accrued), 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, penalties, and other legal matters (other than third-party claims and penalties related to natural gas matters discussed below) totaled $36 million at March 31, 2012 and $52 million at December 31, 2011 and are 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 and regulatory contingencies would have a material impact on their financial condition, results of operations, or cash flows.

Natural Gas Matters

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 (the “San Bruno accident”). The ensuing explosion and fire resulted in the deaths of eight people, numerous personal injuries, and extensive property damage. Following the San Bruno accident, various regulatory proceedings, investigations, and lawsuits were commenced.

Pending CPUC Investigations and Enforcement Matters

On February 24, 2011, the CPUC commenced an investigation pertaining to safety recordkeeping for Line 132, as well as for the Utility’s entire gas transmission system. Among other matters, the investigation will determine whether the San Bruno accident would have been preventable by the exercise of safe procedures and /or accurate and technical recordkeeping in compliance with the law. On March 12, 2012, the CPUC’s Consumer Protection and Safety Division (“CPSD”) filed testimony that consisted of reports by the CPSD’s records management consultant and an engineering consultant. Among other findings, the consultants’ reports concluded that: the Utility’s recordkeeping practices have been deficient and have diminished pipeline safety; the San Bruno accident may have been prevented had the Utility managed its records properly over the years; and that the Utility has been operating, and continues to operate, without a functional

32

integrity management program. On March 30, 2012, the CPSD filed supplemental testimony to address additional recordkeeping items and to list specific violations the CPSD alleges that the Utility committed based on the findings of the consultants’ reports. The Utility’s responses to the CPSD’s reports are due on June 25, 2012. Evidentiary hearings are scheduled for September 2012 with a final decision expected in February 2013. If the CPUC finds that the Utility has violated any rule, regulation or law, it will schedule a second phase to assess penalties. See “Penalties Conclusion” below.

On November 10, 2011, the CPUC commenced an investigation pertaining to the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density. Under federal and state regulations, the class location designation of a pipeline is based on the types of buildings, population density, or level of human activity near the segment of pipeline, and is used to determine the maximum allowable operating pressure (“MAOP”) up to which a pipeline can be operated. On April 2, 2012, in its second response to the CPUC investigation, the Utility reported that 159 miles of pipeline (as compared to 162 miles previously reported) had a current class location designation that was higher than reflected in the Utility’s Geographic Information System. Most of these misclassifications were attributable to the Utility’s failure to correctly identify development or well-defined areas near the pipeline. The Utility had also previously determined it had not timely performed a class location study for certain segments and did not confirm the MAOP of those segments for which the Utility had not timely identified a change in class location. The Utility also reported that it could not confirm that all transmission lines were patrolled as required by the Utility’s procedures and that the Utility has begun a system-wide review of patrol records for all transmission pipelines. Evidentiary hearings are scheduled for August 2012. See “Penalties Conclusion” below.

On January 12, 2012, the CPUC commenced an investigation to determine whether the Utility violated applicable laws and requirements in connection with the San Bruno accident, as alleged by the CPSD. In its investigation report, the CPSD had alleged that the San Bruno accident was caused by the Utility’s failure to follow accepted industry practice when installing the section of pipe that failed, the Utility’s failure to comply with federal pipeline integrity management requirements, the Utility’s inadequate record keeping practices, deficiencies in the Utility’s data collection and reporting system, inadequate procedures to handle emergencies and abnormal conditions, the Utility’s deficient emergency response actions after the incident, and a systemic failure of the Utility’s corporate culture that emphasized profits over safety. The CPUC stated that the scope of the investigation will include all past operations, practices and other events or courses of conduct that could have led to or contributed to the San Bruno accident, as well as, the Utility’s compliance with CPUC orders and resolutions issued since the date of the San Bruno accident. The CPUC noted that the CPSD’s investigation is ongoing and the CPSD could raise additional concerns that it could request the CPUC to consider. Evidentiary hearings are scheduled for September and October 2012 with a final decision expected in January 2013. See “Penalties Conclusion” below.

In December 2011, the CPUC delegated authority to its staff to enforce compliance with certain state and federal regulations related to the safety of natural gas facilities and utilities’ natural gas operating practices, including the authority to issue citations and impose penalties. The CPUC also established a requirement that California gas corporations provide notice to the CPUC of any self-identified or self-corrected violations of these regulations. Since the citation program was adopted, the Utility has filed 12 self-reports with the CPUC. In one of these self-reports, the Utility reported that it failed to conduct periodic leak surveys because the Utility had not included 16 gas distribution maps in its leak survey schedule. In response to this self-report, the CPSD issued a citation to the Utility that included a penalty of approximately $17 million. On April 19, 2012, the CPUC denied the Utility’s appeal of the $17 million penalty and concluded that the CPSD had appropriately determined the number of violations. The Utility was ordered to pay the penalty within 30 days. The CPSD has not yet taken action with respect to the Utility’s other self-reports, including a follow-up report stating that the Utility had not considered an additional 46 gas distribution maps in its leak survey schedule. (The Utility has completed all of the missed leak surveys.) The CPSD may issue additional citations and impose penalties on the Utility associated with these or future reports that the Utility may file. See “Penalties Conclusion” below.

Penalties Conclusion

The CPUC can impose penalties of up to $20,000 per day, per violation, for violations of applicable laws, rules, and orders in connection with the pending investigations described above. For violations that are considered to have occurred on or after January 1, 2012, the statutory penalty has increased to a maximum of $50,000 per day, per violation. (Under the CPUC’s delegation of authority, the CPSD is required to impose the maximum statutory penalty.) The CPUC and CPSD have wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the number of violations; the length of time the violations existed; the severity of the violations, including the type of harm caused by the violations and the number of persons affected; conduct taken to prevent, detect, disclose or rectify the violations; and the financial resources of the regulated entity. The CPUC has stated that it is prepared to impose very significant penalties if the evidence adduced at hearing establishes that the Utility’s policies and practices contributed to the loss of life, injuries, or loss of property resulting from the San Bruno accident.

33

PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties of at least $200 million on the Utility as a result of these investigations and the Utility’s self-reports and have accrued this amount as of March 31, 2012 and December 31, 2011. (The amount accrued included the $17 million penalty described above.) In reaching this conclusion, management has considered, among other factors, the findings and allegations contained in the CPSD’s reports; the Utility’s self-reports to the CPUC; and the outcome of prior CPUC investigations of other matters. PG&E Corporation and the Utility are unable to estimate the reasonably possible amount of penalties in excess of the amount accrued, and such amounts could be material. The ultimate amount of penalties imposed on the Utility will be affected by many factors, including how many violations the CPUC will find the Utility has committed; whether the penalties will be calculated separately for each matter above or in the aggregate; whether the CPSD issues additional citations based on the Utility’s self-reports; and whether and how the CPUC will consider the broader impacts of the San Bruno accident on the Utility’s results of operations, financial condition, and cash flows.

The Utility’s estimates and assumptions are subject to change as the CPUC investigations progress and more information becomes known, and such changes could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

Criminal Investigation

The U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo County District Attorney’s Office are conducting an investigation of the San Bruno accident. The Utility is cooperating with the investigation. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any civil or criminal penalties that could be imposed on the Utility.

Third-Party Claims

Approximately 110 lawsuits involving third-party claims for personal injury and property damage in connection with the San Bruno accident, including two class action lawsuits, have been filed against PG&E Corporation and the Utility on behalf of approximately 380 plaintiffs. The lawsuits seek compensation for these third-party claims and other relief, including punitive damages. These cases have been coordinated and assigned to one judge in the San Mateo County Superior Court. The judge overseeing the coordinated San Bruno accident civil litigation has set a trial date of July 23, 2012 for the first of these lawsuits.

On April 6, 2012, PG&E Corporation and the Utility filed various motions to request that the Court dismiss certain claims, including plaintiffs’ claims for punitive damages, based upon a lack of evidence to support such claims. Plaintiffs’ oppositions to the motions are due on June 8, 2012. The court will hold a hearing on June 22, 2012 to consider the motions.

As of March 31, 2012, the Utility has incurred a cumulative charge of $375 million for third-party claims and estimates that it is reasonably possible it will incur up to an additional $225 million, for a total possible loss of $600 million. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with punitive damages, if any, related to these matters. As more information becomes known, estimates and assumptions regarding the amount of liability incurred may be subject to further changes. Future changes in estimates may have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows in the period during which they are recorded. The Utility has publicly stated that it is liable for the San Bruno accident and will take financial responsibility to compensate all of the victims for the injuries they suffered as a result of the accident.

The following table presents the changes in third-party claims liability since the San Bruno accident in 2010, which is included in other current liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:

(in millions)
Balance at January 1, 2010	$ 0
Loss accrued	220
Less: Payments	(6)
Balance at December 31, 2010	214
Additional loss accrued	155
Less: Payments	(92)
Balance at December 31, 2011	277
Less: Payments	(34)
Balance at March 31, 2012	$ 243

34

Additionally, the Utility has liability insurance from various insurers who provide coverage at different policy limits that are triggered in sequential order or “layers.” Generally, as the policy limit for a layer is exhausted the next layer of insurance becomes available. The aggregate amount of this insurance coverage is approximately $992 million in excess of a $10 million deductible. The Utility submitted insurance claims to certain insurers for the lower layers and recognized $11 million for insurance recoveries during the three months ended March 31, 2012. This is in addition to the $99 million recognized for insurance recoveries during 2011. Although the Utility believes 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 future insurance recoveries.

Environmental Remediation Contingencies

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

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

The following table presents the changes in the environmental remediation liability from December 31, 2011:

(in millions)
Balance at December 31, 2011	$ 785
Additional remediation costs accrued:
Transfer to regulatory account for recovery	77
Amounts not recoverable in customer rates	81
Less: Payments	(22)
Balance at March 31, 2012	$ 921

The $921 million accrued at March 31, 2012 consisted of the following:

• $218 million for remediation at the Utility’s natural gas compressor site located near Hinkley, California (“Hinkley natural gas compressor site”), as described below;

• $240 million for remediation at the Utility’s natural gas compressor site located on the California border, near Topock, Arizona;

• $80 million related to a remediation liability that the Utility retained after selling certain fossil fuel-fired generation facilities in 1998 and 1999;

• $168 million related to remediation costs for the Utility’s generation facilities (other than remediation costs for fossil fuel-fired generation), other facilities, and for third-party disposal sites;

• $165 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

• $50 million related to remediation costs for decommissioning fossil fuel-fired generation facilities and sites.

35

Hinkley Natural Gas Compressor Site

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

In October 2011, the Regional Board ordered the Utility to provide an interim and permanent replacement water system for certain resident households that have domestic wells containing hexavalent chromium concentrations above the 3.1 parts per billion background level. Following the issuance of this order, the Utility filed a petition with the California State Water Resources Control Board (“State Board”) to contest certain provisions of the order. On April 9, 2012, the Utility informed the Regional Board that the Utility would provide approximately 300 resident households located up to one mile from the chromium plume boundary with two options for a replacement water supply. Eligible residents may have an individual water treatment system on the property or, where feasible, have a deeper well installed to draw water from a lower aquifer. Alternatively, eligible residents may choose to have the Utility purchase their properties. The Utility expects to begin implementing this program later in 2012. The Utility will continue the program until the State of California has adopted a drinking water standard specifically for hexavalent chromium or for up to five years at which time the program will be evaluated. The Utility has requested the Regional Board’s acknowledgement that the Utility’s program complies with the October 2011 order.

The Regional Board is also evaluating the Utility’s final groundwater remediation plan that proposes using a combination of remedial methods, including using pumped groundwater from extraction wells to irrigate agricultural land and in-situ treatment of the contaminated water. The Regional Board stated it anticipates releasing a draft environmental impact report (“EIR”) in the second half of 2012 and that it will consider certification of the final EIR, which will include the final approved remediation plan, by the end of 2012.

As of March 31, 2012, $218 million was accrued in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Hinkley natural gas compressor site, compared to $149 million accrued at December 31, 2011. The increase primarily reflects the Utility’s best estimate of future probable costs associated with providing water replacement systems to eligible residents or purchasing property from eligible residents, as described above. Remediation costs for the Hinkley natural gas compressor site are not recovered from customers.

Future costs will depend on many factors, including when and whether the Regional Board certifies the final remediation plan, the extent of the groundwater chromium plume, the levels of hexavalent chromium the Utility is required to use as the standard for remediation, and the number of eligible residents who participate in the Utility’s program described above. As more information becomes known regarding these factors, estimates and assumptions regarding the amount of liability incurred may be subject to further changes. Future changes in estimates may have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

Reasonably Possible Environmental Contingencies

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, the Utility’s undiscounted future costs could increase to as much as $1.6 billion (including amounts related to the Hinkley natural gas compressor site) if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on PG&E Corporation’s and the Utility’s results of operations during the period in which they are recorded.

Recoveries of Environmental Remediation Costs

The CPUC has authorized the Utility to recover 90% of its hazardous substance remediation costs from customers without a reasonableness review for certain approved sites (excluding any remediation costs associated with the Hinkley natural gas compressor site). The Utility expects to recover $427 million through this ratemaking mechanism. The CPUC has historically authorized the Utility to recover 100% of its remediation costs for decommissioning fossil fuel-fired generation facilities and sites through decommissioning funds collected in rates, and the Utility believes it is probable that it will continue to recover these costs in the future. The Utility expects to recover $50 million through this ratemaking mechanism and an additional $99 million from other ratemaking mechanisms. Finally, the Utility also recovers these costs

36

from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility’s ultimate obligations may be subject to refund to customers.

Tax Matters

In 2008, PG&E Corporation began participating in the Compliance Assurance Process (“CAP”), a real-time Internal Revenue Service (“IRS”) audit intended to expedite resolution of tax matters. The CAP audit culminates with a letter from the IRS indicating its acceptance of the return. The IRS partially accepted the 2008 return, withholding two matters for further review. In December 2010, the IRS accepted the 2009 tax return without change. In September 2011, the IRS partially accepted the 2010 return, withholding two matters for further review. The IRS has not completed the CAP audit for 2011.

The most significant of the matters withheld for further review relates to a tax accounting method change filed by PG&E Corporation to accelerate the amount of deductible repairs. In the fourth quarter 2011, the IRS agreed to allow PG&E Corporation to file claims for 2008-2010 for the repairs method change. The IRS has not completed its review of these claims.

The IRS is continuing to work with the utility industry to provide consistent repairs deduction guidance for natural gas transmission, natural gas distribution, and electric generation businesses. PG&E Corporation and the Utility expect the IRS to release this guidance in 2012.

The 2005 through 2007 tax years are currently under Appeals with the IRS. PG&E Corporation expects to complete the Appeals process in 2012. PG&E Corporation believes that the final resolution of open audits will not have a material impact on its financial condition or results of operations.

PG&E Corporation and the Utility are unable to determine the potential impact of future changes to the unrecognized tax benefits at this time.

37

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 that conducts its business 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 served approximately 5.2 million electricity distribution customers and approximately 4.3 million natural gas distribution customers at March 31, 2012.

The Utility is regulated primarily 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 CPUC has jurisdiction over the rates and terms and conditions of service for the Utility’s electricity and natural gas distribution operations, electric generation, and natural gas transportation and storage. The FERC has jurisdiction over the rates and terms and conditions of service governing the Utility’s electric transmission operations and over the rates and terms and conditions of service governing the Utility on its interstate natural gas transportation contracts. The Utility also is subject to the jurisdiction of other federal, state, and local governmental agencies.

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, 2011 which contains or incorporates by reference each company’s audited Consolidated Financial Statements, the Notes to the Consolidated Financial Statements, and other information (“2011 Annual Report”).

Key Factors Affecting Results of Operations and Financial Condition

PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows have continued to be negatively affected by the ongoing regulatory proceedings and investigations related to its natural gas pipeline operations that were commenced following the rupture of one of the Utility’s natural gas transmission pipelines in San Bruno, California on September 9, 2010 (the “San Bruno accident”). The outcome of these matters, as well as the outcome of the civil litigation related to the San Bruno accident, is expected to have a material impact on PG&E Corporation’s and the Utility’s future results of operations, financial condition, and cash flows. As discussed below, other factors, including changes in the estimated costs of environmental remediation associated with the Utility’s natural gas compressor stations, also have had, and may continue to have, a material impact on PG&E Corporation’s and the Utility’s future results of operations, financial condition, and cash flows.

• The Outcome of Matters Related to the Utility’s Natural Gas System.  The Utility forecasts that it will incur total natural gas pipeline-related costs ranging from $450 million to $550 million in 2012 that may not be recoverable through rates, including $104 million incurred during the three months ended March 31, 2012. These costs include amounts related to the Utility’s proposed pipeline safety enhancement plan. It is uncertain when the CPUC will act on the Utility’s request to track plan-related costs for potential future recovery, what portion of plan-related costs incurred in 2012 or future years will be recoverable, and when such plan-related costs, if any, will be recovered. (See “Natural Gas Matters - CPUC Rulemaking Proceeding” below.) PG&E Corporation and the Utility also continue to believe that the ultimate amount of penalties that the CPUC will impose in connection with the investigations and enforcement matters pending at the CPUC could be materially higher than the $200 million accrued. Additionally, it is reasonably possible that the Utility may incur additional charges of up to $225 million for third-party claims related to the San Bruno accident. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.) It is also reasonably possible that an ongoing investigation of the San Bruno accident by federal and state authorities may result in the imposition of civil or criminal penalties on the Utility. PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows will be affected by the scope and timing of the final CPUC-approved pipeline safety enhancement plan, the ultimate amount of pipeline-related costs that are not recovered through rates, the ultimate amount of costs incurred for third-party claims that are not recoverable through insurance, and the ultimate amount of civil or criminal penalties, or punitive damages, if any, the Utility may be required to pay.

• The Ability of the Utility to Control Operating Costs and Capital Expenditures.  The Utility’s revenue requirements are generally set by the CPUC and the FERC at a level to allow the Utility to recover its forecasted operating expenses, to recover depreciation, tax, and interest expenses associated with forecasted capital expenditures, and to provide the Utility an opportunity to earn its authorized return on equity (“ROE”). In addition to the additional expenses related to

38

natural gas matters described above, the Utility forecasts that it will incur expenses in each of 2012 and 2013 that are materially higher than amounts assumed under the 2011 General Rate Case (“GRC”) and the 2011 Gas Transmission and Storage (“GT&S”) rate case as the Utility continues to work to improve the safety and reliability of its electric and natural gas operations. These higher forecasted expenses will negatively affect PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows. During the three months ended March 31, 2012, the Utility increased its environmental remediation liability related to its natural gas compressor station located near Hinkley, California (“Hinkley natural gas compressor site”) by $75 million and agreed to contribute $70 million to the City of San Bruno to support the city and community’s recovery efforts. These additional expenses, which are not recoverable through rates, negatively affected PG&E Corporation’s and the Utility’s financial results.

• Authorized Rate of Return, Capital Structure, and Financing.  Future changes in the Utility’s CPUC-authorized ROE and capital structure will affect the amount of the Utility’s net income and the amount of PG&E Corporation’s income available for common shareholders. The Utility’s capital structure for its electric and natural gas distribution and electric generation rate base, consisting of 52% common equity and 48% debt and preferred stock, and its authorized ROE of 11.35% will remain in effect through 2012. On April 20, 2012, the Utility filed an application to request that the CPUC authorize the Utility’s capital structure and rates of return beginning on January 1, 2013. (See “2013 Cost of Capital Proceeding” below.) The Utility’s financing needs will be affected by various factors, including changes to its authorized capital structure and rates of return, and the timing and amount of capital expenditures, operating expenses, and collateral requirements. PG&E Corporation contributes equity to the Utility as needed by the Utility to maintain its CPUC-authorized capital structure. Charges incurred by the Utility that are not recoverable through customer rates increase the Utility’s equity needs. Additional equity issued by PG&E Corporation could have a dilutive effect on future earnings per common share. PG&E Corporation’s and the Utility’s ability to access the capital markets and the terms and rates of future financings could be affected by changes in their respective credit ratings, the outcome of natural gas matters, general economic and market conditions, and other factors. (See “Liquidity and Financial Resources” below.)

• The Timing and Outcome of Ratemaking and Other Regulatory Proceedings.  The Utility’s financial results are affected by the timing and outcome of rate case decisions. As described in the 2011 Annual Report, the CPUC and FERC issued decisions in 2011 that determined the majority of the Utility’s base revenue requirements for the next several years. In July 2012, the Utility expects to submit a draft of its GRC application to the CPUC for the period beginning January 1, 2014. (See “2014 General Rate Case” below.) From time to time, the Utility also files separate applications with the CPUC requesting authority to recover costs for other projects, such as the Utility’s proposed pipeline safety enhancement plan in August 2011. (See “Natural Gas Matters – CPUC Rulemaking Proceeding” below.) The Utility’s revenues will be affected by whether and when the CPUC authorizes the Utility to recover these costs. The Utility also collects revenue requirements to recover certain costs that the CPUC has authorized the Utility to pass through to customers, such as electricity 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.

39

Summary of Changes in Earnings per Common Share and Income Available for Common Shareholders for the Three Months Ended March 31, 2012

PG&E Corporation’s income available for common shareholders increased by $34 million, or 17%, from $199 million for the three months ended March 31, 2011 to $233 million for the three months ended March 31, 2012. 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 months ended March 31, 2012:

(in millions)	Earnings		Earnings Per     Common Share     (Diluted)
Income Available for Common Shareholders – March 31, 2011		$ 199		$ 0.50
Timing of rate case decisions in 2011		57		0.14
Storm and outage expenses		28		0.07
Litigation and regulatory matters		22		0.05
Increase in rate base earnings		22		0.05
Gas transmission revenues		8		0.02
Natural gas matters		(66)		(0.15)
Environmental-related costs		(42)		(0.10)
Other		5		0.01
Increase in shares outstanding (1)		-		(0.03)
Income Available for Common Shareholders – March 31, 2012		$ 233		$ 0.56
(1)  Represents the impact of a higher number of shares outstanding at March 31, 2012, compared to the number of shares outstanding at March 31, 2011. PG&E Corporation issues shares to fund its equity contributions to the Utility that are used by the Utility to maintain its capital structure and fund operations, including expenses related to natural gas matters. This has no dollar impact on earnings.

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions which are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures; estimated environmental remediation, tax, and other liabilities; estimates and assumptions used in PG&E Corporation’s and the Utility’s critical accounting policies; anticipated outcomes of various regulatory, governmental, and legal proceedings; estimated losses and insurance recoveries associated with the San Bruno accident and natural gas matters; estimated additional costs the Utility will incur related to its natural gas transmission and distribution 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,” “forecast,” “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 outcomes of pending and future investigations, enforcement matters, and regulatory proceedings related to the San Bruno accident and the safety of the Utility’s natural gas system; the ultimate amount of third-party claims associated with the San Bruno accident that are not recovered through insurance; the ultimate amount of any civil or criminal penalties, or punitive damages, if any, the Utility may incur related to these matters, and the ultimate amount of costs the Utility incurs for natural gas matters that are not recovered through rates;

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

• whether PG&E Corporation and the Utility are able to repair the reputational harm that they have suffered which, in part, will depend on their ability to implement the recommendations made by the National Transportation Safety Board (“NTSB”) and the CPUC’s independent review panel and comply with new state and federal regulations applicable to natural gas pipeline operations; whether additional deficiencies are identified in the Utility’s operating practices and procedures or corporate culture; developments that may occur in the various investigations of the San Bruno accident and natural gas matters; the decisions, findings, or orders issued in connection with these investigations, including the amount

40

of civil or criminal penalties that may be imposed on the Utility; developments that may occur in the civil litigation related to the San Bruno accident; and the extent of service disruptions that may occur due to changes in pipeline pressure as the Utility continues to inspect and test pipelines;

• 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, the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and the availability and price of nuclear fuel used in the two nuclear generation units at Diablo Canyon;

• explosions, fires, accidents, mechanical breakdowns, equipment failures, human errors, labor disruptions, and similar events, as well as acts of terrorism, war, or vandalism, including cyber-attacks, that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or 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; and subject the Utility to third-party liability for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory penalties on the Utility;

• the impact of storms, tornadoes, floods, drought, earthquakes, tsunamis, wildland and other fires, pandemics, solar events, electromagnetic events, and other natural disasters, which 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, the impact of environmental laws and regulations aimed at the reduction of carbon dioxide and other greenhouse gases (“GHG”s), and whether the Utility is able to recover associated compliance costs, including the cost of emission allowances and offsets, that the Utility may incur under cap-and-trade regulations;

• changes in customer demand for electricity (“load”) and natural gas resulting from unanticipated population growth or decline in the Utility’s service area, general and regional 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 generation facilities and the ability of the Utility to procure replacement electricity if certain generation facilities were unavailable;

• the results 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 impact of the recently issued NRC orders to implement various recommendations made by the NRC’s task force following the March 2011 earthquake and tsunami that caused significant damage to nuclear facilities in Japan; and the impact of new legislation, regulations, or policies that may be adopted in the future to address the operations, security, safety, or decommissioning of nuclear facilities, the storage of spent nuclear fuel, seismic design, cooling water intake, or other issues;

• the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies, including how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company, and whether the outcome of proceedings and investigations relating to the Utility’s natural gas operations affects the Utility’s ability to make distributions to PG&E Corporation in the form of dividends or share repurchases;

• whether the Utility’s newly installed advanced metering system infrastructure, consisting of electric and gas SmartMeter^TM devices and related software systems and wireless communications equipment, continues to function accurately and timely measure customer energy usage and generate billing information; whether the Utility can timely implement “dynamic pricing” retail electric rates that are more closely aligned with real-time wholesale electricity market prices; and whether the Utility can continue to rely on third-party vendors and contractors to maintain and support the advanced metering system infrastructure;

• whether the Utility is able to protect its information technology, operating systems, and networks, including the advanced metering system infrastructure from damage, disruption, or failure caused by cyber-attacks, computer viruses, and other hazards; and whether the Utility’s security measures are sufficient to protect confidential customer, vendor, and financial data contained in such systems and networks from unauthorized access and disclosure;

• 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;

41

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

• the amount of equity issued by PG&E Corporation in the future to fund equity contributions to the Utility to enable the Utility to maintain its authorized capital structure that will primarily depend on the timing and amount of charges and costs the Utility incurs that will not be recoverable through rates or insurance; and the ability of PG&E Corporation, the Utility, and other counterparties to access capital markets and other sources of credit in a timely manner on acceptable terms;

• the impact of environmental remediation laws, regulations, and orders; the extent to which the Utility is able to recover compliance and remediation costs from third parties or through rates or insurance; and the ultimate amount of costs the Utility incurs in connection with the Hinkley natural gas compressor site, which are not recoverable through rates or insurance;

• 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 certain types of governmental bodies to purchase and sell electricity for their local residents and businesses; and

• the outcome of federal or state tax audits and the impact of any changes in federal or state tax laws, policies, or regulations.

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, results of operations, and cash flows, see the discussion in the section entitled “Risk Factors” in the 2011 Annual Report. 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.

42

RESULTS OF OPERATIONS

The table below details certain items from the accompanying Condensed Consolidated Statements of Income for the three months ended March 31, 2012 and 2011:

	Three Months ended March 31,
(in millions)	2012		2011
Utility
Electric operating revenues		$ 2,771		$ 2,616
Natural gas operating revenues		869		980
Total operating revenues		3,640		3,596
Cost of electricity		859		888
Cost of natural gas		343		508
Operating and maintenance		1,366		1,226
Depreciation, amortization, and decommissioning		584		490
Total operating expenses		3,152		3,112
Operating income		488		484
Interest income		1		2
Interest expense		(168)		(171)
Other income, net		23		17
Income before income taxes		344		332
Income tax provision		113		131
Net Income		231		201
Preferred stock dividend requirement		3		3
Income available for common stock		$ 228		$ 198
PG&E Corporation, Eliminations, and Other (1)
Operating revenues		$ 1		$ 1
Operating expenses		2		1
Operating loss		(1)		-
Interest income		-		-
Interest expense		(6)		(6)
Other income, net		3		-
Loss before income taxes		(4)		(6)
Income tax benefit		(9)		(7)
Net Income		$ 5		$ 1
Consolidated Total
Operating revenues		$ 3,641		$ 3,597
Operating expenses		3,154		3,113
Operating income		487		484
Interest income		1		2
Interest expense		(174)		(177)
Other income, net		26		17
Income before income taxes		340		326
Income tax provision		104		124
Net Income		236		202
Preferred stock dividend requirement of subsidiary		3		3
Income available for common shareholders		$ 233		$ 199
(1)  PG&E Corporation eliminates all intercompany transactions in consolidation.

43

Utility

The following presents the Utility’s operating results for the three months ended March 31, 2012 and 2011. Although the 2011 GRC and GT&S rate case were effective January 1, 2011, final decisions were not issued until the second quarter of 2011. Therefore, approximately $127 million of the total increase in authorized base revenues represents amounts authorized and recorded in the three months ended June 30, 2011, pertaining to the three months ended March 31, 2011.

Electric Operating Revenues

The Utility’s electric operating revenues consist of amounts charged to customers for electricity generation, transmission and distribution services, as well as amounts charged to customers to recover electricity procurement costs and the costs of public purpose, energy efficiency, and demand response programs.

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

	Three months ended                  March 31,
(in millions)	2012		2011
Revenues excluding passed-through costs		$ 1,575		$ 1,414
Revenues for recovery of passed-through costs		1,196		1,202
Total electric operating revenues		$ 2,771		$ 2,616

The Utility’s total electric operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $155 million, or 6%, in the three months ended March 31, 2012, as compared to the same period in 2011. Electric operating revenues, excluding costs passed through to customers, increased by $161 million, primarily due to an increase in base revenues as authorized in the 2011 GRC decision that was issued on May 5, 2011. Of the total increase in authorized base revenues, approximately $100 million represents base revenues that were authorized and recorded in the three months ended June 30, 2011 but pertained to the three months ended March 31, 2011. The increase was partially offset by a decrease in costs that are passed through to customers and do not impact net income, primarily due to decreases in the cost of electricity. (See “Cost of Electricity” below.)

The Utility’s future electric operating revenues, excluding passed-through costs, are expected to increase in the remainder of 2012 and in 2013 as authorized by the CPUC in the 2011 GRC. 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 the costs of power purchased from third parties, transmission, fuel used in its own generation facilities, fuel supplied to other facilities under power purchase agreements, and realized gains and losses on price risk management activities. The volume of power the Utility purchases is driven by load, the availability of the Utility’s own generation facilities, 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 and electric transmission system, which are included in operating and maintenance expense in the Condensed Consolidated Statements of Income.

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

	Three months ended         March 31,
(in millions)	2012		2011
Cost of purchased power		$ 776		$ 821
Fuel used in own generation facilities		83		67
Total cost of electricity		$ 859		$ 888
Average cost of purchased power per kWh (1)		$ 0.075		$ 0.094
Total purchased power (in kWh)		10,290		8,779
(1) Kilowatt-hour

44

The Utility’s total cost of electricity decreased by $29 million, or 3%, in the three months ended March 31, 2012 as compared to the same period in 2011. This was caused by a decrease in the cost of purchased power resulting from a decline in the market price of electricity. The Utility increased the amount of power it purchased as a result of lower market prices. The decrease in the cost of electricity due to lower market prices was partially offset by an increase in the cost of fuel used in the Utility’s own electricity generation facilities as compared to the same period in 2011.

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 load. Additionally, the cost of electricity is expected to be impacted by the higher cost of procuring renewable energy as the Utility increases the amount of its renewable energy deliveries to comply with current and future California law and regulatory requirements. The Utility’s future cost of electricity also will be affected by legislation and rules applicable to GHG emissions. (See “Environmental Matters” below.)

Natural Gas Operating Revenues

The Utility’s natural gas operating revenues consist of amounts charged for transportation, distribution, and storage services, as well as amounts charged to customers to recover the cost of natural gas procurement and public purpose program expenses.

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

	Three months ended         March 31,
(in millions)	2012		2011
Revenues excluding passed-through costs		$ 453		$ 404
Revenues for recovery of passed-through costs		416		576
Total natural gas operating revenues		$ 869		$ 980

The Utility’s natural gas operating revenues, including revenues intended to recover costs that are passed through to customers, decreased by $111 million, or 11%, in the three months ended March 31, 2012 as compared to the same period in 2011. This reflects a $160 million decrease in the costs which are passed through to customers and do not impact net income, primarily due to a decrease in the cost of natural gas. Natural gas operating revenues, excluding costs passed through to customers, increased by $49 million, primarily due to additional base revenues as authorized in the 2011 GT&S rate case decision issued in April 2011 and by the 2011 GRC decision issued in May 2011. Of the total increase in authorized base revenues, approximately $27 million represents base revenues that were authorized and recorded in the three months ended June 30, 2011, but pertained to the three months ended March 31, 2011.

The Utility’s operating revenues for natural gas transmission and storage services in 2013 and 2014 will reflect revenue increases that have been authorized by the CPUC in the 2011 GT&S rate case decision. Additionally, the Utility’s revenues for natural gas distribution services in 2013 (excluding passed-through costs) will reflect revenue increases authorized by the CPUC in the 2011 GRC decision. The Utility’s future gas operating revenues also will be impacted by changes in the cost of natural gas, natural gas throughput volume, and other factors.

Cost of Natural Gas

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

45

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

	Three months ended         March 31,
(in millions)	2012		2011
Cost of natural gas sold		$ 294		$ 461
Transportation cost of natural gas sold		49		47
Total cost of natural gas		$ 343		$ 508
Average cost per Mcf (1) of natural gas sold		$ 2.97		$ 4.52
Total natural gas sold (in millions of Mcf)		99		102
(1)  One thousand cubic feet

The Utility’s total cost of natural gas decreased by $165 million, or 32%, in the three months ended March 31, 2012 as compared to the same period in 2011. The decrease was primarily due to a lower average market price of natural gas during 2012.

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 ability to earn its authorized rate of return depends in large part on the success of its ability to manage expenses and to achieve operational and cost efficiencies.

The Utility’s operating and maintenance expenses (including costs currently passed through to customers) increased by $140 million, or 11%, in the three months ended March 31, 2012, as compared to the same period in 2011. Total costs associated with natural gas matters increased by $112 million, from $51 million in the three months ended March 31, 2011 to $163 million in the three months ended March 31, 2012. The costs for 2012 included $104 million to validate pipeline operating pressures and perform other pipeline-related activities and also included a contribution of $70 million to the City of San Bruno. These expenses were partially offset by $11 million in insurance recoveries for third-party claims related to the San Bruno accident. (See “Natural Gas Matters” below.) The remaining increase in operating and maintenance expense was primarily attributable to additional environmental remediation costs of $75 million associated with the Hinkley natural gas compressor site (see “Environmental Matters” below), which was partially offset by a $48 million decrease in storm-related costs as compared to 2011. The change in costs passed through to customers was immaterial.

The Utility forecasts that it will incur pipeline-related costs associated with its natural gas pipeline system ranging from $450 million to $550 million in 2012 (including $104 million incurred during the three months ended March 31, 2012) which may not be recoverable through rates. (See “Natural Gas Matters – CPUC Rulemaking Proceeding” below.) Future operating and maintenance expense also will be affected by the ultimate amount incurred for third-party claims related to the San Bruno accident, including the amount of punitive damages, if any; related insurance recoveries; and the ultimate amount of civil or criminal penalties that may be imposed on the Utility.

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation and amortization expense consists of depreciation and amortization of plant and regulatory assets, and decommissioning expenses associated with fossil and nuclear decommissioning. The Utility’s depreciation, amortization, and decommissioning expenses increased by $94 million, or 19%, in the three months ended March 31, 2012, as compared to the same period in 2011 primarily due to 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 be impacted as a result of capital additions and the implementation of new depreciation rates as authorized by the CPUC in future GRC and GT&S rate cases, and by the FERC in transmission owner (“TO”) rate cases.

46

Interest Income

The Utility’s interest income decreased by less than $1 million, in the three months ended March 31, 2012, as compared to the same period in 2011.

The Utility’s interest income in future periods will be primarily affected by changes in interest rates, changes in regulatory balancing accounts, and the balance of funds held in escrow pending resolution of the Chapter 11 disputed claims. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements.)

Interest Expense

The Utility’s interest expense decreased by $3 million, or 2%, in the three months ended March 31, 2012, as compared to the same period in 2011, primarily due to an increase in allowance for funds used during construction (“AFUDC”) income related to debt.

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 “Liquidity and Financial Resources” below.)

Other Income, Net

The Utility’s other income, net increased by $6 million in the three months ended March 31, 2012, as compared to the same period in 2011. The increase was primarily due to an increase in AFUDC as the average balance of construction work in progress was higher in 2012 as compared to 2011.

Income Tax Provision

The Utility’s income tax provision decreased by $18 million, or 14%, in the three months ended March 31, 2012, as compared to the same period in 2011. The effective tax rates were 33% and 39% for 2012 and 2011, respectively. The effective tax rate for 2012 decreased as compared to 2011, mainly due to a benefit associated with a loss carryback recorded during the period and non tax-deductible penalties recorded in 2011 with no comparable amount in the current year.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

The Utility’s ability to fund operations and make distributions to PG&E Corporation and preferred stockholders depends on the levels of its operating cash flows and access to the capital and credit markets. The levels of the Utility’s operating cash and short-term debt fluctuate as a result of seasonal load, volatility in energy commodity costs, collateral requirements related to price risk management activities, 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 maintain its CPUC-authorized capital structure and to fund its capital expenditures. 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.

47

Revolving Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and the Utility’s commercial paper program at March 31, 2012:

(in millions)	Termination   Date	Facility Limit		Letters of Credit   Outstanding		Borrowings		Commercial  Paper		Facility  Availability
PG&E Corporation	May 2016		$ 300  (1)		$ -		$ -		$ -		$ 300
Utility	May 2016		3,000 (2)		367		-		1,145 (3)		1,488 (3)
Total revolving credit facilities			$ 3,300		$ 367		$ -		$ 1,145		$ 1,788
(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. (3)  The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facility.

For the three months ended March 31, 2012, there were no borrowings on PG&E Corporation’s and the Utility’s revolving credit facilities. For the three months ended March 31, 2012, the average outstanding commercial paper balance was $1.2 billion and the maximum outstanding balance during the period was $1.4 billion.

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 own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting capital stock of the Utility. At March 31, 2012, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

2012 Financings

Utility

On April 16, 2012, the Utility issued $400 million principal amount of 4.45% Senior Notes due April 15, 2042. The proceeds from the issuance were used to repay a portion of outstanding commercial paper and for general corporate purposes.

On April 2, 2012, the Utility repurchased all of the $50 million principal amount of pollution control bonds Series 2010 E that were subject to mandatory tender on that same date. The Utility will hold the bonds until they are remarketed to investors or retired.

During the three months ended March 31, 2012, the Utility received equity contributions of $385 million from PG&E Corporation to maintain the 52% equity component of the Utility’s CPUC-authorized capital structure.

PG&E Corporation

During the three months ended March 31, 2012, PG&E Corporation sold 1,934,310 shares of its common stock under the Equity Distribution Agreement executed in November 2011 for cash proceeds of $80 million, net of fees and commissions. At March 31, 2012, PG&E Corporation had the ability to issue an additional $219 million of its common stock under the Equity Distribution Agreement. On March 20, 2012, PG&E Corporation sold 5,900,000 shares of its common stock in an underwritten public offering for cash proceeds of $254 million, net of fees and commissions. In addition, during the three months ended March 31, 2012, PG&E Corporation issued 1,429,307 shares of its common stock under its 401(k) plan, its Dividend Reinvestment and Stock Purchase Plan, and upon exercises of employee stock options for total cash proceeds of $53 million. PG&E Corporation used the cash proceeds for general corporate purposes and to contribute equity to the Utility.

48

Future Financing and Liquidity Needs

The amount and timing of the Utility’s future financing and liquidity needs will depend on various factors, including:

• the amount of cash generated through normal business operations;

• the timing and amount of capital expenditures;

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

• the timing and amount of payments, including punitive damages, if any, 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 penalties imposed on the Utility in connection with the investigations and enforcement matters pending against the Utility related to the San Bruno accident and the Utility’s natural gas pipeline system;

• the timing and amount of costs associated with the Utility’s natural gas pipeline system, and the amount that is not recoverable through rates (see “Operating and Maintenance” above and “Natural Gas Matters” below);

• 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 and credit markets, and other factors.

PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure. On April 20, 2012, the Utility filed an application to begin the cost of capital proceeding in which the CPUC will determine the Utility’s authorized capital structure and rates of return beginning on January 1, 2013. A change in the Utility’s authorized capital structure may impact PG&E Corporation’s and the Utility’s future debt and equity financing needs. (See the “2013 Cost of Capital Proceeding” discussion in “Regulatory Matters” below.)

Additionally, charges incurred by the Utility that are not recoverable through customer rates will increase the Utility’s equity needs. Additional equity issued by PG&E Corporation would increase the number of common shares outstanding, which could have a dilutive effect on future earnings per common share.

Dividends

The following table summarizes dividends paid by PG&E Corporation and the Utility during the three months ended March 31, 2012:

(in millions)
PG&E Corporation
Common stock dividends paid	$ 182
Utility
Common stock dividends paid	$ 179
Preferred stock dividends paid	3

On February 15, 2012, the Board of Directors of PG&E Corporation declared a dividend of $0.455 per share, totaling $193 million, of which $187 million was paid on April 15, 2012 to shareholders of record on March 30, 2012. The remaining $6 million was reinvested under the Dividend Reinvestment and Stock Purchase Plan.

On February 15, 2012, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on May 15, 2012, to shareholders of record on April 30, 2012.

As the Utility focuses on improving the safety and reliability of its natural gas and electric operations, and subject to the outcome of the matters described under “Natural Gas Matters” above, PG&E Corporation expects that its Board of Directors will maintain the current annual common stock dividend of $1.82 per share through 2012.

49

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 three months ended March 31, 2012 and 2011 were as follows:

	Three months ended
	March 31,
(in millions)	2012		2011
Net income		$ 231		$ 201
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		584		490
Allowance for equity funds used during construction		(27)		(20)
Deferred income taxes and tax credits, net		153		99
Other		57		29
Effect of changes in operating assets and liabilities:
Accounts receivable		218		69
Inventories		50		65
Accounts payable		(182)		190
Income taxes receivable/payable		30		34
Other current assets and liabilities		(69)		(196)
Regulatory assets, liabilities, and balancing accounts, net		(171)		(10)
Other noncurrent assets and liabilities		75		144
Net cash provided by operating activities		$ 949		$ 1,095

In the three months ended March 31, 2012, net cash provided by operating activities decreased by $146 million compared to the same period in 2011 primarily due to an increase of $104 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 the timing and amount of customer billings and collections.

On December 17, 2010, the Tax Relief Act was signed into law, generally allowing the Utility to accelerate depreciation by deducting 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 its 2012 federal tax payment will be reduced depending on the amount and timing of the Utility’s qualifying capital additions.

Future cash flow from operating activities will be affected by the timing and amount of payments, including punitive damages, if any, that may be awarded, to third parties in connection with the San Bruno accident, any related insurance recoveries, any civil or criminal penalties that may be imposed on the Utility, and higher operating and maintenance costs associated with the Utility’s natural gas and electric operations, among other factors. (See “Operating and Maintenance” above and “Natural Gas Matters” below.)

Investing Activities

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

50

The Utility’s cash flows from investing activities for the three months ended March 31, 2012 and 2011 were as follows:

	Three months ended                  March 31,
(in millions)	2012		2011
Capital expenditures		$ (1,094)		$ (945)
(Increase) Decrease in restricted cash		(5)		132
Proceeds from sales and maturities of nuclear decommissioning trust investments		351		726
Purchases of nuclear decommissioning trust investments		(370)		(735)
Other		3		7
Net cash used in investing activities		$ (1,115)		$ (815)

Net cash used in investing activities increased by $300 million in the three months ended March 31, 2012 compared to the same period in 2011. This increase was partially due to an increase of $149 million in capital expenditures in the three months ended March 31, 2012. In addition, in the three months ended March 31, 2011, there was a decrease of $132 million in restricted cash that primarily reflected $128 million in releases from escrow for settled or withdrawn Chapter 11 disputed claims, as compared to a $5 million increase in restricted cash in the three months ended March 31, 2012.

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 three months ended March 31, 2012 and 2011 were as follows:

	Three months ended
	March 31,
(in millions)	2012		2011
Net (repayments) issuances of commercial paper, net of discount of $1 in 2012 and in 2011		$ (245)		$ 415
Long-term debt matured		-		(500)
Energy recovery bonds matured		(102)		(97)
Preferred stock dividends paid		(3)		(4)
Common stock dividends paid		(179)		(179)
Equity contribution		385		65
Other		51		21
Net cash used in financing activities		$ (93)		$ (279)

In the three months ended March 31, 2012, net cash used in financing activities decreased by $186 million compared to the same period in 2011. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities and the level of cash provided by or used in investing activities. The Utility generally utilizes equity contributions from PG&E Corporation and long-term senior unsecured debt issuances to maintain its CPUC-authorized capital structure and to fund its capital expenditures, and relies on short-term debt to fund temporary financing needs.

PG&E Corporation

As of March 31, 2012, PG&E Corporation 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 $396 million to these companies in exchange for the right to receive benefits from local rebates, federal grants, and a share of the customer payments made to these companies. PG&E Corporation’s financial exposure from these agreements is generally limited to its lease payments and investment contributions to these companies. As of March 31, 2012, PG&E Corporation had made total payments of $360 million under these agreements and received $160 million in benefits and customer payments. 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.

51

CONTRACTUAL COMMITMENTS

PG&E Corporation and the Utility enter into contractual commitments in connection with future obligations that 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 2011 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

The Utility makes capital investments in its electric generation and electric and natural gas transmission and distribution infrastructure to maintain and improve system reliability, safety, and customer service; to extend the life of or replace existing infrastructure; and to add new infrastructure to meet growth. Most of the Utility’s revenue requirements to recover forecasted capital expenditures are authorized in the GRC, TO, and GT&S rate cases. The Utility 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.

Oakley Generation Facility

On March 16, 2012, the California Court of Appeal granted The Utility Reform Network’s (“TURN”) appeal of the CPUC’s decision in December 2010 that had approved the Utility’s purchase of a 586-megawatt natural gas-fired facility in Oakley, California (“Oakley Generation Facility”). The Court determined that the CPUC had not allowed TURN, or other parties, sufficient opportunity to protest the Oakley Generation Facility, conduct discovery, or present evidence concerning the Utility’s purchase and sale agreement. The facility is fully permitted and construction began in June 2011. On March 30, 2012, in response to the Court’s ruling, the Utility filed a new application with the CPUC requesting approval of the Oakley Generation Facility and an amended and restated purchase and sale agreement between the Utility and Contra Costa Generating Station LLC. The Utility has requested that the CPUC issue a final decision on the application by October 2012.

Natural Gas Pipeline Safety Enhancement Plan

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

NATURAL GAS MATTERS

As discussed in the 2011 Annual Report, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows, have continued to be negatively affected by regulatory proceedings, investigations, and civil lawsuits related to the San Bruno accident and the Utility’s natural gas pipeline system. The current status of these matters and new developments are summarized here and described more fully below.

On March 12, 2012, the Utility and the City of San Bruno entered into an agreement under which the Utility contributed $70 million to support the city and the community’s recovery efforts. This amount is not related to the third-party claims for personal injury and property damage described below. The contribution was recorded as a component of operating and maintenance expense in PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Income for the three months ended March 31, 2012.

52

The CPUC is conducting three investigations pertaining to the Utility’s natural gas operations. In addition, the Utility has filed reports notifying the CPUC that the Utility has identified instances in which the Utility did not comply with various regulations and CPUC orders applicable to the Utility’s natural gas operating practices. PG&E Corporation and the Utility believe it is probable that the CPUC will impose a material amount of penalties on the Utility in connection with these pending investigations and self-reports. (See “Pending CPUC Investigations and Enforcement Matters” below.) It is also reasonably possible that an investigation of the San Bruno accident by state and federal authorities will result in the imposition of civil or criminal penalties on the Utility. (See “Criminal Investigation” below.) In addition to these investigations, various 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 and property damage, and other relief, including punitive damages. (See “Pending Lawsuits and Other Claims” below.)

Finally, in connection with the CPUC’s proceeding to develop and adopt safety-related changes to its regulation of natural gas transmission pipelines, evidentiary hearings were held in March 2012 on the Utility’s proposed pipeline safety enhancement plan. The Utility is uncertain what portion of plan-related costs will ultimately be recoverable through rates and when such costs will be recovered. (See “CPUC Rulemaking Proceeding” below.)

Pending CPUC Investigations and Enforcement Matters

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

On March 12, 2012, the CPUC’s Consumer Protection and Safety Division (“CPSD”) filed testimony in the CPUC’s ongoing investigation pertaining to safety recordkeeping for the Utility’s gas transmission pipeline (Line 132) that ruptured in the San Bruno accident, as well as for its entire gas transmission system. The testimony consisted of reports by the CPSD’s records management consultant and an engineering consultant. Among other findings, the consultants’ reports concluded that: the Utility’s recordkeeping practices have been deficient and have diminished pipeline safety; the San Bruno accident may have been prevented had the Utility managed its records properly over the years; and that the Utility has been operating, and continues to operate, without a functional integrity management program. On March 30, 2012, the CPSD filed supplemental testimony to address additional recordkeeping items and to list specific violations the CPSD alleges that the Utility committed based on the findings of the consultants’ reports. The Utility’s responses to the CPSD’s reports are due on June 25, 2012. Evidentiary hearings are scheduled for September 2012 with a final decision expected in February 2013. If the CPUC finds that the Utility has violated any rule, regulation or law, it will schedule a second phase to assess penalties. (See “Penalties Conclusion” below.)

CPUC Investigation Regarding Class Location Designations for Pipelines

On April 2, 2012, the Utility filed its second report in response to the CPUC’s ongoing investigation pertaining to the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density. The Utility provided further information about the classification of its transmission pipeline segments and reported that 159 miles of pipeline (as compared to 162 miles previously reported) had a current class location designation that was higher than reflected in its Geographical Information System. Most of the misclassifications were attributable to the Utility’s failure to correctly identify development or well-defined areas near the pipeline. The Utility also reported that it could not confirm that all transmission lines were patrolled as required by the Utility’s procedures and that the Utility has begun a system-wide review of patrol records for all transmission pipelines. Evidentiary hearings are scheduled for August 2012. (See “Penalties Conclusion” below.)

CPUC Investigation Regarding San Bruno Accident

As discussed in the 2011 Annual Report, the CPUC opened an investigation in January 2012 to determine whether the Utility violated applicable laws and regulations in connection with the San Bruno accident, citing the findings, allegations, and financial recommendations made by the CPSD in an investigation report issued in January 2012. The CPUC stated that the scope of the investigation will include all past operations, practices and other events or courses of conduct that could have led to or contributed to the San Bruno accident, as well as, the Utility’s compliance with CPUC orders and resolutions issued since the date of the San Bruno accident. Evidentiary hearings are scheduled for September and October 2012 with a final decision expected in January 2013. (See “Penalties Conclusion” below.)

53

Other Natural Gas Compliance Matters

In December 2011, the CPUC delegated authority to its staff to enforce compliance with certain state and federal regulations related to the safety of natural gas facilities and utilities’ natural gas operating practices, including the authority to issue citations and impose penalties. The CPUC also established a requirement that California gas corporations provide notice to the CPUC of any self-identified or self-corrected violations of these regulations. Since the citation program was adopted, the Utility has filed 12 self-reports with the CPUC. In one of these self-reports, the Utility reported that it failed to conduct periodic leak surveys because the Utility had not included 16 gas distribution maps in its leak survey schedule. In response to this self-report, the CPSD issued a citation to the Utility that included a penalty of approximately $17 million. On April 19, 2012, the CPUC denied the Utility’s appeal of the $17 million penalty and concluded that the CPSD had appropriately determined the number of violations. The Utility was ordered to pay the penalty within 30 days. The CPSD has not yet taken action with respect to the Utility’s other self-reports, including a follow-up report stating that the Utility had not considered an additional 46 gas distribution maps in its leak survey schedule. (The Utility has completed all of the missed leak surveys.) The CPSD may issue additional citations and impose penalties on the Utility associated with these or future reports that the Utility may file. (See “Penalties Conclusion” below.)

Penalties Conclusion

The CPUC can impose penalties of up to $20,000 per day, per violation, for violations of applicable laws, rules, and orders in connection with the pending investigations described above. For violations that are considered to have occurred on or after January 1, 2012, the statutory penalty has increased to a maximum of $50,000 per day, per violation. (Under the CPUC’s delegation of authority, the CPSD is required to impose the maximum statutory penalty.) The CPUC and CPSD have wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the number of violations; the length of time the violations existed; the severity of the violations, including the type of harm caused by the violations and the number of persons affected; conduct taken to prevent, detect, disclose or rectify the violations; and the financial resources of the regulated entity. The CPUC has stated that it is prepared to impose very significant penalties if the evidence adduced at hearing establishes that the Utility’s policies and practices contributed to the loss of life, injuries, or loss of property resulting from the San Bruno accident.

PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties of at least $200 million on the Utility as a result of these investigations and the Utility’s self-reports and have accrued this amount as of March 31, 2012 and December 31, 2011. (The amount accrued included the $17 million penalty described above.) In reaching this conclusion, management has considered, among other factors, the findings and allegations contained in the CPSD’s reports; the Utility’s self-reports to the CPUC; and the outcome of prior CPUC investigations of other matters. PG&E Corporation and the Utility are unable to estimate the reasonably possible amount of penalties in excess of the amount accrued, and such amounts could be material. The ultimate amount of penalties imposed on the Utility will be affected by many factors, including how many violations the CPUC will find the Utility has committed; whether the penalties will be calculated separately for each matter above or in the aggregate; whether the CPSD will issue additional citations based on the Utility’s self-reports; and whether and how the CPUC will consider the broader impacts of the San Bruno accident on the Utility’s results of operations, financial condition, and cash flows.

The Utility’s estimates and assumptions are subject to change as the CPUC investigations progress and more information becomes known, and such changes could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. (See Note 10 to the Condensed Consolidated Financial Statements.)

Criminal Investigation

The U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo County District Attorney’s Office are conducting an investigation of the San Bruno accident. The Utility is cooperating with the investigation. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any civil or criminal penalties that could be imposed on the Utility.

Pending Lawsuits and Other Claims

In addition to the investigations and proceedings discussed above, approximately 110 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, have been filed against PG&E Corporation and the Utility in connection with the San Bruno accident on behalf of approximately 380 plaintiffs. The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages. These cases have been coordinated and assigned to one judge in the San Mateo County Superior Court, and a trial date of July 23, 2012 has been set for the first of these cases.

54

On April 6, 2012, PG&E Corporation and the Utility filed various motions to request that the Court dismiss certain claims, including the plaintiffs’ claims for punitive damages, based upon a lack of evidence to support such claims. The plaintiffs’ oppositions to the motions are due June 8, 2012. The Court will hold a hearing on June 22, 2012 to consider the motions.

As of March 31, 2012, the Utility has incurred a cumulative charge of $375 million for estimated third-party claims, and of this amount, has made cumulative payments of $132 million. The Utility estimates it is reasonably possible that it may incur as much as an additional $225 million for third-party claims, for a total possible loss of $600 million. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with punitive damages, if any, related to these matters. (See Note 10 to the Condensed Consolidated Financial Statements.)

The Utility has liability insurance from various insurers who provide coverage at different policy limits that are triggered in sequential order or “layers.” Generally, as the policy limit for a layer is exhausted, the next layer of insurance becomes available. The aggregate amount of this insurance coverage is approximately $992 million in excess of a $10 million deductible. The Utility has continued to submit insurance claims to certain insurers for the lower layers and recognized $11 million for insurance recoveries for the three months ended March 31, 2012. This is in addition to the $99 million recognized for insurance recoveries during 2011. Although the Utility believes 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 future insurance recoveries. (See Note 10 to the Condensed Consolidated Financial Statements.)

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

In February 2011, the Board authorized PG&E Corporation to reject a shareholder demand that the Board (1) institute an independent investigation of the San Bruno accident and related alleged safety issues; (2) seek recovery of all costs associated with such issues through legal proceedings against those determined to be responsible, including Board members, officers, other employees, and third parties; and (3) adopt corporate governance initiatives and safety programs. The Board also reserved the right to commence further investigation or litigation regarding the San Bruno accident if the Board deems such investigation or litigation appropriate.

CPUC Rulemaking Proceeding

On March 29, 2012, the CPUC concluded evidentiary hearings on the Utility’s proposed pipeline safety enhancement plan, which was submitted in August 2011. As previously disclosed, the Utility forecasted that its total plan-related costs over a four-year period (2011 through 2014) would be approximately $2.2 billion, which included an estimated $1.4 billion in capital expenditures and $750 million in expenses. The Utility had proposed that most plan-related costs incurred from 2012 through 2014 be recovered through rates. Several parties submitted testimony on the Utility’s proposed plan, including recommendations that the Utility be prohibited from recovering all or a portion of plan-related costs through rates and that the Utility’s rate of return on any authorized capital expenditures be reduced or limited to the costs of debt. The CPUC is scheduled to issue a proposed decision in August 2012 and a final decision in September 2012. The CPUC has not yet taken any action on the Utility’s request to establish a memorandum account to track plan-related costs incurred after January 1, 2012 for potential future recovery. As described above in “Operating and Maintenance,” during the three months ended March 31, 2012, the Utility incurred $104 million in pipeline-related costs, which primarily included amounts associated with its proposed plan.

Additionally, on April 19, 2012, the CPUC expanded the scope of its rulemaking proceeding (to develop safety-related changes to its regulation of natural gas transmission operators) to also include gas distribution matters, to comply with recently enacted California law (Senate Bill 705). The law requires each California gas corporation to develop and implement a plan for the safe and reliable operation of its gas pipeline facilities, and for the CPUC to accept, modify, or reject the plan by the end of 2012. The safety plans must be filed with the CPUC by June 29, 2012, but the CPUC noted that the Utility can refer to its proposed pipeline safety enhancement plan applicable to its gas transmission system. (The Utility anticipates that the costs associated with its gas distribution safety plan will be addressed in the Utility’s next GRC.) The CPUC also ordered that CPSD-managed management and financial audits of each gas corporation be conducted to address safety-related corporate culture and historical spending. An administrative law judge will decide the scope and timing of the audits and whether hearings will be held to consider the gas safety plans.

55

The Utility forecasts that it will incur costs associated with its natural gas pipeline system ranging from $450 million to $550 million in 2012, including estimated costs related to its proposed pipeline safety enhancement plan, that may not be recoverable from customers. The ultimate amount of pipeline-related costs that are recoverable from customers will depend on various factors, including when and whether the CPUC takes action on the Utility’s request to establish a memorandum account to track costs incurred under its pipeline safety enhancement plan, the scope and timing of the work to be performed under the Utility’s plan as approved by the CPUC, whether the CPUC determines that the Utility may not recover costs to perform certain work under the Utility’s plan, and whether additional costs will be incurred to address any other pipeline matters identified by the Utility or in order to comply with new regulatory or legislative requirements.

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC and other federal and state regulatory agencies. The resolutions of these and other proceedings may affect PG&E Corporation’s and the Utility’s results of operations and financial condition. Significant regulatory developments that have occurred since the 2011 Annual Report was filed with the Securities and Exchange Commission (“SEC”) are discussed below.

2013 Cost of Capital Proceeding

On April 20, 2012, the Utility filed an application with the CPUC to request that the CPUC authorize the Utility’s capital structure (i.e., the relative weightings of common equity, preferred equity, and debt), as well as the rates of return on each capital structure component, for the Utility’s electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2013. (The FERC has jurisdiction over the rates of return for the Utility’s electric transmission rate base.) The following table compares the currently authorized capital structure and rates of return which will remain in effect through 2012 with those requested in the Utility’s application:

	Currently Authorized									Requested
	Cost			Capital   Structure			Weighted  Cost			Cost			Capital   Structure			Weighted  Cost
Long-term debt		6.05	%		46.0	%		2.78	%		5.69	%		47.0	%		2.67	%
Preferred stock		5.68	%		2.0	%		0.11	%		5.60	%		1.0	%		0.06	%
Return on common equity		11.35	%		52.0	%		5.90	%		11.00	%		52.0	%		5.72	%
Overall Rate of Return								8.79	%								8.45	%

The Utility also has requested that the CPUC approve the continuation of the annual cost of capital adjustment mechanism that has been in effect since 2008. The mechanism would be triggered in a particular year if the 12-month October-through-September average of the applicable Moody’s Investors Service utility bond index increases or decreases by more than 100 basis points from the benchmark. If the adjustment mechanism is triggered, the Utility’s authorized ROE beginning on the next January 1^st would be adjusted by one-half of the increase or decrease. In addition, the Utility’s authorized long-term debt and preferred stock costs would be updated to reflect actual August month-end embedded costs and forecasted interest rates for variable long-term debt and new long-term debt and preferred stock scheduled to be issued in the coming year. In any year where the 12-month average yield triggers an automatic ROE adjustment, that average would become the new benchmark.

The Utility has proposed that any changes to its revenue requirements resulting from the CPUC’s cost of capital decision be effective January 1, 2013. The Utility estimates that its 2013 revenue requirement associated with the requested cost of capital would be approximately $100 million less than the currently authorized revenue requirement. The Utility has proposed to file its next full cost of capital application with the CPUC in April 2015 for test year 2016. The Utility expects that the CPUC will issue a final decision by the end of 2012.

2014 General Rate Case

In the Utility’s 2014 GRC, the CPUC will determine the amount of revenue requirements the Utility is authorized to collect through rates for its electric generation operations and electric and natural gas distribution for the period beginning January 1, 2014 through December 31, 2016. In July 2012, the Utility expects to submit a draft of the Utility’s GRC application to the CPUC that constitutes the Utility’s notice of intent (“NOI”) that it plans to file its formal GRC application in December 2012. Before the formal application is filed, the CPUC’s Division of Ratepayer Advocates (“DRA”) will review the NOI.

The Executive Director of the CPUC recently directed the Utility to include, as part of the NOI, a risk assessment of the safety and security of the Utility’s entire system, both gas and electric, a comparison to industry best practices, and a description of and justification for the Utility’s risk mitigation program and policies. The Utility also must provide testimony

56

to identify and prioritize areas of risk and the underlying rationale for the assessments; explain the overall policy of the Utility’s safety and security measures, including both physical security and cyber security of the system; explain how safety and security are incorporated into corporate policies, goals and culture; and describe the efforts being made to bolster system safety and security. After the NOI is been submitted, independent consultants hired by the CPSD and paid for by the Utility will review the key public safety issues raised or addressed in the NOI, provide information about the quality and cost-effectiveness of the Utility’s safety and security proposals, and compare the proposals to industry best practices and standards. The Executive Director stated that the DRA’s evaluation and the consultant’s reviews would be conducted concurrently and that the Utility would be able to respond to the consultants’ reviews either when the Utility files its formal GRC application or later in the proceeding. Among other things, the Utility’s response may include a revised revenue requirement forecast to address specific recommendations in the reviews.

Diablo Canyon Nuclear Power Plant

On March 12, 2012, the NRC issued several orders to the owners of all U.S. operating nuclear reactors to implement the highest-priority recommendations issued by the NRC’s task force, which had been appointed to review the NRC’s safety regulations based on the lessons learned from the March 2011 earthquake and tsunami that caused significant damage to nuclear facilities in Japan. As applied to the Utility, the orders require the Utility to develop mitigation strategies to respond to potential extreme natural events resulting in the loss of power at Diablo Canyon and to enhance the instrumentation used in the plant’s spent fuel pool to better monitor water temperature. The NRC is scheduled to issue implementation guidance in August 2012. The Utility, as well as other nuclear power plant owners, will then be required to submit an integrated plan, including a description of how compliance with the orders will be achieved, to the NRC by February 2013. After reviewing the plans, the NRC plans to issue facility-specific orders, as necessary, imposing license conditions that address the requirements of the orders. Each nuclear power plant owner will be required to be in full compliance with the NRC orders within two refueling outages or by December 31, 2016, whichever comes first. The NRC is expected to continue to examine how to best address the task force’s remaining recommendations.

Although the Utility has already taken significant action at Diablo Canyon to address concerns raised by the events in Japan, the Utility expects to incur additional capital expenditures and expenses to comply with the new requirements. The Utility is currently evaluating the NRC’s orders and plans to seek CPUC approval to recover estimated costs to comply with the requirements as part of the 2014 GRC or by a separate application. In addition, the NRC has also issued a letter requesting additional information from nuclear power plant owners related to their evaluation of seismic and flooding hazards and emergency preparedness. The NRC may consider this information in future regulatory proceedings or actions.

The Utility has been conducting extensive seismological studies of the area at and surrounding Diablo Canyon, as had been recommended by the California Energy Commission. The Utility expects that the studies will not be completed until 2013 or 2014. The CPUC is scheduled to issue a decision in August 2012 on the Utility’s request to recover an additional $47 million to conduct these studies. Actual costs may differ from estimates depending on the procurement process, environmental permitting processes, and required environmental mitigation.

Deployment of SmartMeter^TM Technology

The Utility has been installing an advanced metering infrastructure, using SmartMeter™ technology, throughout its service territory. On February 1, 2012, the CPUC issued a decision that requires the Utility to allow residential customers the choice to have traditional meters rather than meters equipped with advanced SmartMeter™ technology. The decision found that the Utility should be permitted to recover costs associated with allowing customers to opt-out of the SmartMeter™ program to the extent that those costs are appropriate, reasonable, and not already being recovered in rates. The CPUC will conduct a second phase to address cost recovery issues. Until a final decision on cost recovery is issued, the Utility is authorized to establish memorandum accounts to track costs for potential future recovery, which will establish the extent to which opt-out costs ultimately will be recoverable.

On April 25, 2012, the CPUC issued an order to show cause to the Utility and instituted an investigation into whether the Utility violated its obligation to provide reasonable service under applicable laws, rules, or orders due to the improper actions taken by a management employee who allegedly misrepresented his identity in order to gain access to the websites of various public groups that opposed installation of the Utility’s advanced metering infrastructure. If the CPUC determines that the Utility violated applicable law, the CPUC may impose penalties on the Utility or require other remedial actions.

Other Matters

In April 2012, the Utility reported to the CPUC staff the results of its re-inspection of approximately 16,000 overhead electric facilities. (The re-inspection had been prompted in the fourth quarter of 2011 after the Utility determined that some underground electric facilities had not been inspected.) During the re-inspections, the Utility identified various

57

maintenance tasks to be performed. These tasks have been prioritized and entered into the Utility’s maintenance work management system.

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 2011 Annual Report.) These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous wastes; the reporting and reduction of carbon dioxide and other GHG emissions; the discharge of pollutants into the air, water, and soil; and the transportation, handling, storage, and disposal of spent nuclear fuel. Significant developments that have occurred since the 2011 Annual Report was filed with the SEC are discussed below.

Remediation

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

Hinkley Natural Gas Compressor Site

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

In October 2011, the Regional Board ordered the Utility to provide an interim and permanent replacement water system for certain resident households that have domestic wells containing hexavalent chromium concentrations above the 3.1 parts per billion background level. Following the issuance of this order, the Utility filed a petition with the California State Water Resources Control Board (“State Board”) to contest certain provisions of the order. On April 9, 2012, the Utility informed the Regional Board that the Utility would provide approximately 300 resident households located up to one mile from the chromium plume boundary with two options for a replacement water supply. Eligible residents may have an individual water treatment system on the property or, where feasible, have a deeper well installed to draw water from a lower aquifer. Alternatively, eligible residents may choose to have the Utility purchase their properties. The Utility expects to begin implementing this program later in 2012. The Utility will continue the program until the State of California has adopted a drinking water standard specifically for hexavalent chromium or for up to five years at which time the program will be evaluated. The Utility has requested the Regional Board’s acknowledgement that the Utility’s program complies with the October 2011 order.

The Regional Board is also evaluating the Utility’s final groundwater remediation plan that proposes using a combination of remedial methods, including using pumped groundwater from extraction wells to irrigate agricultural land and in-situ treatment of the contaminated water. The Regional Board stated it anticipates releasing a draft environmental impact report (“EIR”) in the second half of 2012 and that it will consider certification of the final EIR, which will include the final approved remediation plan, by the end of 2012.

As of March 31, 2012, $218 million was accrued in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Hinkley natural gas compressor site, compared to $149 million accrued at December 31, 2011. The increase primarily reflects the Utility’s best estimate of future probable costs associated with providing water replacement systems to eligible residents or purchasing property from eligible residents, as described above. Remediation costs for the Hinkley natural gas compressor site are not recovered from customers.

Future costs will depend on many factors, including when and whether the Regional Board certifies the final remediation plan, the extent of the groundwater chromium plume, the levels of hexavalent chromium the Utility is required to use as the standard for remediation, and the number of eligible residents who participate in the Utility’s program described above. As more information becomes known regarding these factors, estimates and assumptions regarding the amount of liability incurred may be subject to further changes. Future changes in estimates may have a material impact on PG&E

58

Corporation’s and the Utility’s financial condition, results of operations, and cash flows. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements for a discussion of estimated environmental remediation liabilities.)

Climate Change

California Assembly Bill 32 (“AB 32”) requires the gradual reduction of statewide GHG emissions to the 1990 level by 2020. The California Air Resources Board (“CARB”) has approved various regulations, including regulations to establish a state-wide, comprehensive “cap and trade” program that sets gradually declining limits (or “caps”) on the amount of GHGs that may be emitted by the major sources of GHG emissions. The cap and trade program’s first compliance period, beginning January 1, 2013, will apply to the electricity generation and large industrial sector. The next compliance period, from January 1, 2015 through December 31, 2017, also will apply to the natural gas supply and transportation sectors. (The last compliance period, from January 1, 2018 through December 31, 2020, will apply to all sectors.) Before the first compliance period begins the CARB will issue a fixed number of emission allowances (i.e., the rights to emit GHGs), some of which will be allocated at no charge to regulated electric distribution utilities for their customers’ benefit. The CARB will sell other allowances at an auction, the first of which is scheduled to be held on November 14, 2012.

Under the CARB’s regulations, emitters (i.e., those entities with a compliance obligation) also can purchase “offset credits” from certified parties that develop environmental projects in sectors not regulated under the cap, such as reforestation and methane capture projects. These emitters would be able to use the offset credits to satisfy up to 8% of their compliance obligations. In March 2012, a lawsuit was filed in San Francisco Superior Court challenging the CARB’s regulations pertaining to offset credits. It is uncertain when this challenge will be resolved and how the resolution will affect implementation of the CARB’s cap-and-trade program.

Renewable Energy Resources

California’s new renewable portfolio standard (“RPS”) program increases the amount of renewable energy that load-serving entities (“LSE”s), such as the Utility, must deliver to their customers from at least 20% of their total retail sales, as required by the prior law, to 33% of their total retail sales. The RPS law, which became effective in December 2011, established three initial compliance periods: 2011 through 2013, 2014 through 2016, and 2017 through 2020. The RPS compliance requirement that must be met for each of these compliance periods will gradually increase. Thereafter, compliance with the 33% RPS requirement will be determined on an annual basis.

It is uncertain which decisions issued by the CPUC pursuant to the former 20% RPS law will remain in effect under the new program. The CPUC has indicated its intent to address all compliance provisions of the new law, including rules that focus on the banking of eligible renewable deliveries. The CPUC is also expected to determine whether to change the penalty provisions it established in decisions implementing the former RPS law, which had generally established a maximum penalty of $25 million per year on each retail seller that had an unexcused failure to meet its compliance obligation. Additionally, the California Energy Commission, which continues to have responsibility for certifying the eligibility of renewable resources and verifying LSE compliance with the RPS program, is expected to begin implementing regulations during 2012.

The Utility has made substantial financial commitments under third-party renewable energy contracts to meet RPS procurement quantity requirements. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.) The Utility currently expects that it will comply with its procurement requirement for the first compliance period (2011 through 2013). The costs incurred by the Utility under third-party contracts to meet RPS requirements are expected to be recovered with other procurement costs through rates. The costs of Utility-owned renewable generation projects will be recoverable through traditional cost-of-service ratemaking mechanisms provided that costs do not exceed the maximums authorized by the CPUC for the respective project.

Water Quality

The U.S. Environmental Protection Agency (“EPA”) is expected to issue final regulations in July 2012 to implement the requirements of the federal Clean Water Act which 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. The State Board established a policy on once-through cooling at power plants in 2010. The policy 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%. The Utility must comply with the policy by December 31, 2024. If the State Board required the installation of cooling towers at Diablo Canyon and the Utility determined that the installation was not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge. Assuming the State 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.

59

OFF-BALANCE SHEET ARRANGEMENTS

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

CONTINGENCIES

In addition to the contingencies described under “Natural Gas Matters” above, 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.)

RISK MANAGEMENT ACTIVITIES

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

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

On July 21, 2010, President Obama signed into law federal financial reform legislation, the Dodd-Frank Wall Street Reform and Consumer Protection Act. PG&E Corporation and the Utility are monitoring implementation of the Act, and evaluating draft and final regulations as they are issued to assess compliance requirements, as well as potential impacts on the Utility’s procurement activities and risk management programs.

Commodity 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.

60

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

The Utility’s value-at-risk calculated under the methodology described above was approximately $10 million at March 31, 2012. The Utility’s approximate high, low, and average values-at-risk during the 12 months ended March 31, 2012 were $11 million, $7 million, and $10 million, respectively. (See Note 7 of the Notes to the 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 March 31, 2012, if interest rates changed by 1% for all current PG&E Corporation and Utility variable rate and short-term debt and investments, the change would affect net income for the next 12 months by $13 million, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

Energy Procurement Credit Risk

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

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

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 March 31, 2012 and December 31, 2011:

(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%
March 31, 2012		$ 170		$ 14		$ 156		2		$ 115
December 31, 2011		151		13		138		2		106

⁽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.

61

CRITICAL ACCOUNTING POLICIES

The preparation of the 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 and regulatory matters, asset retirement obligations, and pension and other postretirement benefit plans 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. Actual results may differ substantially from these estimates. These policies and their key characteristics are discussed in detail in the 2011 Annual Report.

62

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4. CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of March 31, 2012, 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 March 31, 2012 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

63

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 contingencies, see Note 10 of the Notes to the Condensed Consolidated Financial Statements.

Diablo Canyon Power Plant

For more information regarding the status of the 2003 settlement agreement between the Central Coast Regional Water Quality Control Board and the Utility, see “Part I, Item 3. Legal Proceedings” in the 2011 Annual Report.

Hinkley Natural Gas Compressor Site

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Hinkley natural gas compressor site. The Utility is also required to take measures to abate the effects of the contamination on the environment. The Utility’s remediation and abatement efforts are subject to the regulatory authority of the Regional Board.

On March 14, 2012, the full Regional Board voted to approve the settlement between the Regional Board and the Utility regarding a claim for administrative penalties the Regional Board sought to impose on the Utility due to the Utility’s alleged violation of a 2008 order requiring the Utility to control the spread of the chromium groundwater plume beyond boundaries described in the order. Under the terms of the settlement, the Utility will pay a penalty of $3.6 million, half of which will fund the construction of a replacement water system for the Hinkley public school. For additional information, see “Part I, Item 3. Legal Proceedings” in the 2011 Annual Report.

For more information about the Utility’s remediation activities at the Hinkley natural gas compressor site, see the section entitled “Environmental Matters” in Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations above and in Note 10 of the Notes to the Condensed Consolidated Financial Statements.

Litigation Related to the San Bruno Accident

Various 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 and property damage, and other relief, including punitive damages. See the section entitled “Natural Gas Matters” Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations above and in Note 10 of the Notes to the Condensed Consolidated Financial Statements.

Pending CPUC Investigations and Enforcement Matters

The CPUC is conducting three investigations pertaining to the Utility’s natural gas operations, including an investigation of the San Bruno accident. If the CPUC determines that the Utility violated applicable law, rules or orders, in connection with these investigations, the CPUC can impose penalties of up to $20,000 per day, per violation. (For violations that are considered to have occurred on or after January 1, 2012, the statutory penalty has increased to a maximum of $50,000 per day, per violation.)

In December 2011, the CPUC delegated authority to its staff to enforce compliance with certain state and federal regulations related to the safety of natural gas facilities and utilities’ natural gas operating practices, including the authority to issue citations and impose penalties. The CPUC also established a requirement that California gas corporations provide notice to the CPUC of any self-identified or self-corrected violations of these regulations. Since the citation program was adopted, the Utility has filed numerous self-reports, including a report that it failed to conduct periodic leak surveys because the Utility had not included 16 gas distribution maps in its leak survey schedule. In response to this self-report, the CPSD issued a citation to the Utility that included a penalty of approximately $17 million. The CPSD has not yet taken action with respect to the Utility’s other self-reports, including a follow-up report stating that the Utility had not considered an additional 46 gas distribution maps in its leak survey schedule. The CPSD may issue additional citations and impose penalties on the Utility associated with these or future self-reports. Under the CPUC’s delegation of authority, the CPSD is required to impose the maximum statutory penalty.

An investigation of the San Bruno accident by state and federal authorities also may result in the imposition of civil or criminal penalties on the Utility.

See the section entitled “Natural Gas Matters” above in Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 10 of the Notes to the Condensed Consolidated Financial Statements.

64

ITEM 1A. RISK FACTORS

The risk factors appearing in the 2011 Annual Report under the headings set forth below are supplemented and updated as follows:

The Utility’s costs to remediate groundwater contamination near the Hinkley natural gas compressor site and to abate the effects of the contamination, have had, and may continue to have, a material effect on PG&E Corporation’s and the Utility’s financial conditions, results of operations, and cash flows.

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Hinkley natural gas compressor site. As discussed above in the section entitled “Environmental Matters,” in Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations, several orders have been issued to require the Utility to take measures to remediate the underground chromium plume and abate the effects of the contamination on the environment. The Utility’s remediation costs associated with the Hinkley natural gas compressor site are not recoverable through rates or insurance. As a result, costs incurred for remediation at the Hinkley natural gas compressor site, as well as changes in the environmental remediation liability for the Hinkley natural gas compressor site, affect PG&E Corporation’s and the Utility’s financial condition and results of operations.

In October 2011, the Regional Board issued an amended clean up and abatement order that the Utility has challenged. In April 2012, the Utility agreed to provide whole house water replacement systems for approximately 300 resident households located up to one mile from the chromium plume boundary or eligible residents can choose to have the Utility purchase their property. PG&E Corporation’s and the Utility’s financial results for the three months ended March 31, 2012 were negatively affected by the increase in the accrued liability associated with the Hinckley site primarily reflecting the Utility’s best estimate of future probable costs associated with providing water replacement systems or purchasing property from eligible residents. The Regional Board also is evaluating final remediation alternatives submitted by the Utility and has stated it anticipates releasing a draft EIR in the second half of 2012 and that it will consider certification of the final EIR, which will include the final approved remediation plan, by the end of 2012.

The amount of future remediation costs will depend on many factors, including when and whether the Regional Board certifies the final remediation plan, the extent of the groundwater chromium plume, the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the scope of requirements to provide a permanent water replacement system to affected residents, and the number of eligible residents who participate in the water replacement program. As more information becomes known regarding these factors, estimates and assumptions regarding the amount of liability incurred may be subject to further changes. Future changes in estimates may have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

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

During the quarter ended March 31, 2012, PG&E Corporation made equity contributions totaling $385 million to the Utility in order to maintain the 52% common equity component of its CPUC-authorized capital structure. Neither PG&E Corporation nor the Utility made any sales of unregistered equity securities during the quarter ended March 31, 2012.

Issuer Purchases of Equity Securities

PG&E Corporation common stock:

Period	Total Number of   Shares Purchased		Average Price   Per Share		Total Number  of Shares Purchased as Part of Publicly Announced Plans or Programs		Approximate Dollar Value  of Shares that May Yet be Purchased Under the Plans      or Programs
January 1 through January 31, 2012		5,353  (1)		$40.82		-		$ -
February 1 through February 28, 2012		-		-		-		-
March 1 through March 31, 2012		-		-		-		-
Total		5,353		$40.82		-		$ -

⁽¹⁾ Shares tendered to satisfy tax withholding obligations arising upon the vesting of PG&E Corporation restricted stock.

During the quarter ended March 31, 2012, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

65

During the quarter ended March 31, 2012, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the quarter ended March 31, 2012, 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 three months ended March 31, 2012 was 2.62. The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the three months ended March 31, 2012 was 2.58. 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 three months ended March 31, 2012 was 2.52. 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.

66

ITEM 6. EXHIBITS

3.1	Amended Bylaws of PG&E Corporation effective March 1, 2012
3.2	Amended Bylaws of Pacific Gas and Electric Company effective March 1, 2012
*10.1	Form of Restricted Stock Unit Agreement for 2012 grants under the PG&E Corporation 2006 Long-Term Incentive Plan
*10.2	Form of Performance Share Agreement for 2012 grants under the PG&E Corporation 2006 Long-Term Incentive Plan
*10.3	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant under the PG&E Corporation 2006 Long-Term Incentive Plan
*10.4	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant under the PG&E Corporation 2006 Long-Term Incentive Plan
*10.5	PG&E Corporation Officer Severance Policy, as amended effective as of March 1, 2012
*10.6	PG&E Corporation 2012 Officer Severance Policy, adopted February 15, 2012, effective as of March 1, 2012
*10.7	Postretirement Life Insurance Plan of the Pacific Gas and Electric Company, as amended and restated on February 14, 2012
12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation
31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
**32.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
**32.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

* Management contract or compensatory agreement.

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

67

SIGNATURES

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

PG&E CORPORATION

KENT M. HARVEY

Kent M. Harvey

Senior Vice President and Chief Financial Officer

(duly authorized officer and principal financial officer)        

PACIFIC GAS AND ELECTRIC COMPANY

DINYAR B. MISTRY

Dinyar B. Mistry

Vice President, Chief Financial Officer and Controller

(duly authorized officer and principal financial officer)

Dated: May 2, 2012

68

EXHIBIT INDEX

3.1	Amended Bylaws of PG&E Corporation effective March 1, 2012
3.2	Amended Bylaws of Pacific Gas and Electric Company effective March 1, 2012
*10.1	Form of Restricted Stock Unit Agreement for 2012 grants under the PG&E Corporation 2006 Long-Term Incentive Plan
*10.2	Form of Performance Share Agreement for 2012 grants under the PG&E Corporation 2006 Long-Term Incentive Plan
*10.3	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant under the PG&E Corporation 2006 Long-Term Incentive Plan
*10.4	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant under the PG&E Corporation 2006 Long-Term Incentive Plan
*10.5	PG&E Corporation Officer Severance Policy, as amended effective as of March 1, 2012
*10.6	PG&E Corporation 2012 Officer Severance Policy, adopted February 15, 2012, effective as of March 1, 2012
*10.7	Postretirement Life Insurance Plan of the Pacific Gas and Electric Company, as amended and restated on February 14, 2012
12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation
31.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
**32.1	Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
**32.2	Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

* Management contract or compensatory agreement.

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

69

EX-3.1

Exhibit 3.1

Bylaws

of

PG&E Corporation

amended as of March 1, 2012

Article I.

SHAREHOLDERS.

1.       Place of Meeting.  All meetings of the shareholders shall be held at the office of the Corporation in the City and County of San Francisco, State of California, or at such other place, within or without the State of California, as may be designated by the Board of Directors.

2.       Annual Meetings.  The annual meeting of shareholders shall be held each year on a date and at a time designated by the Board of Directors.

Written notice of the annual meeting shall be given not less than ten (or, if sent by third-class mail, thirty) nor more than sixty days prior to the date of the meeting to each shareholder entitled to vote thereat. The notice shall state the place, day, and hour of such meeting, and those matters which the Board, at the time of mailing, intends to present for action by the shareholders.

Notice of any meeting of the shareholders shall be given by mail or telegraphic or other written communication, postage prepaid, to each holder of record of the stock entitled to vote thereat, at his address, as it appears on the books of the Corporation.

At an annual meeting of shareholders, only such business shall be conducted as shall have been properly brought before the annual meeting. To be properly brought before an annual meeting, business must be (i) specified in the notice of the annual meeting (or any supplement thereto) given by or at the direction of the Board, or (ii) otherwise properly brought before the annual meeting by a shareholder. For business to be properly brought before an annual meeting by a shareholder, including the nomination of any person (other than a person nominated by or at the direction of the Board) for election to the Board, the shareholder must have given timely and proper written notice to the Corporate Secretary of the Corporation. To be timely, the shareholder’s written notice must be received at the principal executive office of the Corporation not less than forty-five days before the date corresponding to the mailing date of the notice and proxy materials for the prior year’s annual meeting of shareholders; provided, however, that if the annual meeting to which the shareholder’s written notice relates is to be held on a date that differs by more than thirty days from the date of the last annual meeting of shareholders, the shareholder’s written notice to be timely must be so received not later than the close of business on the tenth day

following the date on which public disclosure of the date of the annual meeting is made or given to shareholders. Any shareholder’s written notice that is delivered after the close of business (5:00 p.m. local time) will be considered received on the following business day. To be proper, the shareholder’s written notice must set forth as to each matter the shareholder proposes to bring before the annual meeting (a) a brief description of the business desired to be brought before the annual meeting, (b) the name and address of the shareholder as they appear on the Corporation’s books, (c) the class and number of shares of the Corporation that are beneficially owned by the shareholder, and (d) any material interest of the shareholder in such business. In addition, if the shareholder’s written notice relates to the nomination at the annual meeting of any person for election to the Board, such notice to be proper must also set forth (a) the name, age, business address, and residence address of each person to be so nominated, (b) the principal occupation or employment of each such person, (c) the number of shares of capital stock of the Corporation beneficially owned by each such person, and (d) such other information concerning each such person as would be required under the rules of the Securities and Exchange Commission in a proxy statement soliciting proxies for the election of such person as a Director, and must be accompanied by a consent, signed by each such person, to serve as a Director of the Corporation if elected. Notwithstanding anything in the Bylaws to the contrary, no business shall be conducted at an annual meeting except in accordance with the procedures set forth in this Section.

3.       Special Meetings.  Special meetings of the shareholders shall be called by the Corporate Secretary or an Assistant Corporate Secretary at any time on order of the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the Chief Executive Officer, or the President. Special meetings of the shareholders shall also be called by the Corporate Secretary or an Assistant Corporate Secretary upon the written request of holders of shares entitled to cast not less than ten percent of the votes at the meeting. Such request shall state the purposes of the meeting, and shall be delivered to the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the Chief Executive Officer, the President, or the Corporate Secretary.

A special meeting so requested shall be held on the date requested, but not less than thirty-five nor more than sixty days after the date of the original request. Written notice of each special meeting of shareholders, stating the place, day, and hour of such meeting and the business proposed to be transacted thereat, shall be given in the manner stipulated in Article I, Section 2, Paragraph 3 of these Bylaws within twenty days after receipt of the written request.

4.       Voting at Meetings.  At any meeting of the shareholders, each holder of record of stock shall be entitled to vote in person or by proxy. The authority of proxies must be evidenced by a written document signed by the shareholder and must be delivered to the Corporate Secretary of the Corporation prior to the commencement of the meeting.

2

5.       Shareholder Action by Written Consent.  Subject to Section 603 of the California Corporations Code, any action which, under any provision of the California Corporations Code, may be taken at any annual or special meeting of shareholders may be taken without a meeting and without prior notice if a consent in writing, setting forth the action so taken, shall be signed by the holders of outstanding shares having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted.

Any party seeking to solicit written consent from shareholders to take corporate action must deliver a notice to the Corporate Secretary of the Corporation which requests the Board of Directors to set a record date for determining shareholders entitled to give such consent. Such written request must set forth as to each matter the party proposes for shareholder action by written consents (a) a brief description of the matter and (b) the class and number of shares of the Corporation that are beneficially owned by the requesting party. Within ten days of receiving the request in the proper form, the Board shall set a record date for the taking of such action by written consent in accordance with California Corporations Code Section 701 and Article IV, Section 1 of these Bylaws. If the Board fails to set a record date within such ten-day period, the record date for determining shareholders entitled to give the written consent for the matters specified in the notice shall be the day on which the first written consent is given in accordance with California Corporations Code Section 701.

Each written consent delivered to the Corporation must set forth (a) the action sought to be taken, (b) the name and address of the shareholder as they appear on the Corporation’s books, (c) the class and number of shares of the Corporation that are beneficially owned by the shareholder, (d) the name and address of the proxyholder authorized by the shareholder to give such written consent, if applicable, and (d) any material interest of the shareholder or proxyholder in the action sought to be taken.

Consents to corporate action shall be valid for a maximum of sixty days after the date of the earliest dated consent delivered to the Corporation. Consents may be revoked by written notice (i) to the Corporation, (ii) to the shareholder or shareholders soliciting consents or soliciting revocations in opposition to action by consent proposed by the Corporation (the “Soliciting Shareholders”), or (iii) to a proxy solicitor or other agent designated by the Corporation or the Soliciting Shareholders.

Within three business days after receipt of the earliest dated consent solicited by the Soliciting Shareholders and delivered to the Corporation in the manner provided in California Corporations Code Section 603 or the determination by the Board of Directors of the Corporation that the Corporation should seek corporate action by written consent, as the case may be, the Corporate Secretary shall engage nationally recognized independent inspectors of elections for the purpose of performing a ministerial review of the validity of the consents and revocations. The cost of retaining inspectors of election shall be borne by the Corporation.

3

Consents and revocations shall be delivered to the inspectors upon receipt by the Corporation, the Soliciting Shareholders or their proxy solicitors, or other designated agents. As soon as consents and revocations are received, the inspectors shall review the consents and revocations and shall maintain a count of the number of valid and unrevoked consents. The inspectors shall keep such count confidential and shall not reveal the count to the Corporation, the Soliciting Shareholder or their representatives, or any other entity. As soon as practicable after the earlier of (i) sixty days after the date of the earliest dated consent delivered to the Corporation in the manner provided in California Corporations Code Section 603, or (ii) a written request therefor by the Corporation or the Soliciting Shareholders (whichever is soliciting consents), notice of which request shall be given to the party opposing the solicitation of consents, if any, which request shall state that the Corporation or Soliciting Shareholders, as the case may be, have a good faith belief that the requisite number of valid and unrevoked consents to authorize or take the action specified in the consents has been received in accordance with these Bylaws, the inspectors shall issue a preliminary report to the Corporation and the Soliciting Shareholders stating: (a) the number of valid consents, (b) the number of valid revocations, (c) the number of valid and unrevoked consents, (d) the number of invalid consents, (e) the number of invalid revocations, and (f) whether, based on their preliminary count, the requisite number of valid and unrevoked consents has been obtained to authorize or take the action specified in the consents.

Unless the Corporation and the Soliciting Shareholders shall agree to a shorter or longer period, the Corporation and the Soliciting Shareholders shall have forty-eight hours to review the consents and revocations and to advise the inspectors and the opposing party in writing as to whether they intend to challenge the preliminary report of the inspectors. If no written notice of an intention to challenge the preliminary report is received within forty-eight hours after the inspectors’ issuance of the preliminary report, the inspectors shall issue to the Corporation and the Soliciting Shareholders their final report containing the information from the inspectors’ determination with respect to whether the requisite number of valid and unrevoked consents was obtained to authorize and take the action specified in the consents. If the Corporation or the Soliciting Shareholders issue written notice of an intention to challenge the inspectors’ preliminary report within forty-eight hours after the issuance of that report, a challenge session shall be scheduled by the inspectors as promptly as practicable. A transcript of the challenge session shall be recorded by a certified court reporter. Following completion of the challenge session, the inspectors shall as promptly as practicable issue their final report to the Soliciting Shareholders and the Corporation, which report shall contain the information included in the preliminary report, plus all changes in the vote totals as a result of the challenge and a certification of whether the requisite number of valid and unrevoked consents was obtained to authorize or take the action specified in the consents. A copy of the final report of the inspectors shall be included in the book in which the proceedings of meetings of shareholders are recorded.

Unless the consent of all shareholders entitled to vote have been solicited in writing, the Corporation shall give prompt notice to the shareholders in accordance with California Corporations Code Section 603 of the results of any consent solicitation or

4

the taking of the corporate action without a meeting and by less than unanimous written consent.

Article II.

DIRECTORS.

1.       Number.  As stated in paragraph I of Article Third of this Corporation’s Articles of Incorporation, the Board of Directors of this Corporation shall consist of such number of directors, not less than seven (7) nor more than thirteen (13). The exact number of directors shall be twelve (12) until changed, within the limits specified above, by an amendment to this Bylaw duly adopted by the Board of Directors or the shareholders.

2.       Powers.  The Board of Directors shall exercise all the powers of the Corporation except those which are by law, or by the Articles of Incorporation of this Corporation, or by the Bylaws conferred upon or reserved to the shareholders.

3.       Committees.  The Board of Directors may, by resolution adopted by a majority of the authorized number of directors, designate and appoint one or more committees as the Board deems appropriate, each consisting of two or more directors, to serve at the pleasure of the Board; provided, however, that, as required by this Corporation’s Articles of Incorporation, the members of the Executive Committee (should the Board of Directors designate an Executive Committee) must be appointed by the affirmative vote of two-thirds of the authorized number of directors. Any such committee, including the Executive Committee, shall have the authority to act in the manner and to the extent provided in the resolution of the Board of Directors designating such committee and may have all the authority of the Board of Directors, except with respect to the matters set forth in California Corporations Code Section 311.

4.       Time and Place of Directors’ Meetings.  Regular meetings of the Board of Directors shall be held on such days and at such times and at such locations as shall be fixed by resolution of the Board, or designated by the Chairman of the Board or, in his absence, the Vice Chairman of the Board, the Chief Executive Officer, or the President of the Corporation and contained in the notice of any such meeting. Notice of meetings shall be delivered personally or sent by mail or telegram at least seven days in advance.

5.       Special Meetings.  The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the Chief Executive Officer, the President, or any five directors may call a special meeting of the Board of Directors at any time. Notice of the time and place of special meetings shall be given to each Director by the Corporate Secretary. Such notice shall be delivered personally or by telephone (or other system or technology designed to record and communicate messages, including facsimile, electronic mail, or other such means) to each Director at

5

least four hours in advance of such meeting, or sent by first-class mail or telegram, postage prepaid, at least two days in advance of such meeting.

6.       Quorum.  A quorum for the transaction of business at any meeting of the Board of Directors or any committee thereof shall consist of one-third of the authorized number of directors or committee members, or two, whichever is larger.

7.       Action by Consent.  Any action required or permitted to be taken by the Board of Directors may be taken without a meeting if all Directors individually or collectively consent in writing to such action. Such written consent or consents shall be filed with the minutes of the proceedings of the Board of Directors.

8.       Meetings by Conference Telephone.  Any meeting, regular or special, of the Board of Directors or of any committee of the Board of Directors, may be held by conference telephone or similar communication equipment, provided that all Directors participating in the meeting can hear one another.

9.       Majority Voting.  In any uncontested election, nominees receiving the affirmative vote of a majority of the shares represented and voting at a duly held meeting at which a quorum is present (which shares voting affirmatively also constitute at least a majority of the required quorum) shall be elected. In any election that is not an uncontested election, the nominees receiving the highest number of affirmative votes of the shares entitled to be voted for them, up to the number of directors to be elected by those shares, shall be elected; votes against a director and votes withheld shall have no legal effect.

For purposes of these Bylaws, “uncontested election” means an election of directors of the Corporation in which, at the expiration of the times fixed under Article I, Section 2 of these Bylaws requiring advance notification of director nominees, or for special meetings, at the time notice is given of the meeting at which the election is to occur, the number of nominees for election does not exceed the number of directors to be elected by the shareholders at that election.

If an incumbent director fails, in an uncontested election, to receive the vote required to be elected in accordance with this Article II, Section 9, then, unless the incumbent director has earlier resigned, the term of such incumbent director shall end on the date that is the earlier of (a) ninety (90) days after the date on which the voting results are determined pursuant to Section 707 of the California Corporations Code, or (b) the date on which the Board of Directors selects a person to fill the office held by that director in accordance with the procedures set forth in these Bylaws and Section 305 of the California Corporations Code.

6

Article III.

OFFICERS.

1.       Officers.  The officers of the Corporation shall be elected by the Board of Directors and include a President, a Corporate Secretary, a Treasurer, or other such officers as required by law. The Board of Directors also may elect one or more Vice Presidents, Assistant Secretaries, Assistant Treasurers, and other such officers as may be appropriate, including the offices described below. Any number of offices may be held by the same person.

2.       Chairman of the Board.  The Chairman of the Board shall be a member of the Board of Directors and preside at all meetings of the shareholders, of the Directors, and of the Executive Committee in the absence of the Chairman of that Committee. The Chairman of the Board shall have such duties and responsibilities as may be prescribed by the Board of Directors or the Bylaws. The Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character, and, in the absence or disability of the Chief Executive Officer, shall exercise the Chief Executive Officer’s duties and responsibilities.

3.       Vice Chairman of the Board.  The Vice Chairman of the Board shall be a member of the Board of Directors and have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. In the absence of the Chairman of the Board, the Vice Chairman of the Board shall preside at all meetings of the Board of Directors and of the shareholders; and, in the absence of the Chairman of the Executive Committee and the Chairman of the Board, the Vice Chairman of the Board shall preside at all meetings of the Executive Committee. The Vice Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character.

4.       Chairman of the Executive Committee.  The Chairman of the Executive Committee shall be a member of the Board of Directors and preside at all meetings of the Executive Committee. The Chairman of the Executive Committee shall aid and assist the other officers in the performance of their duties and shall have such other duties as may be prescribed by the Board of Directors or the Bylaws.

5.       Chief Executive Officer.  The Chief Executive Officer shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. If there be no Chairman of the Board, the Chief Executive Officer shall also exercise the duties and responsibilities of that office. The Chief Executive Officer shall have authority to sign on behalf of the Corporation agreements and instruments of every character. In the absence or disability of the President, the Chief Executive Officer shall exercise the President’s duties and responsibilities.

7

6.       President.  The President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, the Chief Executive Officer, or the Bylaws. If there be no Chief Executive Officer, the President shall also exercise the duties and responsibilities of that office. The President shall have authority to sign on behalf of the Corporation agreements and instruments of every character.

7.       Chief Financial Officer.  The Chief Financial Officer shall be responsible for the overall management of the financial affairs of the Corporation. The Chief Financial Officer shall render a statement of the Corporation’s financial condition and an account of all transactions whenever requested by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, or the President.

The Chief Financial Officer shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or the Bylaws.

8.       General Counsel.  The General Counsel shall be responsible for handling on behalf of the Corporation all proceedings and matters of a legal nature. The General Counsel shall render advice and legal counsel to the Board of Directors, officers, and employees of the Corporation, as necessary to the proper conduct of the business. The General Counsel shall keep the management of the Corporation informed of all significant developments of a legal nature affecting the interests of the Corporation.

The General Counsel shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or the Bylaws.

9.       Vice Presidents.  Each Vice President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or the Bylaws. Each Vice President’s authority to sign agreements and instruments on behalf of the Corporation shall be as prescribed by the Board of Directors. The Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, or the President may confer a special title upon any Vice President.

10.     Corporate Secretary.  The Corporate Secretary shall attend all meetings of the Board of Directors and the Executive Committee, and all meetings of the shareholders, and the Corporate Secretary shall record the minutes of all proceedings in books to be kept for that purpose. The Corporate Secretary shall be responsible for maintaining a proper share register and stock transfer books for all classes of shares issued by the Corporation. The Corporate Secretary shall give, or cause to be given, all notices required either by law or the Bylaws. The Corporate Secretary shall keep the seal of the Corporation in safe custody, and shall affix the seal of the Corporation to any instrument requiring it and shall attest the same by the Corporate Secretary’s signature.

8

The Corporate Secretary shall have such other duties as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or the Bylaws.

The Assistant Corporate Secretaries shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or the Corporate Secretary. In the absence or disability of the Corporate Secretary, the Corporate Secretary’s duties shall be performed by an Assistant Corporate Secretary.

11.     Treasurer.  The Treasurer shall have custody of all moneys and funds of the Corporation, and shall cause to be kept full and accurate records of receipts and disbursements of the Corporation. The Treasurer shall deposit all moneys and other valuables of the Corporation in the name and to the credit of the Corporation in such depositaries as may be designated by the Board of Directors or any employee of the Corporation designated by the Board of Directors. The Treasurer shall disburse such funds of the Corporation as have been duly approved for disbursement.

The Treasurer shall perform such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, the Chief Financial Officer, or the Bylaws.

The Assistant Treasurers shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, the Chief Financial Officer, or the Treasurer. In the absence or disability of the Treasurer, the Treasurer’s duties shall be performed by an Assistant Treasurer.

12.     Controller.  The Controller shall be responsible for maintaining the accounting records of the Corporation and for preparing necessary financial reports and statements, and the Controller shall properly account for all moneys and obligations due the Corporation and all properties, assets, and liabilities of the Corporation. The Controller shall render to the officers such periodic reports covering the result of operations of the Corporation as may be required by them or any one of them.

The Controller shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, the Chief Financial Officer, or the Bylaws. The Controller shall be the principal accounting officer of the Corporation, unless another individual shall be so designated by the Board of Directors.

9

Article IV.

MISCELLANEOUS.

1.       Record Date.  The Board of Directors may fix a time in the future as a record date for the determination of the shareholders entitled to notice of and to vote at any meeting of shareholders, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise rights in respect to any change, conversion, or exchange of shares. The record date so fixed shall be not more than sixty nor less than ten days prior to the date of such meeting nor more than sixty days prior to any other action for the purposes for which it is so fixed. When a record date is so fixed, only shareholders of record on that date are entitled to notice of and to vote at the meeting, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise the rights, as the case may be.

2.       Certificates; Direct Registration System.  Shares of the Corporation’s capital stock may be certificated or uncertificated, as provided under California law. Any certificates that are issued shall be signed in the name of the Corporation by the Chairman of the Board, the Vice Chairman of the Board, the President, or a Vice President and by the Chief Financial Officer, an Assistant Treasurer, the Corporate Secretary, or an Assistant Secretary, certifying the number of shares and the class or series of shares owned by the shareholder. Any or all of the signatures on the certificate may be a facsimile. In case any officer, Transfer Agent, or Registrar who has signed or whose facsimile signature has been placed upon a certificate shall have ceased to be such officer, Transfer Agent, or Registrar before such certificate is issued, it may be issued by the Corporation with the same effect as if such person were an officer, Transfer Agent, or Registrar at the date of issue. Shares of the Corporation’s capital stock may also be evidenced by registration in the holder’s name in uncertificated, book-entry form on the books of the Corporation in accordance with a direct registration system approved by the Securities and Exchange Commission and by the New York Stock Exchange or any securities exchange on which the stock of the Corporation may from time to time be traded.

Transfers of shares of stock of the Corporation shall be made by the Transfer Agent and Registrar on the books of the Corporation after receipt of a request with proper evidence of succession, assignment, or authority to transfer by the record holder of such stock, or by an attorney lawfully constituted in writing, and in the case of stock represented by a certificate, upon surrender of the certificate. Subject to the foregoing, the Board of Directors shall have power and authority to make such rules and regulations as it shall deem necessary or appropriate concerning the issue, transfer, and registration of shares of stock of the Corporation, and to appoint and remove Transfer Agents and Registrars of transfers.

10

3.       Lost Certificates.  Any person claiming a certificate of stock to be lost, stolen, mislaid, or destroyed shall make an affidavit or affirmation of that fact and verify the same in such manner as the Board of Directors may require, and shall, if the Board of Directors so requires, give the Corporation, its Transfer Agents, Registrars, and/or other agents a bond of indemnity in form approved by counsel, and in amount and with such sureties as may be satisfactory to the Corporate Secretary of the Corporation, before a new certificate (or uncertificated shares in lieu of a new certificate) may be issued of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, mislaid, or destroyed.

Article V.

AMENDMENTS.

1.       Amendment by Shareholders.  Except as otherwise provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by the affirmative vote of a majority of the outstanding shares entitled to vote at any regular or special meeting of the shareholders.

2.       Amendment by Directors.  To the extent provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by resolution adopted by a majority of the members of the Board of Directors; provided, however, that amendments to Article II, Section 9 of these Bylaws, and any other Bylaw provision that implements a majority voting standard for director elections (excepting any amendments intended to conform those Bylaw provisions to changes in applicable laws) shall be amended by the shareholders of the Corporation as provided in Section 1 of this Article V.

11

EX-3.2

Exhibit 3.2

Bylaws

of

Pacific Gas and Electric Company

amended as of March 1, 2012

Article I.

SHAREHOLDERS.

1.    Place of Meeting.  All meetings of the shareholders shall be held at the office of the Corporation in the City and County of San Francisco, State of California, or at such other place, within or without the State of California, as may be designated by the Board of Directors.

2.    Annual Meetings.  The annual meeting of shareholders shall be held each year on a date and at a time designated by the Board of Directors.

Written notice of the annual meeting shall be given not less than ten (or, if sent by third-class mail, thirty) nor more than sixty days prior to the date of the meeting to each shareholder entitled to vote thereat. The notice shall state the place, day, and hour of such meeting, and those matters which the Board, at the time of mailing, intends to present for action by the shareholders.

Notice of any meeting of the shareholders shall be given by mail or telegraphic or other written communication, postage prepaid, to each holder of record of the stock entitled to vote thereat, at his address, as it appears on the books of the Corporation.

At an annual meeting of shareholders, only such business shall be conducted as shall have been properly brought before the annual meeting. To be properly brought before an annual meeting, business must be (i) specified in the notice of the annual meeting (or any supplement thereto) given by or at the direction of the Board, or (ii) otherwise properly brought before the annual meeting by a shareholder. For business to be properly brought before an annual meeting by a shareholder, including the nomination of any person (other than a person nominated by or at the direction of the Board) for election to the Board, the shareholder must have given timely and proper written notice to the Corporate Secretary of the Corporation. To be timely, the shareholder’s written notice must be received at the principal executive office of the Corporation not less than forty-five days before the date corresponding to the mailing date of the notice and proxy materials for the prior year’s annual meeting of shareholders; provided, however, that if the annual meeting to which the shareholder’s written notice relates is to be held on a date that differs by more than thirty days from the date of the last annual meeting of shareholders, the shareholder’s written notice to be timely must be so received not later than the close of business on the tenth day

following the date on which public disclosure of the date of the annual meeting is made or given to shareholders. Any shareholder’s written notice that is delivered after the close of business (5:00 p.m. local time) will be considered received on the following business day. To be proper, the shareholder’s written notice must set forth as to each matter the shareholder proposes to bring before the annual meeting (a) a brief description of the business desired to be brought before the annual meeting, (b) the name and address of the shareholder as they appear on the Corporation’s books, (c) the class and number of shares of the Corporation that are beneficially owned by the shareholder, and (d) any material interest of the shareholder in such business. In addition, if the shareholder’s written notice relates to the nomination at the annual meeting of any person for election to the Board, such notice to be proper must also set forth (a) the name, age, business address, and residence address of each person to be so nominated, (b) the principal occupation or employment of each such person, (c) the number of shares of capital stock of the Corporation beneficially owned by each such person, and (d) such other information concerning each such person as would be required under the rules of the Securities and Exchange Commission in a proxy statement soliciting proxies for the election of such person as a Director, and must be accompanied by a consent, signed by each such person, to serve as a Director of the Corporation if elected. Notwithstanding anything in the Bylaws to the contrary, no business shall be conducted at an annual meeting except in accordance with the procedures set forth in this Section.

3.    Special Meetings.  Special meetings of the shareholders shall be called by the Corporate Secretary or an Assistant Corporate Secretary at any time on order of the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the Chief Executive Officer, or the President. Special meetings of the shareholders shall also be called by the Corporate Secretary or an Assistant Corporate Secretary upon the written request of holders of shares entitled to cast not less than ten percent of the votes at the meeting. Such request shall state the purposes of the meeting, and shall be delivered to the Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the Chief Executive Officer, the President or the Corporate Secretary.

A special meeting so requested shall be held on the date requested, but not less than thirty-five nor more than sixty days after the date of the original request. Written notice of each special meeting of shareholders, stating the place, day, and hour of such meeting and the business proposed to be transacted thereat, shall be given in the manner stipulated in Article I, Section 2, Paragraph 3 of these Bylaws within twenty days after receipt of the written request.

4.    Voting at Meetings.  At any meeting of the shareholders, each holder of record of stock shall be entitled to vote in person or by proxy. The authority of proxies must be evidenced by a written document signed by the shareholder and must be delivered to the Corporate Secretary of the Corporation prior to the commencement of the meeting.

2

5.    No Cumulative Voting.  No shareholder of the Corporation shall be entitled to cumulate his or her voting power.

Article II.

DIRECTORS.

1.    Number.  The Board of Directors of this Corporation shall consist of such number of directors, not less than nine (9) nor more than seventeen (17). The exact number of directors shall be twelve (12) until changed, within the limits specified above, by an amendment to this Bylaw duly adopted by the Board of Directors or the shareholders.

2.    Powers.  The Board of Directors shall exercise all the powers of the Corporation except those which are by law, or by the Articles of Incorporation of this Corporation, or by the Bylaws conferred upon or reserved to the shareholders.

3.  Committees.  The Board of Directors may, by resolution adopted by a majority of the authorized number of directors, designate and appoint one or more committees as the Board deems appropriate, each consisting of two or more directors, to serve at the pleasure of the Board; provided, however, that, as required by this Corporation’s Articles of Incorporation, the members of the Executive Committee (should the Board of Directors designate an Executive Committee) must be appointed by the affirmative vote of two-thirds of the authorized number of directors. Any such committee, including the Executive Committee, shall have the authority to act in the manner and to the extent provided in the resolution of the Board of Directors designating such committee and may have all the authority of the Board of Directors, except with respect to the matters set forth in California Corporations Code Section 311.

4.    Time and Place of Directors’ Meetings.  Regular meetings of the Board of Directors shall be held on such days and at such times and at such locations as shall be fixed by resolution of the Board, or designated by the Chairman of the Board or, in his absence, the Vice Chairman of the Board, the Chief Executive Officer, or the President of the Corporation and contained in the notice of any such meeting. Notice of meetings shall be delivered personally or sent by mail or telegram at least seven days in advance.

5.    Special Meetings.  The Chairman of the Board, the Vice Chairman of the Board, the Chairman of the Executive Committee, the Chief Executive Officer, the President, or any five directors may call a special meeting of the Board of Directors at any time. Notice of the time and place of special meetings shall be given to each Director by the Corporate Secretary. Such notice shall be delivered personally or by telephone (or other system or technology designed to record and communicate messages, including facsimile, electronic mail, or other such means) to each Director at least four hours in advance of such meeting, or sent by first-class mail or telegram, postage prepaid, at least two days in advance of such meeting.

3

6.  Quorum.  A quorum for the transaction of business at any meeting of the Board of Directors or any committee thereof shall consist of one-third of the authorized number of directors or committee members, or two, whichever is larger.

7.    Action by Consent.  Any action required or permitted to be taken by the Board of Directors may be taken without a meeting if all Directors individually or collectively consent in writing to such action. Such written consent or consents shall be filed with the minutes of the proceedings of the Board of Directors.

8.    Meetings by Conference Telephone.  Any meeting, regular or special, of the Board of Directors or of any committee of the Board of Directors, may be held by conference telephone or similar communication equipment, provided that all Directors participating in the meeting can hear one another.

9.    Majority Voting.  In any uncontested election, nominees receiving the affirmative vote of a majority of the shares represented and voting at a duly held meeting at which a quorum is present (which shares voting affirmatively also constitute at least a majority of the required quorum) shall be elected. In any election that is not an uncontested election, the nominees receiving the highest number of affirmative votes of the shares entitled to be voted for them, up to the number of directors to be elected by those shares, shall be elected; votes against a director and votes withheld shall have no legal effect.

For purposes of these Bylaws, “uncontested election” means an election of directors of the Corporation in which, at the expiration of the times fixed under Article I, Section 2 of these Bylaws requiring advance notification of director nominees, or for special meetings, at the time notice is given of the meeting at which the election is to occur, the number of nominees for election does not exceed the number of directors to be elected by the shareholders at that election.

If an incumbent director fails, in an uncontested election, to receive the vote required to be elected in accordance with this Article II, Section 9, then, unless the incumbent director has earlier resigned, the term of such incumbent director shall end on the date that is the earlier of (a) ninety (90) days after the date on which the voting results are determined pursuant to Section 707 of the California Corporations Code, or (b) the date on which the Board of Directors selects a person to fill the office held by that director in accordance with the procedures set forth in these Bylaws and Section 305 of the California Corporations Code.

10.  Certain Powers Reserved to the Shareholders.  So long as PG&E Corporation shall hold the majority of the outstanding shares of the Corporation, PG&E Corporation may require the written consent of the PG&E Corporation Chairman of the Board or the PG&E Corporation Chief Executive Officer to enter into and execute any transaction or type of transaction identified by the Board of Directors of PG&E Corporation as a “Designated Transaction.” For purposes of this Section 10, a

4

Designated Transaction shall be any transaction or type of transaction identified in a duly adopted resolution of the Board of Directors of PG&E Corporation as requiring the written consent of the PG&E Corporation Chairman of the Board or the PG&E Corporation Chief Executive Officer pursuant to this Section 10. Notwithstanding the foregoing, nothing in this Section 10 shall limit the power of the Corporation to enter into or execute any transaction or type of transaction prior to the receipt by the Corporate Secretary of the Corporation of the resolution designating such transaction or type of transaction as a Designated Transaction pursuant to this Section 10.

Article III.

OFFICERS.

1.                Officers.  The officers of the Corporation shall be elected by the Board of Directors and include a President, a Corporate Secretary, a Treasurer or other such officers as required by law. The Board of Directors also may elect one or more Vice Presidents, Assistant Secretaries, Assistant Treasurers, and such other officers as may be appropriate, including the offices described below. Any number of offices may be held by the same person.

2.    Chairman of the Board.  The Chairman of the Board shall be a member of the Board of Directors and preside at all meetings of the shareholders, of the Directors, and of the Executive Committee in the absence of the Chairman of that Committee. The Chairman of the Board shall have such duties and responsibilities as may be prescribed by the Board of Directors or the Bylaws. The Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character, and in the absence or disability of the Chief Executive Officer, shall exercise the Chief Executive Officer’s duties and responsibilities.

3.    Vice Chairman of the Board.  The Vice Chairman of the Board shall be a member of the Board of Directors and have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. In the absence of the Chairman of the Board, the Vice Chairman of the Board shall preside at all meetings of the Board of Directors and of the shareholders; and, in the absence of the Chairman of the Executive Committee and the Chairman of the Board, The Vice Chairman of the Board shall preside at all meetings of the Executive Committee. The Vice Chairman of the Board shall have authority to sign on behalf of the Corporation agreements and instruments of every character.

4.    Chairman of the Executive Committee.  The Chairman of the Executive Committee shall be a member of the Board of Directors and preside at all meetings of the Executive Committee. The Chairman of the Executive Committee shall aid and assist the other officers in the performance of their duties and shall have such other duties as may be prescribed by the Board of Directors or the Bylaws.

5

5.    Chief Executive Officer.  The Chief Executive Officer shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, or the Bylaws. If there be no Chairman of the Board, the Chief Executive Officer shall also exercise the duties and responsibilities of that office. The Chief Executive Officer shall have authority to sign on behalf of the Corporation agreements and instruments of every character. In the absence or disability of the President, the Chief Executive Officer shall exercise the President’s duties and responsibilities.

6.    President.  The President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, the Chief Executive Officer, or the Bylaws. If there be no Chief Executive Officer, the President shall also exercise the duties and responsibilities of that office. The President shall have authority to sign on behalf of the Corporation agreements and instruments of every character.

7.    Vice Presidents.  Each Vice President shall have such duties and responsibilities as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or the Bylaws. Each Vice President’s authority to sign agreements and instruments on behalf of the Corporation shall be as prescribed by the Board of Directors. The Board of Directors of this company, the Chairman of the Board of this company, the Vice Chairman of the Board of this company, or the Chief Executive Officer of PG&E Corporation may confer a special title upon any Vice President.

8.    Corporate Secretary.  The Corporate Secretary shall attend all meetings of the Board of Directors and the Executive Committee, and all meetings of the shareholders, and the Corporate Secretary shall record the minutes of all proceedings in books to be kept for that purpose. The Corporate Secretary shall be responsible for maintaining a proper share register and stock transfer books for all classes of shares issued by the Corporation. The Corporate Secretary shall give, or cause to be given, all notices required either by law or the Bylaws. The Corporate Secretary shall keep the seal of the Corporation in safe custody, and shall affix the seal of the Corporation to any instrument requiring it and shall attest the same by the Corporate Secretary’s signature.

The Corporate Secretary shall have such other duties as may be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or the Bylaws.

The Assistant Corporate Secretaries shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or the Corporate Secretary. In the absence or disability of the Corporate Secretary, the Corporate Secretary’s duties shall be performed by an Assistant Corporate Secretary.

9.    Treasurer.  The Treasurer shall have custody of all moneys and funds of the Corporation, and shall cause to be kept full and accurate records of receipts and disbursements of the Corporation. The Treasurer shall deposit all moneys and other

6

valuables of the Corporation in the name and to the credit of the Corporation in such depositaries as may be designated by the Board of Directors or any employee of the Corporation designated by the Board of Directors. The Treasurer shall disburse such funds of the Corporation as have been duly approved for disbursement.

The Treasurer shall perform such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or the Bylaws.

The Assistant Treasurer shall perform such duties as may be assigned from time to time by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or the Treasurer. In the absence or disability of the Treasurer, the Treasurer’s duties shall be performed by an Assistant Treasurer.

10.  General Counsel.  The General Counsel shall be responsible for handling on behalf of the Corporation all proceedings and matters of a legal nature. The General Counsel shall render advice and legal counsel to the Board of Directors, officers, and employees of the Corporation, as necessary to the proper conduct of the business. The General Counsel shall keep the management of the Corporation informed of all significant developments of a legal nature affecting the interests of the Corporation.

The General Counsel shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or the Bylaws.

11.  Controller.  The Controller shall be responsible for maintaining the accounting records of the Corporation and for preparing necessary financial reports and statements, and the Controller shall properly account for all moneys and obligations due the Corporation and all properties, assets, and liabilities of the Corporation. The Controller shall render to the officers such periodic reports covering the result of operations of the Corporation as may be required by them or any one of them.

The Controller shall have such other duties as may from time to time be prescribed by the Board of Directors, the Chairman of the Board, the Vice Chairman of the Board, the Chief Executive Officer, the President, or the Bylaws. The Controller shall be the principal accounting officer of the Corporation, unless another individual shall be so designated by the Board of Directors.

Article IV.

MISCELLANEOUS.

1.    Record Date.  The Board of Directors may fix a time in the future as a record date for the determination of the shareholders entitled to notice of and to vote at any

7

meeting of shareholders, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise rights in respect to any change, conversion, or exchange of shares. The record date so fixed shall be not more than sixty nor less than ten days prior to the date of such meeting nor more than sixty days prior to any other action for the purposes for which it is so fixed. When a record date is so fixed, only shareholders of record on that date are entitled to notice of and to vote at the meeting, or entitled to receive any dividend or distribution, or allotment of rights, or to exercise the rights, as the case may be.

2.        Certificates; Direct Registration System.  Shares of the Corporation’s stock may be certificated or uncertificated, as provided under California law. Any certificates that are issued shall be signed in the name of the Corporation by the Chairman of the Board, the Vice Chairman of the Board, the President, or a Vice President and by the Chief Financial Officer, an Assistant Treasurer, the Corporate Secretary, or an Assistant Secretary, certifying the number of shares and the class or series of shares owned by the shareholder. Any or all of the signatures on the certificate may be a facsimile. In case any officer, Transfer Agent, or Registrar who has signed or whose facsimile signature has been placed upon a certificate shall have ceased to be such officer, Transfer Agent, or Registrar before such certificate is issued, it may be issued by the Corporation with the same effect as if such person were an officer, Transfer Agent, or Registrar at the date of issue. Shares of the Corporation’s capital stock may also be evidenced by registration in the holder’s name in uncertificated, book-entry form on the books of the Corporation in accordance with a direct registration system approved by the Securities and Exchange Commission and by the American Stock Exchange or any securities exchange on which the stock of the Corporation may from time to time be traded.

Transfers of shares of stock of the Corporation shall be made by the Transfer Agent and Registrar on the books of the Corporation only after receipt of a request with proper evidence of succession, assignment, or authority to transfer by the record holder of such stock, or by an attorney lawfully constituted in writing, and in the case of stock represented by a certificate, upon surrender of the certificate. Subject to the foregoing, the Board of Directors shall have power and authority to make such rules and regulations as it shall deem necessary or appropriate concerning the issue, transfer, and registration of certificates for shares of stock of the Corporation, and to appoint and remove Transfer Agents and Registrars of transfers.

3.    Lost Certificates.  Any person claiming a certificate of stock to be lost, stolen, mislaid, or destroyed shall make an affidavit or affirmation of that fact and verify the same in such manner as the Board of Directors may require, and shall, if the Board of Directors so requires, give the Corporation, its Transfer Agents, Registrars, and/or other agents a bond of indemnity in form approved by counsel, and in amount and with such sureties as may be satisfactory to the Corporate Secretary of the Corporation, before a new certificate (or uncertificated shares in lieu of a new certificate) may be issued of the same tenor and for the same number of shares as the one alleged to have been lost, stolen, mislaid, or destroyed.

8

Article V.

AMENDMENTS.

1.    Amendment by Shareholders.  Except as otherwise provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by the affirmative vote of a majority of the outstanding shares entitled to vote at any regular or special meeting of the shareholders.

2.    Amendment by Directors.  To the extent provided by law, these Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by resolution adopted by a majority of the members of the Board of Directors; provided, however, that amendments to Article II, Sections 9 and 10 of these Bylaws, and any other Bylaw provision that implements a majority voting standard for director elections (excepting any amendments intended to conform those Bylaw provisions to changes in applicable laws) shall be amended by the shareholders of the Corporation as provided in Section 1 of this Article V.

9

EX-10.1

Exhibit 10.1

PG&E CORPORATION

2006 LONG-TERM INCENTIVE PLAN

RESTRICTED STOCK UNIT GRANT

PG&E CORPORATION, a California corporation, hereby grants Restricted Stock Units to the Recipient named below. The Restricted Stock Units have been granted under the PG&E Corporation 2006 Long-Term Incentive Plan, as amended (the “LTIP”). The terms and conditions of the Restricted Stock Units are set forth in this cover sheet and in the attached Restricted Stock Unit Agreement (the “Agreement”).

Date of Grant:          March 1, 2012

Name of Recipient:

Recipient’s Participant ID:

Number of Restricted Stock Units:

By accepting this award, you agree to all of the terms and conditions described in the attached Agreement. You and PG&E Corporation agree to execute such further instruments and to take such further action as may reasonably be necessary to carry out the intent of the attached Agreement. You are also acknowledging receipt of this Grant, the attached Agreement, and a copy of the prospectus describing the LTIP and the Restricted Stock Units dated March 1, 2012.

If, for any reason, you wish to not accept this award, please notify PG&E Corporation in writing within 30 calendar days of the date of this award at ATTN: LTIP Administrator at PG&E Corporation, One Market, Spear Tower, Suite 400, San Francisco, California, 94105.

Attachment

PG&E CORPORATION

2006 LONG-TERM INCENTIVE PLAN

RESTRICTED STOCK UNIT AGREEMENT

The LTIP and Other Agreements	This Agreement constitutes the entire understanding between you and PG&E Corporation regarding the Restricted Stock Units, subject to the terms of the LTIP. Any prior agreements, commitments, or negotiations are superseded. In the event of any conflict or inconsistency between the provisions of this Agreement and the LTIP, the LTIP shall govern. Capitalized terms that are not defined in this Agreement are defined in the LTIP. In the event of any conflict between the provisions of this Agreement and the PG&E Corporation Officer Severance Policy or the PG&E Corporation 2012 Officer Severance Policy, this Agreement shall govern. For purposes of this Agreement, employment with PG&E Corporation shall mean employment with any member of the Participating Company Group.
Grant of Restricted Stock Units	PG&E Corporation grants you the number of Restricted Stock Units shown on the cover sheet of this Agreement. The Restricted Stock Units are subject to the terms and conditions of this Agreement and the LTIP.
Vesting of Restricted Stock Units	As long as you remain employed with PG&E Corporation, 20 percent of the total number of Restricted Stock Units originally subject to this Agreement, as shown above on the cover sheet, will vest on the first business day of March of each of the first, second and third years following the Date of Grant, and the additional 40 percent of the total number of shares of Restricted Stock Units will vest on the on the first business day of March of the fourth year following the Date of Grant (collectively, the “Normal Vesting Schedule”). The amounts payable upon each vesting date are hereby designated separate payments for purposes of Code Section 409A. Except as described below, all Restricted Stock Units subject to this Agreement which have not vested upon termination of your employment shall then be automatically cancelled. As set forth below, the Restricted Stock Units may vest earlier upon the occurrence of certain events.
Dividends	Restricted Stock Units will accrue Dividend Equivalents in the event cash dividends are paid with respect to PG&E Corporation common stock having a record date prior to the date on which the Restricted Stock Units are settled. Such Dividend Equivalents will be converted into cash and paid, if at all, upon settlement of the underlying Restricted Stock Units.
Settlement	Vested Restricted Stock Units will be settled in an equal number of shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below. PG&E Corporation shall issue shares as soon as practicable after the Restricted Stock Units vest in accordance with the Normal Vesting Schedule (but not later than sixty (60) days after the applicable vesting date); provided, however, that such issuance shall, if earlier, be made with respect to all of your outstanding

	vested Restricted Stock Units (after giving effect to the vesting provisions described below) as soon as practicable after (but not later than sixty (60) days after) the earliest to occur of your (1) Disability (as defined under Code Section 409A), (2) death or (3) “separation from service,” within the meaning of Code Section 409A within 2 years following a Change in Control.
Voluntary Termination	In the event of your voluntary termination (other than Retirement), all unvested Restricted Stock Units will be cancelled on the date of termination.
Retirement	In the event of your Retirement, unvested Restricted Stock Units will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement; provided, however that in the event of your Retirement within 2 years following a Change in Control, all of your Restricted Stock Units shall vest and be settled as soon as practicable after (but not later than sixty (60) days after) the date of such event. Your voluntary termination of employment will be considered to be a Retirement if you are both age 55 or older on the date of termination and if you were employed by PG&E Corporation for at least five consecutive years ending on the date of termination of your employment.
Termination for Cause	If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause, all unvested Restricted Stock Units will be cancelled on the date of termination. In general, termination for “cause” means termination of employment because of dishonesty, a criminal offense or violation of a work rule, and will be determined by and in the sole discretion of PG&E Corporation.
Termination other than for Cause	If your employment with PG&E Corporation is terminated by PG&E Corporation other than for cause and you are an officer in Bands 1-5, any unvested Restricted Stock Units that would have vested during the period of the “Severance Multiple” under the PG&E Corporation Officer Severance Policy or the PG&E Corporation 2012 Officer Severance Policy (as applicable at the time of termination) will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement. In the event of your involuntary termination other than for cause, if you are not an officer in Bands 1-5, any unvested Restricted Stock Units that would have vested within the 12 months following such termination had your employment continued will continue to vest and be settled pursuant to the Normal Vesting Schedule (without regard to the requirement that you be employed), subject to the earlier settlement provisions of this Agreement. All other unvested Restricted Stock Units will be cancelled unless your termination of employment was in connection with a Change in Control as provided below.
Death/Disability	In the event of your death or Disability while you are employed, all of your

A-2

	Restricted Stock Units shall vest and be settled as soon as practicable after (but not later than sixty (60) days after) the date of such event. If your death or Disability occurs following the termination of your employment and your Restricted Stock Units are then outstanding under the terms hereof, then all of your vested Restricted Stock Units plus any Restricted Stock Units that would have otherwise vested during any continued vesting period hereunder shall be settled as soon as practicable after (but not later than sixty (60) days after) the date of your death or Disability.
Termination Due to Disposition of Subsidiary	(1) If your employment is terminated (other than termination for cause, your voluntary termination, or your Retirement) by reason of a divestiture or change in control of a subsidiary of PG&E Corporation, which divestiture or change in control results in such subsidiary no longer qualifying as a subsidiary corporation under Section 424(f) of the Internal Revenue Code of 1986, as amended (the “Code”), or (2) if your employment is terminated (other than termination for cause, your voluntary termination, or your Retirement) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, the Restricted Stock Units shall vest and be settled in the same manner as for a “Termination other than for Cause” described above.
Change in Control	In the event of a Change in Control, the surviving, continuing, successor, or purchasing corporation or other business entity or parent thereof, as the case may be (the “Acquiror”), may, without your consent, either assume or continue PG&E Corporation’s rights and obligations under this Agreement or provide a substantially equivalent award in substitution for the Restricted Stock Units subject to this Agreement. If the Restricted Stock Units are neither assumed nor continued by the Acquiror or if the Acquiror does not provide a substantially equivalent award in substitution for the Restricted Stock Units, all of your unvested Restricted Stock Units shall automatically vest immediately preceding and contingent on, the Change in Control and be settled in accordance with the Normal Vesting Schedule, subject to the earlier settlement provisions of this Agreement.
Termination In Connection with a Change in Control	If you separate from service (other than termination for cause, your voluntary termination, or your Retirement) in connection with a Change in Control within three months before the Change in Control occurs, all of your outstanding Restricted Stock Units (including Restricted Stock Units that you would have otherwise forfeited after the end of the continued vesting period) shall automatically vest on the date of the Change in Control and will be settled in accordance with the Normal Vesting Schedule (without regard to the requirement that you be employed) subject to the earlier settlement provisions of this Agreement. In the event of such a separation in connection with a Change in Control within two years following the Change in Control, your Restricted Stock Units (to the extent they did not previously vest upon, for example, failure of the Acquiror to assume or continue this Award) shall automatically vest on the date of such

A-3

	separation and will be settled as soon as practicable after (but not later than sixty (60) days after) the date of such separation. PG&E Corporation shall have the sole discretion to determine whether termination of your employment was made in connection with a Change in Control
Delay	PG&E Corporation shall delay the issuance of any shares of common stock to the extent it is necessary to comply with Section 409A(a)(2)(B)(i) of the Code (relating to payments made to certain “key employees” of certain publicly-traded companies); in such event, any shares of common stock to which you would otherwise be entitled during the six (6) month period following the date of your “separation from service” under Section 409A (or shorter period ending on the date of your death following such separation) will instead be issued on the first business day following the expiration of the applicable delay period.
Withholding Taxes	The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of Restricted Stock Units will be reduced by a number of shares having an aggregate Fair Market Value, as determined by PG&E Corporation, equal to the amount of any Federal, state, or local taxes of any kind required by law to be withheld by PG&E Corporation in connection with the Restricted Stock Units determined using the applicable minimum statutory withholding rates, including social security and Medicare taxes due under the Federal Insurance Contributions Act and the California State Disability Insurance tax (“Withholding Taxes”). If the withheld shares were not sufficient to satisfy your minimum Withholding Taxes, you will be required to pay, as soon as practicable, including through additional payroll withholding, any amount of the Withholding Taxes that is not satisfied by the withholding of shares described above.
Leaves of Absence	For purposes of this Agreement, if you are on an approved leave of absence from PG&E Corporation, or a recipient of PG&E Corporation sponsored disability benefits, you will continue to be considered as employed. If you do not return to active employment upon the expiration of your leave of absence or the expiration of your PG&E Corporation sponsored disability benefits, you will be considered to have voluntarily terminated your employment. See above under “Voluntary Termination.” Notwithstanding the foregoing, if the leave of absence exceeds six (6) months, and a return to service upon expiration of such leave is not guaranteed by statute or contract, then you shall be deemed to have had a “separation from service” for purposes of any Restricted Stock Units that are settled hereunder upon such separation. To the extent an authorized leave of absence is due to a medically determinable physical or mental impairment that can be expected to result in death or to last for a continuous period of at least six (6) months and such impairment causes you to be unable to perform the duties of your position of employment or any substantially similar position of employment, the six (6) month period

A-4

	in the prior sentence shall be twenty-nine (29) months. PG&E Corporation reserves the right to determine which leaves of absence will be considered as continuing employment and when your employment terminates for all purposes under this Agreement.
Voting and Other Rights	You shall not have voting rights with respect to the Restricted Stock Units until the date the underlying shares are issued (as evidenced by appropriate entry on the books of PG&E Corporation or its duly authorized transfer agent).
No Retention Rights	This Agreement is not an employment agreement and does not give you the right to be retained by PG&E Corporation. Except as otherwise provided in an applicable employment agreement, PG&E Corporation reserves the right to terminate your employment at any time and for any reason.
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

A-5

EX-10.2

Exhibit 10.2

PG&E CORPORATION

2006 LONG-TERM INCENTIVE PLAN

PERFORMANCE SHARE GRANT

PG&E CORPORATION, a California corporation, hereby grants Performance Shares to the Recipient named below. The Performance Shares have been granted under the PG&E Corporation 2006 Long-Term Incentive Plan, as amended (the “LTIP”). The terms and conditions of the Performance Shares are set forth in this cover sheet and the attached Performance Share Agreement (the “Agreement”).

Date of Grant:           March 1, 2012

Name of Recipient:

Recipient’s Participant ID:

Number of Performance Shares:

By accepting this award, you agree to all of the terms and conditions described in the attached Agreement. You and PG&E Corporation agree to execute such further instruments and to take such further action as may reasonably be necessary to carry out the intent of the attached Agreement. You are also acknowledging receipt of this Grant, the attached Agreement, and a copy of the prospectus describing the LTIP and the Performance Shares dated March 1, 2012.

If, for any reason, you wish to not accept this award, please notify PG&E Corporation in writing within 30 calendar dayus of the date of this award at ATTN: LTIP Administrator at PG&E Corporation, One Market, Spear Tower, Suite 400, San Francisco, CA 94105.

Attachment

PG&E CORPORATION 2006 LONG-TERM INCENTIVE PLAN

PERFORMANCE SHARE AGREEMENT

The LTIP and Other Agreements	This Agreement constitutes the entire understanding between you and PG&E Corporation regarding the Performance Shares, subject to the terms of the LTIP. Any prior agreements, commitments or negotiations are superseded. In the event of any conflict or inconsistency between the provisions of this Agreement and the LTIP, the LTIP shall govern. Capitalized terms that are not defined in this Agreement are defined in the LTIP. In the event of any conflict between the provisions of this Agreement and the PG&E Corporation Officer Severance Policy or the PG&E Corporation 2012 Officer Severance Policy, this Agreement shall govern. The LTIP provides the Committee with discretion to adjust the performance award formula. For purposes of this Agreement, employment with PG&E Corporation shall mean employment with any member of the Participating Company Group.
Grant of Performance Shares	PG&E Corporation grants you the number of Performance Shares shown on the cover sheet of this Agreement. The Performance Shares are subject to the terms and conditions of this Agreement and the LTIP.
Vesting of Performance Shares	As long as you remain employed with PG&E Corporation, the Performance Shares will vest on the first business day of March (the “Vesting Date”) of the third year following the date of grant specified in the cover sheet. Except as described below, all Performance Shares subject to this Agreement that have not vested shall be forfeited upon termination of your employment.
Settlement in Shares	Vested performance shares will be settled in shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below. The number of shares you are entitled to receive will be calculated by multiplying the number of vested Performance Shares by the “settlement percentage” determined as follows (except as set forth elsewhere in this Agreement):
	Upon the Vesting Date, PG&E Corporation’s total shareholder return (“TSR”) will be compared to the TSR of the twelve other companies in PG&E Corporation’s comparator group1 for the prior three calendar years (the “Performance Period”). Subject to rounding considerations, if PG&E Corporation’s TSR falls below the 25th percentile of the comparator group the settlement percentage will be 0%; if PG&E Corporation’s TSR is at the 25th percentile, the settlement percentage will be 25%; if PG&E Corporation’s TSR is at the 75th percentile, the settlement percentage will be 100%; and if PG&E Corporation’s TSR is in the top rank, the settlement percentage will be 200%. The following table sets forth the settlement

¹ The current Performance Comparator Group consists of the following companies: American Electric Power, CMS Energy, Consolidated Edison, DTE Energy, Duke Energy, NiSource, Inc., Northeast Utilities, Pinnacle West Capital, Southern Company, SCANA Corp., Wisconsin Energy Corp., and Xcel Energy. PG&E Corporation reserves the right to change the companies comprising the comparator group in accordance with the rules established by PG&E Corporation in connection with this award.

percentages for the other TSR rankings that could be achieved based on PG&E Corporation’s TSR rank within the comparator group:

	Number of Companies in
Total (Including PG&E Corporation) - 13
Rank	Performance Percentile	Rounded Payout
1	100%	200%
2	92%	170%
3	83%	130%
4	75%	100%
5	67%	90%
6	58%	75%
7	50%	65%
8	42%	50%
9	33%	35%
10	25%	25%
11	17%	0%
12	8%	0%

	The final settlement percentage, if any, will be determined as soon as practicable following the date that the Compensation Committee (or a subcommittee of that Committee) of the PG&E Corporation Board of Directors or an equivalent body certifies the TSR percentile rank over the Performance Period pursuant to Section 10.5(a) of the LTIP. PG&E Corporation will issue shares as soon as practicable after such determination, but no earlier than the Vesting Date, and not later than sixty (60) days after the Vesting Date.
Dividends	Each time that PG&E Corporation declares a dividend on its shares of common stock, an amount equal to the dividend multiplied by the number of Performance Shares granted to you by this Agreement shall be accrued on your behalf. If you receive a Performance Share settlement in accordance with the preceding paragraph, at that same time you also shall receive a cash payment equal to the amount of any dividends accrued with respect to your Performance Shares over the Performance Period multiplied by the same settlement percentage used to determine the number of shares you are entitled to receive, if any.
Voluntary Termination	If you terminate your employment with PG&E Corporation voluntarily before the Vesting Date (other than for Retirement), all of the Performance Shares shall be cancelled as of the date of such termination and any dividends accrued with respect to your Performance Shares shall be forfeited.
Termination for Cause	If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause before the Vesting Date, all of the Performance Shares shall be cancelled as of the date of such termination and any dividends accrued with respect to your Performance Shares shall be forfeited. In general, termination for “cause” means termination of

A-2

	employment because of dishonesty, a criminal offense or violation of a work rule, and will be determined by and in the sole discretion of PG&E Corporation.
Termination other than for Cause	If your employment with PG&E Corporation is terminated by PG&E Corporation other than for cause before the Vesting Date, your unvested Performance Shares will vest proportionally based on the number of months during the Performance Period that you were employed (rounded down) divided by the number of months in the Performance Period (36 months). All other outstanding Performance Shares (and any associated accrued dividends) shall be cancelled unless your termination of employment was in connection with a Change in Control as provided below. Your vested Performance Shares will be settled, if at all, as soon as practicable after the Vesting Date and in any event within sixty (60) days of the Vesting Date, based on the same settlement percentage applied to active employees. At that time you also shall receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your vested Performance Shares multiplied by the same settlement percentage used to determine the number of shares you are entitled to receive, if any.
Retirement	If you retire before the Vesting Date, your outstanding Performance Shares will continue to vest as though your employment had continued and will be settled, if at all, as soon as practicable following the Vesting Date and in any event within sixty (60) days of the Vesting Date. At the same time you also shall also receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your Performance Shares multiplied by the same settlement percentage used to determine the number of shares you are entitled to receive, if any. You will be considered to have retired if you are age 55 or older on the date of termination and if you were employed by PG&E Corporation for at least five consecutive years ending on the date of termination of your employment.
Death/Disability	If your employment terminates due to your death or disability before the Vesting Date, all of your Performance Shares shall immediately vest and will be settled, if at all, as soon as practicable after the Vesting Date and in any event within sixty (60) days of the Vesting Date based on the same settlement percentage applied to active employees. At that same time you also shall receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your Performance Shares multiplied by the same settlement percentage used to determine the number of shares you are entitled to receive, if any.
Termination Due to Disposition of Subsidiary	(1) If your employment is terminated (other than for cause or your voluntary termination) by reason of a divestiture or change in control of a subsidiary of PG&E Corporation, which divestiture or change in control results in such subsidiary no longer qualifying as a subsidiary corporation under Section 424(f) of the Internal Revenue Code of 1986, as amended, or (2) if your employment is terminated (other than for cause or your voluntary termination) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, your unvested Performance Shares shall vest proportionally based on the number of months during the Performance

A-3

Period that you were employed (rounded down) divided by the number of months in the Performance Period (36 months). All other outstanding Performance Shares (and any associated accrued dividends) shall automatically be cancelled upon such termination. Your vested Performance Shares will be settled, if at all, as soon as practicable after the Vesting Date and in any event within sixty (60) days of the Vesting Date, based on the same settlement percentage applied to active employees. At that same time you also shall receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your vested Performance Shares multiplied by the same settlement percentage used to determine the number of shares you are entitled to receive, if any.

Change in Control

In the event of a Change in Control, the surviving, continuing, successor, or purchasing corporation or other business entity or parent thereof, as the case may be (the “Acquiror”), may, without your consent, either assume or continue PG&E Corporation’s rights and obligations under this Agreement or provide a substantially equivalent award in substitution for the Performance Shares subject to this Agreement. If the Acquiror assumes or continues PG&E Corporation’s rights and obligations under this Agreement or substitutes a substantially equivalent award, TSR shall be calculated by combining (a) the TSR of PG&E Corporation for the period from January 1 of the year of grant to the date of the Change in Control, and (b) the TSR of the Acquiror from the date of the Change in Control to the last calendar day of the year preceding the Vesting Date. The settlement percentage reflected in the table set forth above for the highest percentile TSR performance met or exceeded when calculated on that basis, and considering any adjustments to the comparator group, will be used to determine the number of shares, if any, you are entitled to receive upon settlement of the assumed, continued or substituted award, which settlement shall occur as soon as practicable after the Vesting Date and in any event within sixty (60) days of the Vesting Date. At that time you also shall receive a cash payment, if any, equal to the amount of dividends accrued with respect to your Performance Shares over the Performance Period multiplied by the same settlement percentage used to determine the number of shares you are entitled to receive, if any. If the Change in Control of PG&E Corporation occurs before the original Vesting Date, and if this Award is neither assumed nor continued by the Acquiror or if the Acquiror does not provide a substantially equivalent award in substitution for the Performance Shares subject to this Agreement, all of your outstanding Performance Shares shall automatically vest and become nonforfeitable on the date of the Change in Control. Such vested Performance Shares will be settled, if at all, as soon as practicable following the original Vesting Date and in any event within sixty (60) days of the original Vesting Date. The settlement percentage, if any, will be based on TSR for the period from January 1 of the year of grant to the date of the Change in Control compared to the TSR of the other companies in PG&E Corporation’s comparator group for the same period. At the same time you also shall receive a cash payment, if any, equal to the amount of dividends accrued with respect to your Performance Shares to the date of the Change in Control multiplied by the same settlement percentage used to determine the

A-4

	number of shares you are entitled to receive, if any.
Termination In Connection with a Change in Control	If your employment is terminated by PG&E Corporation other than for cause in connection with a Change in Control within within two years following the Change in Control, all of your outstanding Performance Shares (to the extent they did not previously vest upon failure of the Acquiror to assume or continue this Award) shall automatically vest and become nonforfeitable on the date of termination of your employment. If your employment is terminated by PG&E Corporation other than for cause in connection with a Change in Control within three months before the Change in Control occurs, all of your outstanding performance shares will automatically vest in full and become nonforfeitable (including the portion that you would have otherwise forfeited based on the proration of vested performance shares through the date of termination of your employment) as of the date of the Change in Control. Your vested Performance Shares will be settled, if at all, as soon as practicable following the original Vesting Date and in any event within sixty (60) days of the Vesting Date and will be based on the same settlement percentage applied to active employees. You shall also at that time receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your vested Performance Shares multiplied by the same settlement percentage used to determine the number of shares you are entitled to receive, if any. PG&E Corporation shall have the sole discretion to determine whether termination of your employment was made in connection with a Change in Control.
Withholding Taxes	The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of Performance Shares will be reduced by a number of shares having an aggregate Fair Market Value, as determined by PG&E Corporation, equal to the amount of any Federal, state, or local taxes of any kind required by law to be withheld by PG&E Corporation in connection with the Performance Shares determined using the applicable minimum statutory withholding rates, including social security and Medicare taxes due under the Federal Insurance Contributions Act and the California State Disability Insurance tax (“Withholding Taxes”). If the withheld shares were not sufficient to satisfy your minimum Withholding Taxes, you will be required to pay, as soon as practicable, including through additional payroll withholding, any amount of the Withholding Taxes that is not satisfied by the withholding of shares described above.
Leaves of Absence	For purposes of this Agreement, if you are on an approved leave of absence from PG&E Corporation, or a recipient of PG&E Corporation sponsored disability benefits, you will continue to be considered as employed. If you do not return to active employment upon the expiration of your leave of absence or the expiration of your PG&E Corporation sponsored disability benefits, you will be considered to have voluntarily terminated your employment. See above under “Voluntary Termination.” PG&E Corporation reserves the right to determine which leaves of absence will be considered as continuing employment and when your employment terminates for all purposes under this Agreement.

A-5

No Retention Rights	This Agreement is not an employment agreement and does not give you the right to be retained by PG&E Corporation. Except as otherwise provided in an applicable employment agreement, PG&E Corporation reserves the right to terminate your employment at any time and for any reason.
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

A-6

EX-10.3

Exhibit 10.3

PG&E CORPORATION

2006 LONG-TERM INCENTIVE PLAN

2012 RESTRICTED STOCK UNIT GRANT

PG&E CORPORATION, a California corporation, hereby grants Restricted Stock Units to the Recipient named below. The Restricted Stock Units have been granted under the PG&E Corporation 2006 Long-Term Incentive Plan, as amended (the “LTIP”). The terms and conditions of the Restricted Stock Units are set forth in this cover sheet and in the attached Restricted Stock Unit Agreement (the “Agreement”).

Date of Grant:          March 1, 2012

  Name of Recipient:                    ANTHONY F. EARLEY, JR.

  Recipient’s Participant ID:                      00236781

  Number of Restricted Stock Units:            62,305

By accepting this award, you agree to all of the terms and conditions described in the attached Agreement. You and PG&E Corporation agree to execute such further instruments and to take such further action as may reasonably be necessary to carry out the intent of the attached Agreement. You are also acknowledging receipt of this Grant, the attached Agreement, and a copy of the prospectus describing the LTIP and the Restricted Stock Units dated March 1, 2012, and any supplements to that prospectus.

If, for any reason, you wish to not accept this award, please notify PG&E Corporation in writing within 60 calendar days of the date of this award at ATTN: LTIP Administrator, PG&E Corporation, One Market, Spear Tower, San Francisco, CA 94105.

Attachment

PG&E CORPORATION

2006 LONG-TERM INCENTIVE PLAN

RESTRICTED STOCK UNIT AGREEMENT

The LTIP and Other Agreements	This Agreement constitutes the entire understanding between you and PG&E Corporation regarding the Restricted Stock Units, subject to the terms of the LTIP. Any prior agreements, commitments, or negotiations are superseded. In the event of any conflict or inconsistency between the provisions of this Agreement and the LTIP, the LTIP shall govern. Capitalized terms that are not defined in this Agreement are defined in the LTIP. In the event of any conflict between the provisions of this Agreement and the PG&E Corporation Officer Severance Policy or the PG&E Corporation 2012 Officer Severance Policy, this Agreement shall govern. For purposes of this Agreement, employment with PG&E Corporation shall mean employment with any member of the Participating Company Group.
Grant of Restricted Stock Units	PG&E Corporation grants you the number of Restricted Stock Units shown on the cover sheet of this Agreement. The Restricted Stock Units are subject to the terms and conditions of this Agreement and the LTIP.
Vesting of Restricted Stock Units	As long as you remain employed with PG&E Corporation, 20 percent of the total number of Restricted Stock Units originally subject to this Agreement, as shown above on the cover sheet, will vest on the first business day of March of each of the first, second and third years following the Date of Grant, and the additional 40 percent of the total number of shares of Restricted Stock Units will vest on the on the first business day of March of the fourth year following the Date of Grant (collectively, the “Normal Vesting Schedule”). The amounts payable upon each vesting date are hereby designated separate payments for purposes of Code Section 409A. Except as described below, all Restricted Stock Units subject to this Agreement which have not vested upon termination of your employment shall then be automatically cancelled. As set forth below, the Restricted Stock Units may vest earlier upon the occurrence of certain events.
Pro-Rata Vesting of Restricted Stock Units	Notwithstanding any other vesting provisions noted in this Agreement, after you complete at least three years of employment with PG&E Corporation, upon your termination (other than termination for cause, voluntary termination, termination due to death or Disability, or termination in connection with a Change in Control) additional Restricted Stock Units shall continue to vest (as if you continued to be employed by PG&E Corporation) such that the total number of vested Restricted Stock Units (including Restricted Stock Units, if any, that vested prior to the date of termination) shall be equal to the greater of (1) the actual number of vested Restricted Stock Units or (2) the number determined by multiplying the total number of Restricted Stock Units subject to this Agreement by the number of your days of service with PG&E Corporation in the Normal Vesting Schedule (through the date of termination), divided by the

	potential number of days of service in the Normal Vesting Schedule. All other unvested Restricted Stock Units will be cancelled upon such termination. Vested Restricted Stock Units will continue to be settled and paid on the same time schedule and at the rate that would be normally applicable (absent your termination of employment) until the pro-rated amount (if any) is exhausted.
Dividends	Restricted Stock Units will accrue Dividend Equivalents in the event cash dividends are paid with respect to PG&E Corporation common stock having a record date prior to the date on which the Restricted Stock Units are settled. Such Dividend Equivalents will be converted into cash and paid, if at all, upon settlement of the underlying Restricted Stock Units.
Settlement	Vested Restricted Stock Units will be settled in an equal number of shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below. PG&E Corporation shall issue shares as soon as practicable after the Restricted Stock Units vest in accordance with the Normal Vesting Schedule (but not later than sixty (60) days after the applicable vesting date); provided, however, that such issuance shall, if earlier, be made with respect to all of your outstanding vested Restricted Stock Units (after giving effect to the vesting provisions described below) as soon as practicable after (but not later than sixty (60) days after) the earliest to occur of your (1) Disability (as defined under Code Section 409A), (2) death or (3) “separation from service,” within the meaning of Code Section 409A within 2 years following a Change in Control.
Voluntary Termination	In the event of your voluntary termination, all unvested Restricted Stock Units will be cancelled on the date of termination.
Termination for Cause	If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause, all unvested Restricted Stock Units will be cancelled on the date of termination. For these purposes, “cause” means when PG&E Corporation, acting in good faith based upon information then known to it, determines that you have engaged in, committed, or are responsible for, (1) serious misconduct, gross negligence, theft, or fraud against PG&E Corporation and/or its affiliates, (2) refusal or unwillingness to perform your duties; (3) inappropriate conduct in violation of PG&E Corporation’s equal employment opportunity policy; (4) conduct which reflects adversely upon, or making any remarks disparaging of, PG&E Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries; (5) insubordination; (6) any willful act that is likely to have the effect of injuring the reputation, business, or business relationships of PG&E Corporation or its subsidiaries or affiliates; (7) violation of any fiduciary duty; or (8) breach of any duty of loyalty.

A-2

Termination other than for Cause	If your employment with PG&E Corporation is terminated by PG&E Corporation other than for cause, all unvested Restricted Stock Units will be cancelled unless your termination of employment was in connection with a Change in Control as provided below, or if provisions relating to pro-rata vesting of Restricted Stock Units apply.
Death/Disability	In the event of your death or Disability while you are employed, all of your Restricted Stock Units shall vest and be settled as soon as practicable after (but not later than sixty (60) days after) the date of such event. If your death or Disability occurs following the termination of your employment and your Restricted Stock Units are then outstanding under the terms hereof, then all of your vested Restricted Stock Units plus any Restricted Stock Units that would have otherwise vested during any continued vesting period hereunder shall be settled as soon as practicable after (but not later than sixty (60) days after) the date of your death or Disability.
Termination Due to Disposition of Subsidiary	(1) If your employment is terminated (other than termination for cause or your voluntary termination) by reason of a divestiture or change in control of a subsidiary of PG&E Corporation, which divestiture or change in control results in such subsidiary no longer qualifying as a subsidiary corporation under Section 424(f) of the Internal Revenue Code of 1986, as amended (the “Code”), or (2) if your employment is terminated (other than termination for cause or your voluntary termination) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, the Restricted Stock Units shall vest and be settled in the same manner as for a “Termination other than for Cause” described above.
Change in Control	In the event of a Change in Control, the surviving, continuing, successor, or purchasing corporation or other business entity or parent thereof, as the case may be (the “Acquiror”), may, without your consent, either assume or continue PG&E Corporation’s rights and obligations under this Agreement or provide a substantially equivalent award in substitution for the Restricted Stock Units subject to this Agreement. If the Restricted Stock Units are neither assumed nor continued by the Acquiror or if the Acquiror does not provide a substantially equivalent award in substitution for the Restricted Stock Units, all of your unvested Restricted Stock Units shall automatically vest immediately preceding and contingent on, the Change in Control and be settled in accordance with the Normal Vesting Schedule, subject to the earlier settlement provisions of this Agreement.
Termination In Connection with a Change in Control	If you separate from service (other than termination for cause or your voluntary termination) in connection with a Change in Control within three months before the Change in Control occurs, all of your outstanding Restricted Stock Units (including Restricted Stock Units that you would have otherwise forfeited after the end of the continued vesting period) shall

A-3

	automatically vest on the date of the Change in Control and will be settled in accordance with the Normal Vesting Schedule (without regard to the requirement that you be employed) subject to the earlier settlement provisions of this Agreement. In the event of such a separation in connection with a Change in Control within two years following the Change in Control, your Restricted Stock Units (to the extent they did not previously vest upon, for example, failure of the Acquiror to assume or continue this Award) shall automatically vest on the date of such separation and will be settled as soon as practicable after (but not later than sixty (60) days after) the date of such separation. PG&E Corporation shall have the sole discretion to determine whether termination of your employment was made in connection with a Change in Control
Delay	PG&E Corporation shall delay the issuance of any shares of common stock to the extent it is necessary to comply with Section 409A(a)(2)(B)(i) of the Code (relating to payments made to certain “key employees” of certain publicly-traded companies); in such event, any shares of common stock to which you would otherwise be entitled during the six (6) month period following the date of your “separation from service” under Section 409A (or shorter period ending on the date of your death following such separation) will instead be issued on the first business day following the expiration of the applicable delay period.
Withholding Taxes	The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of Restricted Stock Units will be reduced by a number of shares having an aggregate Fair Market Value, as determined by PG&E Corporation, equal to the amount of any Federal, state, or local taxes of any kind required by law to be withheld by PG&E Corporation in connection with the Restricted Stock Units determined using the applicable minimum statutory withholding rates, including social security and Medicare taxes due under the Federal Insurance Contributions Act and the California State Disability Insurance tax (“Withholding Taxes”). If the withheld shares were not sufficient to satisfy your minimum Withholding Taxes, you will be required to pay, as soon as practicable, including through additional payroll withholding, any amount of the Withholding Taxes that is not satisfied by the withholding of shares described above.
Leaves of Absence	For purposes of this Agreement, if you are on an approved leave of absence from PG&E Corporation, or a recipient of PG&E Corporation sponsored disability benefits, you will continue to be considered as employed. If you do not return to active employment upon the expiration of your leave of absence or the expiration of your PG&E Corporation sponsored disability benefits, you will be considered to have voluntarily terminated your employment. See above under “Voluntary Termination.” Notwithstanding the foregoing, if the leave of absence exceeds six (6) months, and a return to service upon expiration of such leave is not

A-4

	guaranteed by statute or contract, then you shall be deemed to have had a “separation from service” for purposes of any Restricted Stock Units that are settled hereunder upon such separation. To the extent an authorized leave of absence is due to a medically determinable physical or mental impairment that can be expected to result in death or to last for a continuous period of at least six (6) months and such impairment causes you to be unable to perform the duties of your position of employment or any substantially similar position of employment, the six (6) month period in the prior sentence shall be twenty-nine (29) months. PG&E Corporation reserves the right to determine which leaves of absence will be considered as continuing employment and when your employment terminates for all purposes under this Agreement.
Voting and Other Rights	You shall not have voting rights with respect to the Restricted Stock Units until the date the underlying shares are issued (as evidenced by appropriate entry on the books of PG&E Corporation or its duly authorized transfer agent).
No Retention Rights	This Agreement is not an employment agreement and does not give you the right to be retained by PG&E Corporation. Except as otherwise provided in an applicable employment agreement, PG&E Corporation reserves the right to terminate your employment at any time and for any reason.
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

A-5

EX-10.4

Exhibit 10.4

PG&E CORPORATION

2006 LONG-TERM INCENTIVE PLAN

2012 PERFORMANCE SHARE GRANT

PG&E CORPORATION, a California corporation, hereby grants Performance Shares to the Recipient named below. The Performance Shares have been granted under the PG&E Corporation 2006 Long-Term Incentive Plan, as amended (the “LTIP”). The terms and conditions of the Performance Shares are set forth in this cover sheet and the attached Performance Share Agreement (the “Agreement”).

Date of Grant:           March 1, 2012

  Name of Recipient:                              ANTHONY F. EARLEY, JR.

  Recipient’s Participant ID:                              00236781

  Number of Performance Shares:                      93.455

By accepting this award, you agree to all of the terms and conditions described in the attached Agreement. You and PG&E Corporation agree to execute such further instruments and to take such further action as may reasonably be necessary to carry out the intent of the attached Agreement. You are also acknowledging receipt of this Grant, the attached Agreement, and a copy of the prospectus describing the LTIP and the Performance Shares dated March 1, 2012, and any supplements to that Prospectus.

If, for any reason, you wish to not accept this award, please notify PG&E Corporation in writing within 60 calendar days of the date of this award at ATTN: LTIP Administrator, PG&E Corporation, One Market, Spear Tower, Suite 400, San Francisco, CA, 94105.

Attachment

PG&E CORPORATION 2006 LONG-TERM INCENTIVE PLAN

PERFORMANCE SHARE AGREEMENT

The LTIP and Other Agreements	This Agreement constitutes the entire understanding between you and PG&E Corporation regarding the Performance Shares, subject to the terms of the LTIP. Any prior agreements, commitments or negotiations are superseded. In the event of any conflict or inconsistency between the provisions of this Agreement and the LTIP, the LTIP shall govern. Capitalized terms that are not defined in this Agreement are defined in the LTIP. In the event of any conflict between the provisions of this Agreement and the PG&E Corporation Officer Severance Policy or the PG&E Corporation 2012 Officer Severance Policy, this Agreement shall govern. The LTIP provides the Committee with discretion to adjust the performance award formula. For purposes of this Agreement, employment with PG&E Corporation shall mean employment with any member of the Participating Company Group.
Grant of Performance Shares	PG&E Corporation grants you the number of Performance Shares shown on the cover sheet of this Agreement. The Performance Shares are subject to the terms and conditions of this Agreement and the LTIP.
Vesting of Performance Shares	As long as you remain employed with PG&E Corporation, the Performance Shares will vest on the first business day of March (the “Vesting Date”) of the third year following the date of grant specified in the cover sheet. Except as described below, all Performance Shares subject to this Agreement that have not vested shall be forfeited upon termination of your employment.
Pro-Rata Vesting of Performance Shares	Notwithstanding any other vesting provisions noted in this Agreement, after you complete at least three years of employment with PG&E Corporation, upon your termination (other than termination for cause, voluntary termination, termination due to death or Disability, or termination in connection with a Change in Control) the number of vested Performance Shares shall equal the number of Performance Shares subject to this Agreement, multiplied by the number of your days of service with PG&E Corporation in the vesting period (through the date of termination), divided by the potential number of days of service in the vesting period. Your vested Performance Shares will be settled, if at all, as soon as practicable after the Vesting Date and in any event within sixty (60) days of the Vesting Date, based on the same settlement percentage applied to active employees. All other unvested Performance Shares will be cancelled upon such termination. Your vested Performance Shares will be settled, if at all, as soon as practicable after the Vesting Date and in any event within sixty (60) days of the Vesting Date, based on the same settlement percentage applied to active employees. At that time you also shall receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your vested Performance Shares multiplied by the same settlement percentage used to determine the number of shares you are entitled to receive, if any.
Settlement in Shares	Vested Performance Shares will be settled in shares of PG&E Corporation common stock, subject to the satisfaction of Withholding Taxes, as described below. The number of shares you are entitled to receive will be calculated

by multiplying the number of vested Performance Shares by the “settlement percentage” determined as follows (except as set forth elsewhere in this Agreement):

Upon the Vesting Date, PG&E Corporation’s total shareholder return (“TSR”) will be compared to the TSR of the twelve other companies in PG&E Corporation’s comparator group¹ for the prior three calendar years (the “Performance Period”). Subject to rounding considerations, if PG&E Corporation’s TSR falls below the 25^th percentile of the comparator group the settlement percentage will be 0%; if PG&E Corporation’s TSR is at the 25^th percentile, the settlement percentage will be 25%; if PG&E Corporation’s TSR is at the 75^th percentile, the settlement percentage will be 100%; and if PG&E Corporation’s TSR is in the top rank, the settlement percentage will be 200%. The following table sets forth the settlement percentages for the other TSR rankings that could be achieved based on PG&E Corporation’s TSR rank within the comparator group:

	Number of Companies in
Total (Including PG&E Corporation) - 13
Rank	Performance Percentile	Rounded Payout
1	100%	200%
2	92%	170%
3	83%	130%
4	75%	100%
5	67%	90%
6	58%	75%
7	50%	65%
8	42%	50%
9	33%	35%
10	25%	25%
11	17%	0%
12	8%	0%

The final settlement percentage, if any, will be determined as soon as practicable following the date that the Compensation Committee (or a subcommittee of that Committee) of the PG&E Corporation Board of Directors or an equivalent body certifies the TSR percentile rank over the Performance Period pursuant to Section 10.5(a) of the LTIP. PG&E Corporation will issue shares as soon as practicable after such determination, but no earlier than the Vesting Date, and not later than sixty (60) days after the Vesting Date.

¹  The current Performance Comparator Group consists of the following companies: American Electric Power, CMS Energy, Consolidated Edison, DTE Energy, Duke Energy, NiSource, Inc., Northeast Utilities, Pinnacle West Capital, Southern Company, SCANA Corp., Wisconsin Energy Corp., and Xcel Energy. PG&E Corporation reserves the right to change the companies comprising the comparator group in accordance with the rules established by PG&E Corporation in connection with this award.

Dividends	Each time that PG&E Corporation declares a dividend on its shares of common stock, an amount equal to the dividend multiplied by the number of Performance Shares granted to you by this Agreement shall be accrued on your behalf. If you receive a Performance Share settlement in accordance with the preceding paragraph, at that same time you also shall receive a cash payment equal to the amount of any dividends accrued with respect to your Performance Shares over the Performance Period multiplied by the same settlement percentage used to determine the number of shares you are entitled to receive, if any.
Voluntary Termination	If you terminate your employment with PG&E Corporation voluntarily before the Vesting Date, all of the Performance Shares shall be cancelled as of the date of such termination and any dividends accrued with respect to your Performance Shares shall be forfeited.
Termination for Cause	If your employment with PG&E Corporation is terminated at any time by PG&E Corporation for cause before the Vesting Date, all of the Performance Shares shall be cancelled as of the date of such termination and any dividends accrued with respect to your Performance Shares shall be forfeited. For these purposes, “cause” means when PG&E Corporation, acting in good faith based upon information then known to it, determines that you have engaged in, committed, or are responsible for, (1) serious misconduct, gross negligence, theft, or fraud against PG&E Corporation and/or its affiliates, (2) refusal or unwillingness to perform your duties; (3) inappropriate conduct in violation of PG&E Corporation’s equal employment opportunity policy; (4) conduct which reflects adversely upon, or making any remarks disparaging of, PG&E Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries; (5) insubordination; (6) any willful act that is likely to have the effect of injuring the reputation, business, or business relationships of PG&E Corporation or its subsidiaries or affiliates; (7) violation of any fiduciary duty; or (8) breach of any duty of loyalty.
Termination other than for Cause	If your employment with PG&E Corporation is terminated by PG&E Corporation other than for cause before the Vesting Date, all unvested Performance Shares shall be cancelled unless your termination of employment was in connection with a Change in Control as provided below, or if provisions relating to pro-rata vesting of Restricted Stock Units apply.
Death/Disability	If your employment terminates due to your death or disability before the Vesting Date, all of your Performance Shares shall immediately vest and will be settled, if at all, as soon as practicable after the Vesting Date and in any event within sixty (60) days of the Vesting Date based on the same settlement percentage applied to active employees. At that same time you also shall receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your Performance Shares multiplied by the same settlement percentage used to determine the number of shares you are entitled to receive, if any.

Termination Due to Disposition of Subsidiary

(1) If your employment is terminated (other than for cause or your voluntary termination) by reason of a divestiture or change in control of a subsidiary of PG&E Corporation, which divestiture or change in control results in such subsidiary no longer qualifying as a subsidiary corporation under Section 424(f) of the Internal Revenue Code of 1986, as amended, or (2) if your employment is terminated (other than for cause or your voluntary termination) coincident with the sale of all or substantially all of the assets of a subsidiary of PG&E Corporation, your unvested Performance Shares shall vest and be settled in the same manner as for a “Termination other than for Cause” described above.

Change in Control

In the event of a Change in Control, the surviving, continuing, successor, or purchasing corporation or other business entity or parent thereof, as the case may be (the “Acquiror”), may, without your consent, either assume or continue PG&E Corporation’s rights and obligations under this Agreement or provide a substantially equivalent award in substitution for the Performance Shares subject to this Agreement. If the Acquiror assumes or continues PG&E Corporation’s rights and obligations under this Agreement or substitutes a substantially equivalent award, TSR shall be calculated by combining (a) the TSR of PG&E Corporation for the period from January 1 of the year of grant to the date of the Change in Control, and (b) the TSR of the Acquiror from the date of the Change in Control to the last calendar day of the year preceding the Vesting Date. The settlement percentage reflected in the table set forth above for the highest percentile TSR performance met or exceeded when calculated on that basis, and considering any adjustments to the comparator group, will be used to determine the number of shares, if any, you are entitled to receive upon settlement of the assumed, continued or substituted award, which settlement shall occur as soon as practicable after the Vesting Date and in any event within sixty (60) days of the Vesting Date. At that time you also shall receive a cash payment, if any, equal to the amount of dividends accrued with respect to your Performance Shares over the Performance Period multiplied by the same settlement percentage used to determine the number of shares you are entitled to receive, if any. If the Change in Control of PG&E Corporation occurs before the original Vesting Date, and if this Award is neither assumed nor continued by the Acquiror or if the Acquiror does not provide a substantially equivalent award in substitution for the Performance Shares subject to this Agreement, all of your outstanding Performance Shares shall automatically vest and become nonforfeitable on the date of the Change in Control. Such vested Performance Shares will be settled, if at all, as soon as practicable following the original Vesting Date and in any event within sixty (60) days of the original Vesting Date. The settlement percentage, if any, will be based on TSR for the period from January 1 of the year of grant to the date of the Change in Control compared to the TSR of the other companies in PG&E Corporation’s comparator group for the same period. At the same time you also shall receive a cash payment, if any, equal to the amount of dividends accrued with respect to your Performance Shares to the date of the Change in Control multiplied by the same settlement percentage used to determine the number of shares you are entitled to receive, if any.

Termination In Connection with a Change in Control	If your employment is terminated by PG&E Corporation other than for cause in connection with a Change in Control within two years following the Change in Control, all of your outstanding Performance Shares (to the extent they did not previously vest upon failure of the Acquiror to assume or continue this Award) shall automatically vest and become nonforfeitable on the date of termination of your employment. If your employment is terminated by PG&E Corporation other than for cause in connection with a Change in Control within three months before the Change in Control occurs, all of your outstanding Performance Shares will automatically vest in full and become nonforfeitable (including the portion that you would have otherwise forfeited based on the proration of vested Performance Shares through the date of termination of your employment) as of the date of the Change in Control. Your vested Performance Shares will be settled, if at all, as soon as practicable following the original Vesting Date and in any event within sixty (60) days of the Vesting Date and will be based on the same settlement percentage applied to active employees. You shall also at that time receive a cash payment, if any, equal to the amount of dividends accrued over the Performance Period with respect to your vested Performance Shares multiplied by the same settlement percentage used to determine the number of shares you are entitled to receive, if any. PG&E Corporation shall have the sole discretion to determine whether termination of your employment was made in connection with a Change in Control.
Withholding Taxes	The number of shares of PG&E Corporation common stock that you are otherwise entitled to receive upon settlement of Performance Shares will be reduced by a number of shares having an aggregate Fair Market Value, as determined by PG&E Corporation, equal to the amount of any Federal, state, or local taxes of any kind required by law to be withheld by PG&E Corporation in connection with the Performance Shares determined using the applicable minimum statutory withholding rates, including social security and Medicare taxes due under the Federal Insurance Contributions Act and the California State Disability Insurance tax (“Withholding Taxes”). If the withheld shares were not sufficient to satisfy your minimum Withholding Taxes, you will be required to pay, as soon as practicable, including through additional payroll withholding, any amount of the Withholding Taxes that is not satisfied by the withholding of shares described above.
Leaves of Absence	For purposes of this Agreement, if you are on an approved leave of absence from PG&E Corporation, or a recipient of PG&E Corporation sponsored disability benefits, you will continue to be considered as employed. If you do not return to active employment upon the expiration of your leave of absence or the expiration of your PG&E Corporation sponsored disability benefits, you will be considered to have voluntarily terminated your employment. See above under “Voluntary Termination.” PG&E Corporation reserves the right to determine which leaves of absence will be considered as continuing employment and when your employment terminates for all purposes under this Agreement.
No Retention Rights	This Agreement is not an employment agreement and does not give you the right to be retained by PG&E Corporation. Except as otherwise provided in an applicable employment agreement, PG&E Corporation reserves the right

	to terminate your employment at any time and for any reason.
Applicable Law	This Agreement will be interpreted and enforced under the laws of the State of California.

EX-10.5

Exhibit 10.5

PG&E CORPORATION

OFFICER SEVERANCE POLICY

(As Amended Effective as of March 1, 2012)

1.       Purpose.  This is the controlling and definitive statement of the Officer Severance Policy of PG&E Corporation (“Policy”). Since Officers are employed at the will of PG&E Corporation (“Corporation”) or a participating employer (“Employer”), their employment may be terminated at any time, with or without cause. A list of Employers is attached hereto as Appendix A. The Policy, which was first adopted effective November 1, 1998, provides Officers of the Corporation and Employers in Officer Compensation Bands I through V (“Officers”) with severance benefits if their employment is terminated.¹ Severance benefits for officers not covered by this Policy will be provided under policies or programs developed by the appropriate lines of business in consultation with and with the approval by the Senior Human Resources Officer of the Corporation. For the avoidance of doubt, the revisions made to this Policy relating to Code Section 409A (defined below), apply to all Officers including those that may be covered under prior provisions of the Policy as required by Section 6 hereof.

The purpose of the Policy is to attract and retain senior management by defining terms and conditions for severance benefits, to provide severance benefits that are part of a competitive total compensation package, to provide consistent treatment for all terminated officers, and to minimize potential litigation costs associated with Officer termination of employment.

This Policy will not provide benefits to individuals who newly satisfy the definition of “Officer” on or after March 1, 2012. Such individuals will instead be eligible for severance benefits described in the PG&E Corporation 2012 Officer Severance Policy (“2012 Policy”). Any Officer who is eligible for benefits under this Policy as of February 29, 2012, will continue to be eligible for benefits under this Policy until three years following the date on which notice is provided regarding the adoption of the 2012 Policy and its terms, to the extent that such delay is required by Section 6. After the completion of any required three-year notice period, such Officers will be subject to the 2012 Policy. Notwithstanding the terms of this agreement, any individual who qualifies as an “Officer” may waive his or her rights under this Policy.

2.       Termination of Employment Not Following a Change in Control or Potential Change in Control.

(a)      Corporation or Employer’s Obligations.  If the Corporation or an Employer exercises its right to terminate an Officer’s employment without cause and such termination does not entitle Officer to payments under Section 3, the Officer shall be given thirty (30) days’

¹  Severance benefits for Officers who are currently covered by an employment agreement will continue to be provided solely under such agreements until their expiration at which time this Policy will become effective for such Officers. If an employee becomes a covered Officer under this Policy as a result of a promotion, if such Officer was then covered by a severance arrangement subject to Section 409A of the Internal Revenue Code of 1986 (“Code Section 409A”), the severance benefits under this Policy provided to such person shall comply with the time and form of payment provisions of such prior severance arrangement, to the extent required by Code Section 409A.

advance written notice or pay in lieu thereof (which shall be paid in a lump sum together with the payment described in Section 2(a)(1) below). Except as provided in Section 2(b) below, in consideration of the Officer’s agreement to the obligations described in Section 2(d) below and to the arbitration provisions described in Section 12 below, the following payments and benefits shall also be provided to Officer following Officer’s separation from service (within the meaning of Code Section 409A):²

(1)      A lump sum severance payment equal to: ¹/ ₁₂ (the sum of the Officer’s annual base compensation and the Officer’s Short-Term Incentive Plan target award at the time of his or her termination) times (the number of months that Officer was employed by the Corporation or the Employer (“Severance Multiple”)); provided, however, that the Severance Multiple shall be no less than 6, nor more than 24 for Officers in Officer Bands I, II, III, or more than 18 for Officers in Officer Bands IV or V. Annual base compensation shall mean the Officer’s monthly base pay for the month in which the Officer is given notice of termination, multiplied by 12. The payment described in this Section 2(a)(1) shall be made in a single lump sum as soon as practicable following the date the release of claims described in Section 2(d)(1) becomes effective, provided that payment shall in no event be made later than the 15th day of the third month following the later of the end of the calendar year or the Corporation’s taxable year in which the Officer’s separation from service occurs.

(2)      Except as otherwise set forth in the applicable award agreement or as otherwise required by applicable law, the equity-based incentive awards granted to Officer under the Corporation’s Long-Term Incentive Program which have not yet vested as of the date of termination will continue to vest over a period of months equal to the Severance Multiple after the date of termination as if the Officer had remained employed for such period. Except as otherwise set forth in the applicable award agreement, for vested stock options as of the date of termination, the Officer shall have the right to exercise such stock options at any time within their respective terms or within five years after termination, whichever is shorter. Except as otherwise set forth in the applicable award agreement, for stock options that vest during a period of months equal to the Severance Multiple, the Officer shall have the right to exercise such options at any time within five years after termination, subject to the term of the options. Except as otherwise set forth in the applicable award agreement, any unvested equity-based incentive awards remaining at the end of such period shall be forfeited;

(3)      For Officers in Officer Bands I, II or III, two thirds of the unvested Company stock units in the Officer’s account in the Corporation’s Deferred Compensation Plan for Officers which were awarded in connection with the Executive Stock Ownership Program requirements (“SISOPs”) shall vest upon the Officer’s termination, and one third shall be forfeited. For Officers in Officer Bands IV and V, one third of any unvested SISOPs shall vest upon the Officer’s termination, and two thirds shall be forfeited. Unvested stock units attributable to SISOPs which become vested under this provision shall be distributed to Officer in accordance with the Deferred Compensation Plan after such stock units vest;

²  Any payments made hereunder shall be less applicable taxes.

2

(4)      For a period of up to 18 months, the Officer’s COBRA premiums (with such payment subject to taxation if required or advisable to avoid violating the nondiscrimination requirements of Code Section 105(h)), if any;

(5)      If Officer is terminated after serving consecutively for six months in a fiscal year, Officer shall be entitled to receive a prorated bonus under any short-term incentive plan in which such Officer participates, at the time such bonus, if any, would otherwise be paid (but in any event no later than the 15th day of the third month following the later of the end of the calendar year or the Corporation’s taxable year in which the Officer’s separation from service occurs or in which the right to such payment otherwise ceases to be subject to a substantial risk of forfeiture for purposes of Code Section 409A);

(6)      To the extent not theretofore paid or provided, the Officer shall be paid or provided with any other amounts or benefits required to be paid or provided or which the Officer is eligible to receive under any plan, contract or agreement of the Corporation or Employer;

(7)      Such career transition services as the Corporation’s Senior Human Resources Officer shall determine is appropriate (if any), provided that payment of such services will only be made to the extent the Officer actually incurs an expense and then only to the extent incurred and paid within the time limit set forth in Treasury Regulation Section 1.409A-1(b)(9)(v)(E). Any such services, to the extent they are not exempt under Treasury Regulation Section 1.409A-1(b)(9)(v)(A) or (D), shall be structured to comply with the requirements of Treasury Regulation Section 1.409A-3(i)(1)(iv) and, if applicable, shall be subject to the six-month delay described in Code Section 409A(a)(2)(B)(i).

(8)      All acts required of the Employer under the Policy may be performed by the Corporation for itself and the Employer, and the costs of the Policy may be equitably apportioned by the Administrator among the Corporation and the other Employers. The Corporation shall be responsible for making payments and providing benefits pursuant to this Policy for Officers employed by the Corporation. Whenever the Employer is permitted or required under the terms of the Policy to do or perform any act, matter or thing, it shall be done and performed by any Officer or employee of the Employer who is thereunto duly authorized by the board of directors of the Employer. Each Employer shall be responsible for making payments and providing benefits pursuant to the Policy on behalf of its Officers or for reimbursing the Corporation for the cost of such payments or benefits, as determined by the Corporation in its sole discretion. In the event the respective Employer fails to make such payment or reimbursement, an Officer’s (or other payee’s) sole recourse shall be against the respective Employer, and not against the Corporation;

(b)       Remedies.  An Officer shall be entitled to recover damages for late or nonpayment of amounts to which the Officer is entitled hereunder. The Officer shall also be entitled to seek specific performance of the obligations and any other applicable equitable or injunctive relief.

(c)       Section 2(a) shall not apply in the event that an Officer’s employment is terminated “for cause.” Except as used in Section 3 of this Policy, “for cause” means that the Corporation, in the case of an Officer employed by the Corporation, or Employer in the case

3

of an Officer employed by an Employer, acting in good faith based upon information then known to it, determines that the Officer has engaged in, committed, or is responsible for (1) serious misconduct, gross negligence, theft, or fraud against the Corporation and/or an Employer; (2) refusal or unwillingness to perform his duties; (3) inappropriate conduct in violation of Corporation’s equal employment opportunity policy; (4) conduct which reflects adversely upon, or making any remarks disparaging of, the Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries; (5) insubordination; (6) any willful act that is likely to have the effect of injuring the reputation, business, or business relationship of the Corporation or its subsidiaries or affiliates; (7) violation of any fiduciary duty; or (8) breach of any duty of loyalty; or (9) any breach of the restrictive covenants contained in Section 2(d) below. Upon termination “for cause,” the Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries shall have no liability to the Officer other than for accrued salary, vacation benefits, and any vested rights the Officer may have under the benefit and compensation plans in which the Officer participates and under the general terms and conditions of the applicable plan.

(d)       Obligations of Officer.

(1)      Release of Claims.  There shall be no obligation to commence the payment of the amounts and benefits described in Section 2(a) until the latter of (1) the delivery by Officer to the Corporation a fully executed comprehensive general release of any and all known or unknown claims that he or she may have against the Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries and a covenant not to sue in the form prescribed by the Administrator, and (2) the expiration of any revocation period set forth in the release. The Corporation shall promptly furnish such release to Officer in connection with the Officer’s separation from service, and such release must be executed by Officer and become effective during the period set forth in the release as a condition to Officer receiving the payments and benefits described in Section 2(a).

(2)      Covenant Not to Compete.  (i) During the period of Officer’s employment with the Corporation or its subsidiaries and for a period of months equal to the Severance Multiple thereafter (the “Restricted Period”), Officer shall not, in any county within the State of California or in any city, county or area outside the State of California within the United States or in the countries of Canada or Mexico, directly or indirectly, whether as partner, employee, consultant, creditor, shareholder, or other similar capacity, promote, participate, or engage in any activity or other business competitive with the Corporation’s business or that of any of its subsidiaries or affiliates, without the prior written consent of the Corporation’s Chief Executive Officer. Notwithstanding the foregoing, Officer may have an interest in any public company engaged in a competitive business so long as Officer does not own more than 2 percent of any class of securities of such company, Officer is not employed by and does not consult with, or becomes a director of, or otherwise engage in any activities for, such competing company.

 a.       The Corporation and its subsidiaries presently conduct their businesses within each county in the State of California and in areas outside California that are located within the United States, and it is anticipated that the Corporation and its subsidiaries will also be conducting business within the countries of Canada and Mexico. Such covenants are

4

necessary and reasonable in order to protect the Corporation and its subsidiaries in the conduct of their businesses. To the extent that the foregoing covenant or any provision of this Section 2(d)(2)a shall be deemed illegal or unenforceable by a court or other tribunal of competent jurisdiction with respect to (i) any geographic area, (ii) any part of the time period covered by such covenant, (iii) any activity or capacity covered by such covenant, or (iv) any other term or provision of such covenant, such determination shall not affect such covenant with respect to any other geographic area, time period, activity or other term or provision covered by or included in such covenant.

(3)      Soliciting Customers and Employees.  During the Restricted Period, Officer shall not, directly or indirectly, solicit or contact any customer or any prospective customer of the Corporation or its subsidiaries or affiliates for any commercial pursuit that could be reasonably construed to be in competition with the Corporation, or induce, or attempt to induce, any employees, agents or consultants of or to the Corporation or any of its subsidiaries or affiliates to do anything from which Officer is restricted by reason of this covenant nor shall Officer, directly or indirectly, offer or aid to others to offer employment to, or interfere or attempt to interfere with any employment, consulting or agency relationship with, any employees, agents or consultants of the Corporation, its subsidiaries and affiliates, who received compensation of $75,000 or more during the preceding six (6) months, to work for any business competitive with any business of the Corporation, its subsidiaries or affiliates.

(4)      Confidentiality.  Officer shall not at any time (including after termination of employment) divulge to others, use to the detriment of the Corporation or its subsidiaries or affiliates, or use in any business competitive with any business of the Corporation or its subsidiaries or affiliates any trade secret, confidential or privileged information obtained during his employment with the Corporation or its subsidiaries or affiliates, without first obtaining the written consent of the Corporation’s Chief Executive Officer. This paragraph covers but is not limited to discoveries, inventions (except as otherwise provided by California law), improvements, and writings, belonging to or relating to the affairs of the Corporation or of any of its subsidiaries or affiliates, or any marketing systems, customer lists or other marketing data. Officer shall, upon termination of employment for any reason, deliver to the Corporation all data, records and communications, and all drawings, models, prototypes or similar visual or conceptual presentations of any type, and all copies or duplicates thereof, relating to all matters contemplated by this paragraph.

(5)      Assistance in Legal Proceedings.  During the Restricted Period, Officer shall, upon reasonable notice from the Corporation, furnish information and proper assistance (including testimony and document production) to the Corporation as may be reasonably required by the Corporation in connection with any legal, administrative or regulatory proceeding in which it or any of its subsidiaries or affiliates is, or may become, a party, or in connection with any filing or similar obligation of the Corporation imposed by any taxing, administrative or regulatory authority having jurisdiction, provided, however, that the Corporation shall pay all reasonable expenses incurred by Officer in complying with this paragraph within 60 days after Officer incurs such expenses.

5

(6)      Remedies.  Upon Officer’s failure to comply with the provisions of this Section 2(d), the Corporation shall have the right to immediately terminate any unpaid amounts or benefits described in Section 2(a) to Officer. In the event of such termination, the Corporation shall have no further obligations under this Policy and shall be entitled to recover damages. In the event of an Officer’s breach or threatened breach of any of the covenants set forth in this Section 2(d), the Corporation shall also be entitled to specific performance by Officer of any such covenant and any other applicable equitable or injunctive relief.

3.       Termination of Employment Following a Change in Control or Potential Change in Control.

(a)       If an Executive Officer’s employment by the Corporation or any subsidiary or successor of the Corporation shall be subject to an Involuntary Termination within the Covered Period, then the provisions of this Section 3 instead of Section 2 shall govern the obligations of the Corporation as to the payments and benefits it shall provide to the Executive Officer. In the event that Executive Officer’s employment with the Corporation or an employing subsidiary is terminated under circumstances which would not entitle Executive Officer to payments under this Section 3, Executive Officer shall only receive such benefits to which he is entitled under Section 2, if any. In no event shall Executive Officer be entitled to receive termination benefits under both this Section 3 and Section 2.

All the terms used in this Section 3 shall have the following meanings:

(1)      “Affiliate” shall mean any entity which owns or controls, is owned or is under common ownership or control with, the Corporation.

(2)      “Cause” shall mean (i) the willful and continued failure of the Executive Officer to perform substantially the Executive Officer’s duties with the Corporation or one of its affiliates (other than any such failure resulting from incapacity due to physical or mental illness), after a written demand for substantial performance is delivered to the Executive Officer by the Board of Directors or the Chief Executive Officer of the Corporation which specifically identifies the manner in which the Board of Directors or Chief Executive Officer believes that the Executive Officer has not substantially performed the Executive Officer’s duties; or (ii) the willful engaging by the Executive Officer in illegal conduct or gross misconduct which is materially demonstrably injurious to the Corporation.

For purposes of the provision, no act or failure to act, on the part of the Executive Officer, shall be considered “willful” unless it is done, or omitted to be done, by the Executive Officer in bad faith or without reasonable belief that the Executive Officer’s action or omission was in the best interests of the Corporation. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board of Directors or upon the instructions of the Chief Executive Officer or a senior officer of the Corporation or based upon the advice of counsel for the Corporation shall be conclusively presumed to be done, or omitted to be done, by the Executive Officer in good faith and in the best interests of the Corporation. The cessation of employment of the Executive Officer shall not be deemed to be for Cause unless and until there shall have been delivered to the Executive Officer a copy of a resolution duly adopted by the affirmative vote of not less than three-quarters of the entire membership of the Board of

6

Directors at a meeting of the Board of Directors called and held for such purpose (after reasonable notice is provided to the Executive Officer and the Executive Officer is given an opportunity, together with counsel, to be heard before the Board of Directors), finding that, in the good faith opinion of the Board of Directors, the Executive Officer is guilty of the conduct described in subparagraph (i) or (ii) above, and specifying the particulars thereof in detail.

(3)      “Change in Control” shall be deemed to have occurred if:

  a.       any “person” (as such term is used in Sections 13(d) and 14(d)(2) of the Securities Exchange Act of 1934, but excluding any benefit plan for employees or any trustee, agent or other fiduciary for any such plan acting in such person’s capacity as such fiduciary), directly or indirectly, becomes the beneficial owner of securities of the Corporation representing 20 percent or more of the combined voting power of the Corporation’s then outstanding securities;

  b.       during any two consecutive years, individuals who at the beginning of such a period constitute the Board of Directors of the Corporation cease for any reason to constitute at least a majority of the Board of Directors of the Corporation, unless the election or the nomination for election by the shareholders of the Corporation, of each new Director was approved by a vote of at least two-thirds (²/₃) of the Directors then still in office who were Directors at the beginning of the period; or

  c.       any consolidation or merger of the Corporation shall have been consummated other than a merger or consolidation which would result in the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent of such surviving entity) at least 70 percent of the Combined Voting Power of the Corporation, such surviving entity or the parent of such surviving entity outstanding immediately after such merger or consolidation; or

  d.       the shareholders of the Corporation shall have approved (i) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Corporation; or (ii) any plan or proposal for the liquidation or dissolution of the Corporation.

(4)      “Change in Control Date” shall mean the date on which a Change in Control occurs.

(5)      “Combined Voting Power” shall mean the combined voting power of the Corporation’s or other relevant entity’s then outstanding voting securities.

(6)      “Covered Period” shall mean the period commencing with the Change in Control Date and terminating two (2) years following said commencement; provided, however, that if a Change in Control occurs and Executive Officer’s employment with the Corporation or the employing subsidiary is subject to an Involuntary Termination before the Change in Control Date but on or after a Potential Change in Control Date, and if it is reasonably demonstrated by the Executive Officer that such termination (i) was at the request of a third party who has taken

7

steps reasonably calculated to effect a Change in Control, or (ii) otherwise arose in connection with or in anticipation of a Change in Control, then the Covered Period shall mean, as applied to Executive Officer, the two-year period beginning on the date immediately before the Potential Change in Control Date.

(7)      “Disability” shall mean the absence of the Executive Officer from the Executive Officer’s duties with the Corporation or the employing subsidiary on a full-time basis for 180 consecutive business days as a result of incapacity due to physical or mental illness which is determined to be total and permanent by a physician selected by the Corporation or its insurers and acceptable to the Executive Officer or the Executive Officer’s legal representative.

(8)      “Executive Officer” shall mean officers of the Corporation at the level of Senior Vice President and above and the principal executive officer of each Employer.

(9)      “Good Reason” shall mean any one or more of the following which takes place within the Covered Period:

  a.       A material diminution in the Executive Officer’s base compensation;

  b.       A material diminution in the Executive Officer’s authority, duties, or responsibilities;

  c.       A material diminution in the authority, duties, or responsibilities of the supervisor to whom the Executive Officer is required to report, including a requirement that the Executive Officer report to a corporate officer or employee instead of reporting directly to the Board of Directors of the Corporation (in the case of an Executive Officer reporting to such Board of Directors);

  d.       A material diminution in the budget over which the Executive Officer retains authority;

  e.       A material change in the geographic location at which the Executive Officer must perform the services; or

  f.       Any other action or inaction that constitutes a material breach by the Corporation of this Policy;

provided, however, that the Executive Officer must provide notice to the Corporation of the existence of the applicable condition described in this Section 3(a)(9) within 90 days of the initial existence of the condition, upon the notice of which the Corporation shall have 30 days during which it may remedy the condition and, if remedied, Good Reason shall not exist.

(10)   “Involuntary Termination” shall mean a termination (i) by the Corporation without Cause, or (ii) by Executive Officer following Good Reason; provided, however, the term “Involuntary Termination” shall not include termination of Executive Officer’s employment due to Executive Officer’s death, Disability, or voluntary retirement.

8

(11)    “Potential Change in Control” shall mean the earliest to occur of (i) the date on which the Corporation executes an agreement or letter of intent, where the consummation of the transaction described therein would result in the occurrence of a Change in Control, (ii) the date on which the Board of Directors approves a transaction or series of transactions, the consummation of which would result in a Change in Control, or (iii) the date on which a tender offer for the Corporation’s voting stock is publicly announced, the completion of which would result in a Change in Control; provided, however, that if such Potential Change in Control terminates by its terms, such transaction shall no longer constitute a Potential Change in Control.

(12)    “Potential Change in Control Date” shall mean the date on which a Potential Change in Control occurs.

(13)    “Reference Salary” shall mean the greater of (i) the annual rate of Executive Officer’s base salary from the Corporation or the employing subsidiary in effect immediately before the date of Executive Officer’s Involuntary Termination, or (ii) the annual rate of Executive Officer’s base salary from the Corporation or the employing subsidiary in effect immediately before the Change in Control Date.

(14)    “Termination Date” shall be the date specified in the written notice of termination of Executive Officer’s employment given by either party in accordance with Section 3(b) of this Policy.

(b)        Notice of Termination.  During the Covered Period, in the event that the Corporation (including an employing subsidiary) or Executive Officer terminates Executive Officer’s employment with the Corporation or Employer, the party terminating employment shall give written notice of termination to the other party, specifying the Termination Date and the specific termination provision in this Section 3 that is relied upon, if any, and setting forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Executive Officer’s employment under the provision so indicated. The Termination Date shall be determined as follows: (i) if Executive Officer’s employment is terminated for Disability, thirty (30) days after a Notice of Termination is given (provided that Executive Officer shall not have returned to the full-time performance of Executive Officer’s duties during such 30-day period); (ii) if Executive Officer’s employment is terminated by the Corporation in an Involuntary Termination, thirty days after the date the Notice of Termination is received by Executive Officer (provided that the Corporation may provide Officer with pay in lieu of notice, which shall be paid in a lump sum together with the payment described in Section 3(c)(1) below); and (iii) if Executive Officer’s employment is terminated by the Corporation for Cause (as defined in this Section 3), the date specified in the Notice of Termination, provided, that the events or circumstances cited by the Board of Directors as constituting Cause are not cured by Executive Officer during any cure period that may be offered by the Board of Directors. The Date of Termination for a resignation of employment other than for Good Reason shall be the date set forth in the applicable notice, which shall be no earlier than ten (10) days after the date such notice is received by the Corporation, unless waived by the Corporation.

During the Covered Period, a notice of termination given by Executive Officer for Good Reason

9

shall be given within 90 days after occurrence of the event on which Executive Officer bases his notice of termination and shall provide a Termination Date of thirty (30) days after the notice of termination is given to the Corporation (provided that the Corporation may provide Officer with pay in lieu of notice, which shall be paid in a lump sum together with the payment described in Section 3(c)(1) below).

(c)        Corporation’s Obligations.  If Executive Officer separates from service due to an Involuntary Termination within the Covered Period, then the Corporation shall provide Executive Officer the following benefits:

(1)      The Corporation shall pay to the Executive Officer a lump sum in cash within thirty (30) days after the Executive Officer’s separation from service:

  a.       the sum of (1) any earned but unpaid base salary through the Termination Date at the rate in effect at the time of the notice of termination to the extent not theretofore paid; (2) the Executive Officer’s target bonus under the Short-Term Incentive Plan of the Corporation, an Affiliate, or a predecessor, for the fiscal year in which the Termination Date occurs (the “Target Bonus”); and (3) any accrued but unpaid vacation pay, in each case to the extent not theretofore paid; and

  b.       the amount equal to the product of (1) three and (2) the sum of (x) the Reference Salary and (y) the Target Bonus.

(2)      The vesting of any benefits conditioned upon continued future employment shall accelerate in full upon the Executive Officer’s separation from service and shall be delivered or paid in accordance with the terms thereof.

(3)      Remedies.  The Executive Officer shall be entitled to recover damages for late or nonpayment of amounts which the Corporation is obligated to pay hereunder. The Executive Officer shall also be entitled to seek specific performance of the Corporation’s obligations and any other applicable equitable or injunctive relief.

(d)        Adjustment for Excise Taxes.

  (1)  “Best-Net Provision”

Subject to Section 3(d)(2) below, in the event that the payments and other benefits provided for in this Policy or otherwise payable to Executive Officer (i) constitute “parachute payments” within the meaning of Section 280G of the Internal Revenue Code of 1986, as amended (the “Code”) and (ii) would be subject to the excise tax imposed by Section 4999 of the Code, then Executive Officer’s payments and benefits under this Policy or otherwise payable to Executive Officer outside of this Policy shall be either delivered in full (without the Corporation paying any portion of such excise tax), or delivered as to 2.99 times of Executive’s base amount (within the meaning of Section 280G of the Code) so as to result in no portion of such payments and benefits being subject to such excise tax, whichever of the foregoing amounts, taking into account the applicable federal, state and local income taxes and such excise tax, results in the receipt by Executive Officer on an after-tax basis of the greatest amount of payments and

10

benefits, notwithstanding that all or some portion of such payments and benefits may subject to such excise tax. Unless the Corporation and Executive Officer otherwise agree in writing, any determination required under this Section 3(d)(1) shall be made in writing by Deloitte & Touche (the “Accounting Firm”), whose determination shall be conclusive and binding upon Executive Officer and the Corporation for all purposes. For purposes of making the calculations required by this Section 3(d)(1), the Accounting Firm may make reasonable assumptions and approximations concerning applicable taxes and may rely on reasonable, good faith interpretations concerning the application of Section 280G and 4999 of the Code. The Corporation and Executive Officer shall furnish to the Accounting Firm such information and documents as the Accounting Firm may reasonably request in order to make a determination under this Section 3(d)(1).

Any reduction in payments and/or benefits shall occur in the following order as reasonably determined by the Accounting Firm: (1) reduction of cash payments, (2) reduction of non-cash/non-equity-based payments or benefits, and (3) reduction of vesting acceleration of equity-based awards; provided, however, that any non-taxable payments or benefits shall be reduced last in accordance with the same categorical ordering rule. In the event items described in (1) or (2) are to be reduced, reduction shall occur in reverse chronological order such that the payment or benefit owed on the latest date following the occurrence of the event triggering the excise tax will be the first payment to be reduced (with reductions made pro-rata in the event payments are owed at the same time). In the event that acceleration of vesting of equity-based awards is to be reduced, such acceleration of vesting shall be cancelled in a manner such as to obtain the best economic benefit for the officer (with reductions made pro-rata if economically equivalent), as determined by the Accounting Firm

(2) Grandfathered Tax Restoration Payment

With respect to officers that were Executive Officers as of February 15, 2011, if any portion of the payments to the Executive Officer under this Section 3 or under any other plan, program, or arrangement maintained by the Corporation (a “Payment”) would be subject to the excise tax levied under the Code, or any interest or penalties are incurred by Executive Officer with respect to such excise tax (such excise tax together with such interest and penalties are referred to herein as the “Excise Tax”), then the Corporation shall make an additional payment to Executive Officer (a “Tax Restoration Payment”) in an amount such that after payment by the Executive Officer of all taxes (including any interest or penalties imposed with respect to such taxes), including, without limitation, any income taxes (and any interest and penalties imposed with respect thereto) and Excise Tax imposed upon the Tax Restoration Payment, the Executive Officer retains an amount of the Tax Restoration Payment equal to the Excise Tax imposed upon the Payments. The payment of a Tax Restoration Payment under this Section 3 shall not be conditioned upon the Executive Officer’s termination of employment.

All determinations and calculations required to be made under this Section 3(d) shall be made by Deloitte & Touche (the “Accounting Firm”), which shall provide its determination (the “Determination”), together with detailed supporting calculations regarding the amount of any Tax Restoration Payment and any other relevant matter, both to the Corporation and the Executive Officer within five (5) days of the termination of the Executive Officer’s employment,

11

if applicable, or such earlier time as is requested by the Corporation or the Executive Officer (if the Executive Officer reasonably believes that any of the Payments may be subject to Excise Tax). If the Accounting Firm determines that no Excise Tax is payable by the Executive Officer, it shall furnish the Executive Officer with a written statement that such Accounting Firm has concluded that no Excise Tax is payable (including the reasons therefor) and that the Executive Officer has substantial authority not to report any Excise Tax on the Executive Officer’s federal income tax return. If a Tax Restoration Payment is determined to be payable, it shall be paid to the Executive Officer within five (5) days after the Determination is delivered to the Corporation or the Executive Officer. Any determination by the Accounting Firm shall be binding upon the Corporation and the Executive Officer, absent manifest error.

As a result of uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Accounting Firm hereunder, it is possible that Tax Restoration Payments not made by the Corporation should have been made (“Underpayment”) or that Tax Restoration Payments will have been made by the Corporation which should not have been made (“Overpayment”). In either such event, the Accounting Firm shall determine the amount of the Underpayment or Overpayment that has occurred. In the case of an Underpayment, the amount of such Underpayment shall be promptly paid by the Corporation to or for the benefit of the Executive Officer. In the case of an Overpayment, the Executive Officer shall, at the direction and expense of the Corporation, take such steps as are reasonably necessary (including the filing of returns and claims for refund), follow reasonable instructions from, and procedures established by, the Corporation, and otherwise reasonably cooperate with the Corporation to correct such Overpayment, provided, however, that (i) the Executive Officer shall in no event be obligated to return to the Corporation an amount greater than the net after-tax portion of the Overpayment that the Executive Officer has retained or has recovered as a refund from the applicable taxing authorities, and (ii) this provision shall be interpreted in a manner consistent with the intent of the Tax Restoration Payment paragraph above, which is to make the Executive Officer whole, on an after-tax basis, from the application of Excise Tax, it being understood that the correction of an Overpayment may result in the Executive Officer’s repaying to the Corporation an amount that is less than the Overpayment.

All Tax Restoration Payments shall be paid no later than the calendar year next following the calendar year in which the Executive Officer remits the related taxes.

This Section 3(d)(2) will be effective until the third anniversary of the Corporation notifying individuals who are Executive Officers as of February 15, 2011 of the elimination of this Section 3(d)(2) and the application of the potential benefit reductions described in Section 3(d)(1). After such time, such Executive Officers no longer will be eligible for a Tax Restoration Payment pursuant to this Section 3(d)(2) and will instead be subject to Section 3(d)(1).

4.        Administration.  The Policy shall be administered by the Senior Human Resources Officer of the Corporation (“Administrator”), who shall have the authority to interpret the Policy and make and revise such rules as may be reasonably necessary to administer the Policy. The Administrator shall have the duty and responsibility of maintaining records, making the requisite calculations, securing Officer releases, and disbursing payments hereunder. The Administrator’s

12

interpretations, determinations, rules, and calculations shall be final and binding on all persons and parties concerned.

5.        No Mitigation.  Payment of the amounts and benefits under Section2(a) and Section 3 (except as otherwise provided in Section 2(a)(5)) shall not be subject to offset, counterclaim, recoupment, defense or other claim, right or action which the Corporation or an Employer may have and shall not be subject to a requirement that Officer mitigate or attempt to mitigate damages resulting from Officer’s termination of employment.

6.        Amendment and Termination.  The Corporation, acting through its Compensation Committee, reserves the right to amend or terminate the Policy at any time; provided, however, that any amendment which would reduce the aggregate level of benefits, or terminate the Policy, shall not become effective prior to the third anniversary of the Corporation giving notice to Officers of such amendment or termination.

7.        Successors.  The Corporation will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets of the Corporation expressly to assume and to agree to perform its obligations under this Policy in the same manner and to the same extent that the Corporation would be required to perform such obligations if no such succession had taken place; provided, however, that no such assumption shall relieve the Corporation of its obligations hereunder. As used herein, the “Corporation” shall mean the Corporation as hereinbefore defined and any successor to its business and/or assets as aforesaid which assumes and agrees to perform its obligations by operation or law or otherwise.

This Policy shall inure to the benefit of and be binding upon the Officer (and Officer’s personal representatives and heirs), Corporation and its successors and assigns, and any such successor or assignee shall be deemed substituted for the Corporation under the terms of this Policy for all purposes. As used herein, “successor” and “assignee” shall include any person, firm, corporation or other business entity which at any time, whether by purchase, merger or otherwise, directly or indirectly acquires the stock of the Corporation or to which the Corporation assigns this Policy by operation of law or otherwise. If Officer should die while any amount would still be payable to Officer hereunder if Officer had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with this Policy to Officer’s devisee, legatee or other designee, or if there is no such designee, to Officer’s estate.

8.        Nonassignability of Benefits.  The payments under this Policy or the right to receive future payments under this Policy may not be anticipated, alienated, pledged, encumbered, or subject to any charge or legal process, and if any attempt is made to do so, or a person eligible for payments becomes bankrupt, the payments under the Policy of the person affected may be terminated by the Administrator who, in his or her sole discretion, may cause the same to be held if applied for the benefit of one or more of the dependents of such person or make any other disposition of such benefits that he or she deems appropriate.

9.        Nonguarantee of Employment.  Officers covered by the Policy are at-will employees, and nothing contained in this Policy shall be construed as a contract of employment between the Officer and the Corporation (or, where applicable, a subsidiary or affiliate of the

13

Corporation), or as a right of the Officer to continued employment, or to remain as an Officer, or as a limitation on the right of the Corporation (or a subsidiary or affiliate of the Corporation) to discharge Officer at any time, with or without cause.

10.      Benefits Unfunded and Unsecured.  The payments under this Policy are unfunded, and the interest under this Policy of any Officer and such Officer’s right to receive payments under this Policy shall be an unsecured claim against the general assets of the Corporation.

11.      Applicable Law.  All questions pertaining to the construction, validity, and effect of the Policy shall be determined in accordance with the laws of the United States and, to the extent not preempted by such laws, by the laws of the state of California.

12.      Arbitration.  With the exception of any request for specific performance, injunctive or other equitable relief, any dispute or controversy of any kind arising out of or related to this Policy, Officer’s employment with the Corporation (or with the employing subsidiary), the termination thereof or any claims for benefits shall be resolved exclusively by final and binding arbitration in accordance with the Commercial Arbitration Rules of the American Arbitration Association then in effect. Provided, however, that in making their determination, the arbitrators shall be limited to accepting the position of the Officer or the position of the Corporation, as the case may be. The only claims not covered by this Section 12 are claims for benefits under workers’ compensation or unemployment insurance laws; such claims will be resolved under those laws. The place of arbitration shall be San Francisco, California. Parties may be represented by legal counsel at the arbitration but must bear their own fees for such representation. The prevailing party in any dispute or controversy covered by this Section 12, or with respect to any request for specific performance, injunctive or other equitable relief, shall be entitled to recover, in addition to any other available remedies specified in this Policy, all litigation expenses and costs, including any arbitrator or administrative or filing fees and reasonable attorneys’ fees. Such expenses, costs and fees, if payable to Officer, shall be paid within 60 days after they are incurred. Both the Officer and the Corporation specifically waive any right to a jury trial on any dispute or controversy covered by this Section 12. Judgment may be entered on the arbitrators’ award in any court of competent jurisdiction.

13.      Reimbursements and In-Kind Benefits.  Notwithstanding any other provision of this Policy, all reimbursements and in-kind benefits provided under this Policy shall be made or provided in accordance with the requirements of Code Section 409A, including, where applicable, the requirement that (i) the amount of expenses eligible for reimbursement and the provision of benefits in kind during a calendar year shall not affect the expenses eligible for reimbursement or the provision of in-kind benefits in any other calendar year; (ii) the reimbursement for an eligible expense will be made on or before the last day of the calendar year following the calendar year in which the expense is incurred (or by such earlier time set forth in this Policy); (iii) the right to reimbursement or right to in-kind benefit is not subject to liquidation or exchange for another benefit; and (iv) each reimbursement payment or provision of in-kind benefit shall be one of a series of separate payments (and each shall be construed as a separate identified payment) for purposes of Code Section 409A.

14

14.      Separate Payments.  Each payment and benefit under this Policy shall be a “separate payment” for purposes of Code Section 409A.

15

APPENDIX A

PARTICIPATING EMPLOYERS

PG&E Corporation

Pacific Gas and Electric Company

PG&E Corporation Support Services, Inc.

EX-10.6

Exhibit 10.6

PG&E CORPORATION

2012 OFFICER SEVERANCE POLICY

(Effective as of March 1, 2012)

1.        Purpose.  This is the controlling and definitive statement of the Officer Severance Policy of PG&E Corporation (“Policy”). Since Officers are employed at the will of PG&E Corporation (“Corporation”) or a participating employer (“Employer”), their employment may be terminated at any time, with or without cause. A list of Employers is attached hereto as Appendix A. The Policy provides Officers of the Corporation and Employers in Officer Compensation Bands I through V (“Officers”) with severance benefits if their employment is terminated, and the Officer is not eligible for severance benefits under the predecessor PG&E Corporation Officer Severance Policy (the “Predecessor Policy”), which was first adopted effective November 1, 1998.¹ Severance benefits for officers not covered by this Policy (or the Predecessor Policy) will be provided under policies or programs developed by the appropriate lines of business in consultation with and with the approval by the Senior Human Resources Officer of the Corporation. For the avoidance of doubt, the revisions made to this Policy relating to Code Section 409A (defined below), apply to all Officers including those that may be covered under prior provisions of the Policy as required by Section 6 hereof.

The purpose of the Policy is to attract and retain senior management by defining terms and conditions for severance benefits, to provide severance benefits that are part of a competitive total compensation package, to provide consistent treatment for all terminated officers, and to minimize potential litigation costs associated with Officer termination of employment.

2.        Termination of Employment Not Following a Change in Control or Potential Change in Control.

(a)      Corporation or Employer’s Obligations.  If the Corporation or an Employer exercises its right to terminate an Officer’s employment without cause and such termination does not entitle Officer to payments under Section 3, the Officer shall be given thirty (30) days’ advance written notice or pay in lieu thereof (which shall be paid in a lump sum together with the payment described in Section 2(a)(1) below). Except as provided in Section 2(b) below, in consideration of the Officer’s agreement to the obligations described in Section 2(d) below and

¹  Severance benefits for Officers who are currently covered by an employment agreement will continue to be provided solely under such agreements until their expiration at which time this Policy will become effective for such Officers. Any Officer’s waiver of benefits under this Policy shall take precedence over the terms of this Policy. If an employee becomes a covered Officer under this Policy as a result of a promotion, if such Officer was then covered by a severance arrangement subject to Section 409A of the Internal Revenue Code of 1986 (“Code Section 409A”), the severance benefits under this Policy provided to such person shall comply with the time and form of payment provisions of such prior severance arrangement, to the extent required by Code Section 409A.

Officers subject to the Predecessor Policy as of February 29, 2012 will continue to be subject to the terms of that Prececessor Policy until three years afer receiving notice of the adoption of the this Policy and its terms, to the extent that becoming subject to this Policy would reduce such officers’ aggregate level of benefits, as per Section 6 of the Predecessor Policy.

to the arbitration provisions described in Section 12 below, the following payments and benefits shall also be provided to Officer following Officer’s separation from service (within the meaning of Code Section 409A):²

(1)      A lump sum severance payment equal to: ¹/₁₂ (the sum of the Officer’s annual base compensation and the Officer’s Short-Term Incentive Plan target award at the time of his or her termination) times twelve (“Severance Multiple”). Annual base compensation shall mean the Officer’s monthly base pay for the month in which the Officer is given notice of termination, multiplied by 12. The payment described in this Section 2(a)(1) shall be made in a single lump sum as soon as practicable following the date the release of claims described in Section 2(d)(1) becomes effective, provided that payment shall in no event be made later than the 15th day of the third month following the later of the end of the calendar year or the Corporation’s taxable year in which the Officer’s separation from service occurs.

(2)      Except as otherwise set forth in the applicable award agreement or as otherwise required by applicable law, the equity-based incentive awards granted to Officer under the Corporation’s Long-Term Incentive Program which have not yet vested as of the date of termination will continue to vest over a period of months equal to the Severance Multiple after the date of termination as if the Officer had remained employed for such period. Except as otherwise set forth in the applicable award agreement, for vested stock options as of the date of termination, the Officer shall have the right to exercise such stock options at any time within their respective terms or within five years after termination, whichever is shorter. Except as otherwise set forth in the applicable award agreement, for stock options that vest during a period of months equal to the Severance Multiple, the Officer shall have the right to exercise such options at any time within one year after termination, subject to the term of the options. Except as otherwise set forth in the applicable award agreement, any unvested equity-based incentive awards remaining at the end of such period shall be forfeited;

(3)      For Officers in Officer Bands I, II or III, two thirds of the unvested Company stock units in the Officer’s account in the Corporation’s Deferred Compensation Plan for Officers which were awarded in connection with the Executive Stock Ownership Program requirements (“SISOPs”) shall vest upon the Officer’s termination, and one third shall be forfeited. For Officers in Officer Bands IV and V, one third of any unvested SISOPs shall vest upon the Officer’s termination, and two thirds shall be forfeited. Unvested stock units attributable to SISOPs which become vested under this provision shall be distributed to Officer in accordance with the Deferred Compensation Plan after such stock units vest;

(4)      Officer shall be entitled to receive a lump sum cash payment equal to the estimated value of 18 months’of COBRA premiums for the Officer, based on the Officer’s benefit levels at the time of termination (with such payment subject to taxation under applicable law);

²  Any payments made hereunder shall be less applicable taxes.

2

(5)      To the extent not theretofore paid or provided, the Officer shall be paid or provided with any other amounts or benefits required to be paid or provided or which the Officer is eligible to receive under any plan, contract or agreement of the Corporation or Employer;

(6)      Such career transition services as the Corporation’s Senior Human Resources Officer shall determine is appropriate (if any), provided that payment of such services will only be made to the extent the Officer actually incurs an expense and then only to the extent incurred and paid within the time limit set forth in Treasury Regulation Section 1.409A-1(b)(9)(v)(E). Any such services, to the extent they are not exempt under Treasury Regulation Section 1.409A-1(b)(9)(v)(A) or (D), shall be structured to comply with the requirements of Treasuary Regulation Section 1.409A-3(i)(1)(iv) and, if applicable, shall be subject to the six-month delay described in Code Section 409A(a)(2)(B)(i).

(7)      All acts required of the Employer under the Policy may be performed by the Corporation for itself and the Employer, and the costs of the Policy may be equitably apportioned by the Administrator among the Corporation and the other Employers. The Corporation shall be responsible for making payments and providing benefits pursuant to this Policy for Officers employed by the Corporation. Whenever the Employer is permitted or required under the terms of the Policy to do or perform any act, matter or thing, it shall be done and performed by any Officer or employee of the Employer who is thereunto duly authorized by the board of directors of the Employer. Each Employer shall be responsible for making payments and providing benefits pursuant to the Policy on behalf of its Officers or for reimbursing the Corporation for the cost of such payments or benefits, as determined by the Corporation in its sole discretion. In the event the respective Employer fails to make such payment or reimbursement, an Officer’s (or other payee’s) sole recourse shall be against the respective Employer, and not against the Corporation;

(b)       Remedies.  An Officer shall be entitled to recover damages for late or nonpayment of amounts to which the Officer is entitled hereunder. The Officer shall also be entitled to seek specific performance of the obligations and any other applicable equitable or injunctive relief.

(c)       Section 2(a) shall not apply in the event that an Officer’s employment is terminated “for cause.” Except as used in Section 3 of this Policy, “for cause” means that the Corporation, in the case of an Officer employed by the Corporation, or Employer in the case of an Officer employed by an Employer, acting in good faith based upon information then known to it, determines that the Officer has engaged in, committed, or is responsible for (1) serious misconduct, gross negligence, theft, or fraud against the Corporation and/or an Employer; (2) refusal or unwillingness to perform his duties; (3) inappropriate conduct in violation of Corporation’s equal employment opportunity policy; (4) conduct which reflects adversely upon, or making any remarks disparaging of, the Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries; (5) insubordination; (6) any willful act that is likely to have the effect of injuring the reputation, business, or business relationship of the Corporation or its subsidiaries or affiliates; (7) violation of any fiduciary duty; or (8) breach of any duty of loyalty; or (9) any breach of the restrictive covenants contained in Section 2(d) below. Upon termination “for cause,” the Corporation, its Board of Directors, Officers, or employees, or its

3

affiliates or subsidiaries shall have no liability to the Officer other than for accrued salary, vacation benefits, and any vested rights the Officer may have under the benefit and compensation plans in which the Officer participates and under the general terms and conditions of the applicable plan.

(d)        Obligations of Officer.

(1)      Release of Claims.  There shall be no obligation to commence the payment of the amounts and benefits described in Section 2(a) until the latter of (1) the delivery by Officer to the Corporation a fully executed comprehensive general release of any and all known or unknown claims that he or she may have against the Corporation, its Board of Directors, Officers, or employees, or its affiliates or subsidiaries and a covenant not to sue in the form prescribed by the Administrator, and (2) the expiration of any revocation period set forth in the release. The Corporation shall promptly furnish such release to Officer in connection with the Officer’s separation from service, and such release must be executed by Officer and become effective during the period set forth in the release as a condition to Officer receiving the payments and benefits described in Section 2(a).

(2)      Covenant Not to Compete.  (i) During the period of Officer’s employment with the Corporation or its subsidiaries and for a period of twelve (12) months thereafter (the “Restricted Period”), Officer shall not, in any county within the State of California or in any city, county or area outside the State of California within the United States or in the countries of Canada or Mexico, directly or indirectly, whether as partner, employee, consultant, creditor, shareholder, or other similar capacity, promote, participate, or engage in any activity or other business competitive with the Corporation’s business or that of any of its subsidiaries or affiliates, without the prior written consent of the Corporation’s Chief Executive Officer. Notwithstanding the foregoing, Officer may have an interest in any public company engaged in a competitive business so long as Officer does not own more than 2 percent of any class of securities of such company, Officer is not employed by and does not consult with, or becomes a director of, or otherwise engage in any activities for, such competing company.

  a.        The Corporation and its subsidiaries presently conduct their businesses within each county in the State of California and in areas outside California that are located within the United States, and it is anticipated that the Corporation and its subsidiaries will also be conducting business within the countries of Canada and Mexico. Such covenants are necessary and reasonable in order to protect the Corporation and its subsidiaries in the conduct of their businesses. To the extent that the foregoing covenant or any provision of this Section 2(d)(2)a shall be deemed illegal or unenforceable by a court or other tribunal of competent jurisdiction with respect to (i) any geographic area, (ii) any part of the time period covered by such covenant, (iii) any activity or capacity covered by such covenant, or (iv) any other term or provision of such covenant, such determination shall not affect such covenant with respect to any other geographic area, time period, activity or other term or provision covered by or included in such covenant.

(3)      Soliciting Customers and Employees.  During the Restricted Period, Officer shall not, directly or indirectly, solicit or contact any customer or any prospective customer of the Corporation or its subsidiaries or affiliates for any commercial pursuit that could

4

be reasonably construed to be in competition with the Corporation, or induce, or attempt to induce, any employees, agents or consultants of or to the Corporation or any of its subsidiaries or affiliates to do anything from which Officer is restricted by reason of this covenant nor shall Officer, directly or indirectly, offer or aid to others to offer employment to, or interfere or attempt to interfere with any employment, consulting or agency relationship with, any employees, agents or consultants of the Corporation, its subsidiaries and affiliates, who received compensation of $75,000 or more during the preceding six (6) months, to work for any business competitive with any business of the Corporation, its subsidiaries or affiliates.

(4)      Confidentiality.  Officer shall not at any time (including after termination of employment) divulge to others, use to the detriment of the Corporation or its subsidiaries or affiliates, or use in any business competitive with any business of the Corporation or its subsidiaries or affiliates any trade secret, confidential or privileged information obtained during his employment with the Corporation or its subsidiaries or affiliates, without first obtaining the written consent of the Corporation’s Chief Executive Officer. This paragraph covers but is not limited to discoveries, inventions (except as otherwise provided by California law), improvements, and writings, belonging to or relating to the affairs of the Corporation or of any of its subsidiaries or affiliates, or any marketing systems, customer lists or other marketing data. Officer shall, upon termination of employment for any reason, deliver to the Corporation all data, records and communications, and all drawings, models, prototypes or similar visual or conceptual presentations of any type, and all copies or duplicates thereof, relating to all matters contemplated by this paragraph.

(5)      Assistance in Legal Proceedings.  During the Restricted Period, Officer shall, upon reasonable notice from the Corporation, furnish information and proper assistance (including testimony and document production) to the Corporation as may be reasonably required by the Corporation in connection with any legal, administrative or regulatory proceeding in which it or any of its subsidiaries or affiliates is, or may become, a party, or in connection with any filing or similar obligation of the Corporation imposed by any taxing, administrative or regulatory authority having jurisdiction, provided, however, that the Corporation shall pay all reasonable expenses incurred by Officer in complying with this paragraph within 60 days after Officer incurs such expenses.

(6)      Remedies.  Upon Officer’s failure to comply with the provisions of this Section 2(d), the Corporation shall have the right to immediately terminate any unpaid amounts or benefits described in Section 2(a) to Officer. In the event of such termination, the Corporation shall have no further obligations under this Policy and shall be entitled to recover damages. In the event of an Officer’s breach or threatened breach of any of the covenants set forth in this Section 2(d), the Corporation shall also be entitled to specific performance by Officer of any such covenant and any other applicable equitable or injunctive relief.

3.        Termination of Employment Following a Change in Control or Potential Change in Control.

(a)      If an Executive Officer’s employment by the Corporation or any subsidiary or successor of the Corporation shall be subject to an Involuntary Termination within the Covered Period, then the provisions of this Section 3 instead of Section 2 shall govern the obligations of

5

the Corporation as to the payments and benefits it shall provide to the Executive Officer. In the event that Executive Officer’s employment with the Corporation or an employing subsidiary is terminated under circumstances which would not entitle Executive Officer to payments under this Section 3, Executive Officer shall only receive such benefits to which he is entitled under Section 2, if any. In no event shall Executive Officer be entitled to receive termination benefits under both this Section 3 and Section 2.

All the terms used in this Section 3 shall have the following meanings:

(1)      “Affiliate” shall mean any entity which owns or controls, is owned or is under common ownership or control with, the Corporation.

(2)      “Cause” shall mean (i) the willful and continued failure of the Executive Officer to perform substantially the Executive Officer’s duties with the Corporation or one of its affiliates (other than any such failure resulting from incapacity due to physical or mental illness), after a written demand for substantial performance is delivered to the Executive Officer by the Board of Directors or the Chief Executive Officer of the Corporation which specifically identifies the manner in which the Board of Directors or Chief Executive Officer believes that the Executive Officer has not substantially performed the Executive Officer’s duties; or (ii) the willful engaging by the Executive Officer in illegal conduct or gross misconduct which is materially demonstrably injurious to the Corporation.

For purposes of the provision, no act or failure to act, on the part of the Executive Officer, shall be considered “willful” unless it is done, or omitted to be done, by the Executive Officer in bad faith or without reasonable belief that the Executive Officer’s action or omission was in the best interests of the Corporation. Any act, or failure to act, based upon authority given pursuant to a resolution duly adopted by the Board of Directors or upon the instructions of the Chief Executive Officer or a senior officer of the Corporation or based upon the advice of counsel for the Corporation shall be conclusively presumed to be done, or omitted to be done, by the Executive Officer in good faith and in the best interests of the Corporation. The cessation of employment of the Executive Officer shall not be deemed to be for Cause unless and until there shall have been delivered to the Executive Officer a copy of a resolution duly adopted by the affirmative vote of not less than three-quarters of the entire membership of the Board of Directors at a meeting of the Board of Directors called and held for such purpose (after reasonable notice is provided to the Executive Officer and the Executive Officer is given an opportunity, together with counsel, to be heard before the Board of Directors), finding that, in the good faith opinion of the Board of Directors, the Executive Officer is guilty of the conduct described in subparagraph (i) or (ii) above, and specifying the particulars thereof in detail.

(3)      “Change in Control” shall be deemed to have occurred if:

  a.        any “person” (as such term is used in Sections 13(d) and 14(d)(2) of the Securities Exchange Act of 1934, but excluding any benefit plan for employees or any trustee, agent or other fiduciary for any such plan acting in such person’s capacity as such fiduciary), directly or indirectly, becomes the beneficial owner of securities of the Corporation representing 20 percent or more of the combined voting power of the Corporation’s then outstanding securities;

6

  b.        during any two consecutive years, individuals who at the beginning of such a period constitute the Board of Directors of the Corporation cease for any reason to constitute at least a majority of the Board of Directors of the Corporation, unless the election or the nomination for election by the shareholders of the Corporation, of each new Director was approved by a vote of at least two-thirds (²/ ₃) of the Directors then still in office who were Directors at the beginning of the period; or

  c.        any consolidation or merger of the Corporation shall have been consummated other than a merger or consolidation which would result in the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent of such surviving entity) at least 70 percent of the Combined Voting Power of the Corporation, such surviving entity or the parent of such surviving entity outstanding immediately after such merger or consolidation; or

  d.        the shareholders of the Corporation shall have approved (i) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of the Corporation; or (ii) any plan or proposal for the liquidation or dissolution of the Corporation.

(4)      “Change in Control Date” shall mean the date on which a Change in Control occurs.

(5)      “Combined Voting Power” shall mean the combined voting power of the Corporation’s or other relevant entity’s then outstanding voting securities.

(6)      “Covered Period” shall mean the period commencing with the Change in Control Date and terminating two (2) years following said commencement; provided, however, that if a Change in Control occurs and Executive Officer’s employment with the Corporation or the employing subsidiary is subject to an Involuntary Termination before the Change in Control Date but on or after a Potential Change in Control Date, and if it is reasonably demonstrated by the Executive Officer that such termination (i) was at the request of a third party who has taken steps reasonably calculated to effect a Change in Control, or (ii) otherwise arose in connection with or in anticipation of a Change in Control, then the Covered Period shall mean, as applied to Executive Officer, the two-year period beginning on the date immediately before the Potential Change in Control Date.

(7)      “Disability” shall mean the absence of the Executive Officer from the Executive Officer’s duties with the Corporation or the employing subsidiary on a full-time basis for 180 consecutive business days as a result of incapacity due to physical or mental illness which is determined to be total and permanent by a physician selected by the Corporation or its insurers and acceptable to the Executive Officer or the Executive Officer’s legal representative.

(8)      “Executive Officer” shall mean officers in Officer Compensation Bands I through II.

7

(9)      “Good Reason” shall mean any one or more of the following which takes place within the Covered Period:

  a.        A material diminution in the Executive Officer’s base compensation;

  b.        A material diminution in the Executive Officer’s authority, duties, or responsibilities;

  c.        A material diminution in the authority, duties, or responsibilities of the supervisor to whom the Executive Officer is required to report, including a requirement that the Executive Officer report to a corporate officer or employee instead of reporting directly to the Board of Directors of the Corporation (in the case of an Executive Officer reporting to such Board of Directors);

  d.        A material diminution in the budget over which the Executive Officer retains authority;

  e.        A material change in the geographic location at which the Executive Officer must perform the services; or

  f.        Any other action or inaction that constitutes a material breach by the Corporation of this Policy;

provided, however, that the Executive Officer must provide notice to the Corporation of the existence of the applicable condition described in this Section 3(a)(9) within 90 days of the initial existence of the condition, upon the notice of which the Corporation shall have 30 days during which it may remedy the condition and, if remedied, Good Reason shall not exist.

(10)      “Involuntary Termination” shall mean a termination (i) by the Corporation without Cause, or (ii) by Executive Officer following Good Reason; provided, however, the term “Involuntary Termination” shall not include termination of Executive Officer’s employment due to Executive Officer’s death, Disability, or voluntary retirement.

(11)      “Potential Change in Control” shall mean the earliest to occur of (i) the date on which the Corporation executes an agreement or letter of intent, where the consummation of the transaction described therein would result in the occurrence of a Change in Control, (ii) the date on which the Board of Directors approves a transaction or series of transactions, the consummation of which would result in a Change in Control, or (iii) the date on which a tender offer for the Corporation’s voting stock is publicly announced, the completion of which would result in a Change in Control; provided, however, that if such Potential Change in Control terminates by its terms, such transaction shall no longer constitute a Potential Change in Control.

(12)      “Potential Change in Control Date” shall mean the date on which a Potential Change in Control occurs.

8

(13)     “Reference Salary” shall mean the greater of (i) the annual rate of Executive Officer’s base salary from the Corporation or the employing subsidiary in effect immediately before the date of Executive Officer’s Involuntary Termination, or (ii) the annual rate of Executive Officer’s base salary from the Corporation or the employing subsidiary in effect immediately before the Change in Control Date.

(14)     “Termination Date” shall be the date specified in the written notice of termination of Executive Officer’s employment given by either party in accordance with Section 3(b) of this Policy.

(b)       Notice of Termination.  During the Covered Period, in the event that the Corporation (including an employing subsidiary) or Executive Officer terminates Executive Officer’s employment with the Corporation or Employer, the party terminating employment shall give written notice of termination to the other party, specifying the Termination Date and the specific termination provision in this Section 3 that is relied upon, if any, and setting forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of Executive Officer’s employment under the provision so indicated. The Termination Date shall be determined as follows: (i) if Executive Officer’s employment is terminated for Disability, thirty (30) days after a Notice of Termination is given (provided that Executive Officer shall not have returned to the full-time performance of Executive Officer’s duties during such 30-day period); (ii) if Executive Officer’s employment is terminated by the Corporation in an Involuntary Termination, thirty days after the date the Notice of Termination is received by Executive Officer (provided that the Corporation may provide Officer with pay in lieu of notice, which shall be paid in a lump sum together with the payment described in Section 3(c)(1) below); and (iii) if Executive Officer’s employment is terminated by the Corporation for Cause (as defined in this Section 3), the date specified in the Notice of Termination, provided, that the events or circumstances cited by the Board of Directors as constituting Cause are not cured by Executive Officer during any cure period that may be offered by the Board of Directors. The Date of Termination for a resignation of employment other than for Good Reason shall be the date set forth in the applicable notice, which shall be no earlier than ten (10) days after the date such notice is received by the Corporation, unless waived by the Corporation.

During the Covered Period, a notice of termination given by Executive Officer for Good Reason shall be given within 90 days after occurrence of the event on which Executive Officer bases his notice of termination and shall provide a Termination Date of thirty (30) days after the notice of termination is given to the Corporation (provided that the Corporation may provide Officer with pay in lieu of notice, which shall be paid in a lump sum together with the payment described in Section 3(c)(1) below).

(c)       Corporation’s Obligations.  If Executive Officer separates from service due to an Involuntary Termination within the Covered Period, then the Corporation shall provide Executive Officer the following benefits:

(1)       The Corporation shall pay to the Executive Officer a lump sum in cash within thirty (30) days after the Executive Officer’s separation from service:

9

  a.        the sum of (1) any earned but unpaid base salary through the Termination Date at the rate in effect at the time of the notice of termination to the extent not theretofore paid; (2) the Executive Officer’s pro-rated target bonus under the Short-Term Incentive Plan of the Corporation, an Affiliate, or a predecessor, for the fiscal year in which the Termination Date occurs (the “Target Bonus”); and (3) any accrued but unpaid vacation pay, in each case to the extent not theretofore paid;

  b.      the amount equal to the product of (1) two and (2) the sum of (x) the Reference Salary and (y) the Target Bonus; and

  c.      a lump sum cash payment equal to the estimated value of 18 months’of COBRA premiums for the Officer, based on the Officer’s beneit levels at the time of termination (with such payment subject to taxation under applicable law), if any;

(2)      Executive Officer shall be eligible to receive such career transition services as the Corporation’s Senior Human Resources Officer shall determine is appropriate (if any), provided that payment of such services will only be made to the extent the Officer actually incurs an expense and then only to the extent incurred and paid within the time limit set forth in Treasury Regulation Section 1.409A-1(b)(9)(v)(E). Any such services, to the extent they are not exempt under Treasury Regulation Section 1.409A-1(b)(9)(v)(A) or (D), shall be structured to comply with the requirements of Treasuary Regulation Section 1.409A-3(i)(1)(iv) and, if applicable, shall be subject to the six-month delay described in Code Section 409A(a)(2)(B)(i).

(3)      Remedies.  The Executive Officer shall be entitled to recover damages for late or nonpayment of amounts which the Corporation is obligated to pay hereunder. The Executive Officer shall also be entitled to seek specific performance of the Corporation’s obligations and any other applicable equitable or injunctive relief.

(d)       Adjustment for Excise Taxes.

  (1)  “Best-Net Provision”

Subject to Section 3(d)(2) below, in the event that the payments and other benefits provided for in this Policy or otherwise payable to Executive Officer (i) constitute “parachute payments” within the meaning of Section 280G of the Internal Revenue Code of 1986, as amended (the “Code”) and (ii) would be subject to the excise tax imposed by Section 4999 of the Code, then Executive Officer’s payments and benefits under this Policy or otherwise payable to Executive Officer outside of this Policy shall be either delivered in full (without the Corporation paying any portion of such excise tax), or delivered as to 2.99 times of Executive’s base amount (within the meaning of Section 280G of the Code) so as to result in no portion of such payments and benefits being subject to such excise tax, whichever of the foregoing amounts, taking into account the applicable federal, state and local income taxes and such excise tax, results in the receipt by Executive Officer on an after-tax basis of the greatest amount of payments and benefits, notwithstanding that all or some portion of such payments and benefits may subject to such excise tax. Unless the Corporation and Executive Officer otherwise agree in writing, any determination required under this Section 3(d)(1) shall be made in writing by Deloitte & Touche (the “Accounting Firm”), whose determination shall be conclusive and binding upon Executive

10

Officer and the Corporation for all purposes. For purposes of making the calculations required by this Section 3(d)(1), the Accounting Firm may make reasonable assumptions and approximations concerning applicable taxes and may rely on reasonable, good faith interpretations concerning the application of Section 280G and 4999 of the Code. The Corporation and Executive Officer shall furnish to the Accounting Firm such information and documents as the Accounting Firm may reasonably request in order to make a determination under this Section 3(d)(1).

Any reduction in payments and/or benefits shall occur in the following order as reasonably determined by the Accounting Firm: (1) reduction of cash payments, (2) reduction of non-cash/non-equity-based payments or benefits, and (3) reduction of vesting acceleration of equity-based awards; provided, however, that any non-taxable payments or benefits shall be reduced last in accordance with the same categorical ordering rule. In the event items described in (1) or (2) are to be reduced, reduction shall occur in reverse chronological order such that the payment or benefit owed on the latest date following the occurrence of the event triggering the excise tax will be the first payment to be reduced (with reductions made pro-rata in the event payments are owed at the same time). In the event that acceleration of vesting of equity-based awards is to be reduced, such acceleration of vesting shall be cancelled in a manner such as to obtain the best economic benefit for the officer (with reductions made pro-rata if economically equivalent), as determined by the Accounting Firm

4.       Administration.  The Policy shall be administered by the Senior Human Resources Officer of the Corporation (“Administrator”), who shall have the authority to interpret the Policy and make and revise such rules as may be reasonably necessary to administer the Policy. The Administrator shall have the duty and responsibility of maintaining records, making the requisite calculations, securing Officer releases, and disbursing payments hereunder. The Administrator’s interpretations, determinations, rules, and calculations shall be final and binding on all persons and parties concerned.

5.       No Mitigation.  Payment of the amounts and benefits under Section2(a) and Section 3 (except as otherwise provided in Section 2(a)(5)) shall not be subject to offset, counterclaim, recoupment, defense or other claim, right or action which the Corporation or an Employer may have and shall not be subject to a requirement that Officer mitigate or attempt to mitigate damages resulting from Officer’s termination of employment.

6.       Amendment and Termination.  The Corporation, acting through its Compensation Committee, reserves the right to amend or terminate the Policy at any time; provided, however, that any amendment which would reduce the aggregate level of benefits, or terminate the Policy, shall not become effective prior to the third anniversary of the Corporation giving notice to Officers of such amendment or termination.

7.       Successors.  The Corporation will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets of the Corporation expressly to assume and to agree to perform its obligations under this Policy in the same manner and to the same extent that the Corporation would be

11

required to perform such obligations if no such succession had taken place; provided, however, that no such assumption shall relieve the Corporation of its obligations hereunder. As used herein, the “Corporation” shall mean the Corporation as hereinbefore defined and any successor to its business and/or assets as aforesaid which assumes and agrees to perform its obligations by operation or law or otherwise.

This Policy shall inure to the benefit of and be binding upon the Officer (and Officer’s personal representatives and heirs), Corporation and its successors and assigns, and any such successor or assignee shall be deemed substituted for the Corporation under the terms of this Policy for all purposes. As used herein, “successor” and “assignee” shall include any person, firm, corporation or other business entity which at any time, whether by purchase, merger or otherwise, directly or indirectly acquires the stock of the Corporation or to which the Corporation assigns this Policy by operation of law or otherwise. If Officer should die while any amount would still be payable to Officer hereunder if Officer had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with this Policy to Officer’s devisee, legatee or other designee, or if there is no such designee, to Officer’s estate.

8.        Nonassignability of Benefits.  The payments under this Policy or the right to receive future payments under this Policy may not be anticipated, alienated, pledged, encumbered, or subject to any charge or legal process, and if any attempt is made to do so, or a person eligible for payments becomes bankrupt, the payments under the Policy of the person affected may be terminated by the Administrator who, in his or her sole discretion, may cause the same to be held if applied for the benefit of one or more of the dependents of such person or make any other disposition of such benefits that he or she deems appropriate.

9.        Nonguarantee of Employment.  Officers covered by the Policy are at-will employees, and nothing contained in this Policy shall be construed as a contract of employment between the Officer and the Corporation (or, where applicable, a subsidiary or affiliate of the Corporation), or as a right of the Officer to continued employment, or to remain as an Officer, or as a limitation on the right of the Corporation (or a subsidiary or affiliate of the Corporation) to discharge Officer at any time, with or without cause.

10.        Benefits Unfunded and Unsecured.  The payments under this Policy are unfunded, and the interest under this Policy of any Officer and such Officer’s right to receive payments under this Policy shall be an unsecured claim against the general assets of the Corporation.

11.        Applicable Law.  All questions pertaining to the construction, validity, and effect of the Policy shall be determined in accordance with the laws of the United States and, to the extent not preempted by such laws, by the laws of the state of California.

12.        Arbitration.  With the exception of any request for specific performance, injunctive or other equitable relief, any dispute or controversy of any kind arising out of or related to this Policy, Officer’s employment with the Corporation (or with the employing subsidiary), the termination thereof or any claims for benefits shall be resolved exclusively by final and binding arbitration in accordance with the Commercial Arbitration Rules of the American Arbitration Association then in effect. Provided, however, that in making their determination, the arbitrators shall be limited to accepting the position of the Officer or the position of the Corporation, as the

12

case may be. The only claims not covered by this Section 12 are claims for benefits under workers’ compensation or unemployment insurance laws; such claims will be resolved under those laws. The place of arbitration shall be San Francisco, California. Parties may be represented by legal counsel at the arbitration but must bear their own fees for such representation. The prevailing party in any dispute or controversy covered by this Section 12, or with respect to any request for specific performance, injunctive or other equitable relief, shall be entitled to recover, in addition to any other available remedies specified in this Policy, all litigation expenses and costs, including any arbitrator or administrative or filing fees and reasonable attorneys’ fees. Such expenses, costs and fees, if payable to Officer, shall be paid within 60 days after they are incurred. Both the Officer and the Corporation specifically waive any right to a jury trial on any dispute or controversy covered by this Section 12. Judgment may be entered on the arbitrators’ award in any court of competent jurisdiction.

13.      Reimbursements and In-Kind Benefits.  Notwithstanding any other provision of this Policy, all reimbursements and in-kind benefits provided under this Policy shall be made or provided in accordance with the requirements of Code Section 409A, including, where applicable, the requirement that (i) the amount of expenses eligible for reimbursement and the provision of benefits in kind during a calendar year shall not affect the expenses eligible for reimbursement or the provision of in-kind benefits in any other calendar year; (ii) the reimbursement for an eligible expense will be made on or before the last day of the calendar year following the calendar year in which the expense is incurred (or by such earlier time set forth in this Policy); (iii) the right to reimbursement or right to in-kind benefit is not subject to liquidation or exchange for another benefit; and (iv) each reimbursement payment or provision of in-kind benefit shall be one of a series of separate payments (and each shall be construed as a separate identified payment) for purposes of Code Section 409A.

14.      Separate Payments.  Each payment and benefit under this Policy shall be a “separate payment” for purposes of Code Section 409A.

13

APPENDIX A

PARTICIPATING EMPLOYERS

PG&E Corporation

Pacific Gas and Electric Company

PG&E Corporation Support Services, Inc.

EX-10.7

Exhibit 10.7

POSTRETIREMENT LIFE INSURANCE PLAN

OF

THE PACIFIC GAS AND ELECTRIC COMPANY

 This is the controlling and definitive statement of the Pacific Gas and Electric Company Postretirement Life Insurance Plan – Plan #542 (“PLAN”¹), as amended on April 1, 2007 (to reflect eligibility of affiliate employees for participation in the Retirement Plan), amended effective as of January 1, 2009 (in conformance with Section 409A of the Internal Revenue Code), amended effective March 15, 2012 (with respect to benefits provided to weekly paid non-bargaining unit employees) and amended effective May 15, 2012 with respect to certain tax matters. The PLAN is for the benefit of all eligible employees of Pacific Gas and Electric Company (“COMPANY”) and such other companies, affiliates, subsidiaries, or associations as the BOARD OF DIRECTORS may designate from time to time. The PLAN was first adopted in substantially its current form by the BOARD OF DIRECTORS in 1978 and has since been amended from time to time. Except as expressly stated by any amendment to this PLAN, benefits of eligible employees who retire, terminate from employment, or cease to be an eligible employee prior to the effective date of any amendment shall not be affected by any such amendment. The Company intends to amend, restate, and maintain the Plan pursuant to this written instrument and in accordance with the requirements of the Employee Retirement Income Security Act (ERISA) of 1974.

ARTICLE I

DEFINITIONS

 1.01    Actual Retirement Date shall mean the earlier of:    (a) the date as of which payment of a pension under the COMPANY’s Retirement Plan commences, or (b) if an employee is age 55 or older, the day following the date on which an employee’s SERVICE ends.

¹  Words in all capitals are defined in Article I.

 1.02    Bargaining Unit Employee shall mean an employee of the COMPANY or a designated company, affiliate, subsidiary, or association, who is a member of a collective bargaining unit.

 1.03    Beneficiary shall mean the individual or individuals or intervivos trust or trusts that an eligible employee designates to receive benefits under Section 3.02. Such designation must be made on a Designation of Beneficiary form provided by, and filed with, the PLAN ADMINISTRATOR.

 1.04    Board or Board of Directors shall mean the BOARD OF DIRECTORS of the COMPANY or, when appropriate, any committee of the BOARD which has been delegated the authority to take action with respect to the PLAN.

 1.05    Company shall mean the Pacific Gas and Electric Company, a California corporation.

 1.06    Compensation shall mean an employee’s monthly base salary rate. For an employee on an authorized leave of absence, COMPENSATION also includes the monthly salary rate applicable to such employee, whether or not the employee was paid while on such leave of absence. For an employee receiving benefits under the COMPANY’s Long-Term Disability Plan or the PG&E Corporation Disability Plan, COMPENSATION is the employee’s monthly base salary rate for the 12 months preceding the employee’s last day worked.

 1.07    Group Life Insurance Plan shall mean the Pacific Gas and Electric Company GROUP LIFE INSURANCE PLAN, as amended January 1, 2008, and as may thereafter be amended, from time to time.

 1.08    Management Employee shall mean an employee of the COMPANY or of a designated company, affiliate, subsidiary, or association, who is employed in a monthly paid position and who is not in a collective bargaining unit. Effective April 1, 2007, Management Employee shall include any such employee of PG&E Corporation, PG&E Corporation Support Services, Inc., and PG&E Corporation Support Services, II, Inc.

 1.09    Normal Retirement Date shall mean the first of the month following an employee’s 65th birthday.

 1.10    Participating Employer shall mean the COMPANY, PG&E Corporation, PG&E Corporation Support Services, Inc., and PG&E Corporation Support Services II, Inc., or such other company, affiliate, subsidiary, or association as may be designated by the BOARD or its delegates.

 1.11    Plan shall mean the Pacific Gas and Electric Company Postretirement Life Insurance Plan, amended and restated from time to time, as set forth herein.

 1.12    Plan Administrator shall mean the Employee Benefit Committee or such individual or individuals as that Committee may appoint to handle the day-to-day affairs of the PLAN.

 1.13    Service shall mean “credited service” as that term is defined in the Retirement Plan or, if the Compensation Committee of the Board of Directors of PG&E Corporation has granted an adjusted service date for an eligible employee, “credited service” as calculated from such adjusted service date. Additionally, for purposes of this PLAN, SERVICE shall include service with a PARTICIPATING EMPLOYER.

 1.14    Weekly-Paid Non-Bargaining Unit Employee shall mean an employee of the COMPANY or a PARTICIPATING EMPLOYER, who is paid on a weekly basis and is not a member of a collective bargaining unit.

ARTICLE II

ELIGIBILITY AND BENEFIT LEVELS

 2.01    The PLAN provides for different levels of benefits, depending upon the employment status, hire date, and/or promotion date of an eligible employee. Except as expressly provided under the terms of the PLAN, an eligible employee is entitled to receive only one level of benefits. A schedule setting forth the different benefit levels, and eligibility criteria is contained in Attachment A.

  All life insurance benefit proceeds will be paid in a single lump sum to the BENEFICIARY at the time of the the eligible employee’s death.

 2.02    Terminated Employees.    Anything in the PLAN to the contrary notwithstanding, an employee whose employment with the COMPANY or a PARTICIPATING EMPLOYER

terminates prior to attaining Normal or Early Retirement Date, as those terms are defined under the COMPANY’s Retirement Plan, shall not be an eligible employee entitled to benefits under the PLAN.

 2.03    Demotions.    An eligible employee who (i) is eligible to retire under the terms of the COMPANY’s Retirement Plan, (ii) has met all of the criteria for a specified level of benefit, and is subsequently demoted for reasons other than for just cause, will nonetheless be entitled to receive the level of benefits to which he was entitled prior to demotion. COMPENSATION for purposes of determining the amount of benefits to which a demoted employee is entitled shall be based on the larger of (i) the last 12 months of COMPENSATION prior to the date of demotion, or (ii) the last 12 months of COMPENSATION prior to ACTUAL RETIREMENT DATE. An eligible employee who is demoted for just cause, however, automatically ceases to be entitled to the level of benefits to which he was entitled prior to demotion. Eligibility for a specific level of benefits and the amount of any benefit will depend on employment status and COMPENSATION received subsequent to demotion.

ARTICLE III

ADMINISTRATIVE PROVISIONS

 3.01    Elections.

  (a)     Prior to ACTUAL RETIREMENT DATE, an eligible employee shall make any applicable elections as to optional benefit forms appropriate to the level of benefit to which he is entitled. Elections made prior to an eligible employee’s ACTUAL RETIREMENT DATE are irrevocable.

  (b)     On or prior to December 31, 2008, certain eligible employees, as designated by the COMPANY in its sole discretion, were allowed to elect a cash payment in lieu of life insurance benefits under the PLAN. Any cash payment to an eligible employee as a result of this election shall be payable upon the eligible employee’s “separation from service” (within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended (“Section 409A”)), and in no event later than the later of (i) the 15th day of the 3rd month following the eligible employee’s SEPARATION FROM SERVICE or December 31 of the calendar year in which the eligible employee

separates from service, subject to applicable tax withholding.

If pursuant to section 3.01(b) an employee who is eligible for Level Four, Level Five, or Level Six benefits elects a cash payment in lieu of a life insurance benefit, then in determining the present value of a cash benefit elected pursuant to 3.01(b), the PLAN ADMINISTRATOR shall use the appropriate mortality factors contained in the Retirement Plan for single life annuities and the 90-day Treasury Bill interest rate in effect as of the eligible employee’s ACTUAL RETIREMENT DATE. If provided for in a participant’s election form, the eligible employee also shall receive, at the same time as such cash payment, an additional payment equal to the federal and state income taxes attributable to such payment, except that, as of May 15, 2012, no such payment will be provided to an individual who is or was prior to retirement an executive officer named in the compensation tables of any of the COMPANY’s or PG&E Corporation’s proxy statements that have been filed with the Securities and Exchange Commission prior to the date of payment of benefits under this PLAN.

  3.02    Designation of Beneficiary.

 An eligible employee shall designate a BENEFICIARY by filling out and submitting a Designation of Beneficiary electronic or paper form provided by the PLAN ADMINISTRATOR. A BENEFICIARY may be changed at any time by submitting a Change of Beneficiary form available from the PLAN ADMINISTRATOR.

The designation of a BENEFICIARY becomes effective only when received by the PLAN ADMINISTRATOR. If there is no designation of a BENEFICIARY on file with the PLAN ADMINISTRATOR, the BENEFICIARY shall be in accordance with the last Designation of Beneficiary form filed by the eligible employee under the COMPANY’s GROUP LIFE INSURANCE PLAN. If the designated BENEFICIARY is not living at the time of the eligible employee’s death, the PLAN ADMINISTRATOR shall determine the individual, individuals, or estate entitled to receive benefits by application of the Preference of Beneficiary clause contained in the COMPANY’s GROUP LIFE INSURANCE PLAN.

  3.03    Operation and Administration.

  (a)     COMPANY’s Powers and Duties.    The COMPANY, acting through its BOARD OF DIRECTORS, reserves to itself the exclusive power to amend, suspend, or terminate the PLAN, as provided below, and to appoint and remove from time to time:

  (i)       the individuals comprising the Employee Benefit Committee;

  (i)       the individuals comprising the Employee Benefits Appeals Committee; and

  (iii)      the employers whose employees may participate in the PLAN.

 All powers and duties not reserved to the COMPANY are delegated to the PG&E Corporation Employee Benefit Committee (the “EBC”) as Plan Administrator and to the Employee Benefit Appeals Committee (the “EBAC”) with respect to review and adjudication of Participant claims and appeals. Action of either committee shall be by vote of a majority of the members of the committee at a meeting, or in writing without a meeting, and evidenced by the signature of any member who is so authorized by the committee.

 The COMPANY indemnifies each member of each committee against any personal liability or expense arising out of any action or inaction of the committee or of any member of the committee or of such individual, except that due to his or her own willful misconduct.

  (b)   Employee Benefit Committee.    The Employee Benefit Committee, appointed by the Board of Directors of PG&E Corporation to serve at its pleasure, is the PLAN ADMINISTRATOR of the PLAN and is responsible for the overall administration of the PLAN.

 The PLAN ADMINISTRATOR has the sole power and duty to establish and from time to time revise such rules and regulations as may be necessary to administer the PLAN in a non-discriminatory manner for the exclusive benefit of employees and all other persons entitled to benefits under the PLAN.

 The PLAN ADMINISTRATOR shall establish, carry out, and revise from time to time the funding policy for the PLAN. The PLAN ADMINISTRATOR shall have the authority to allocate among its members or to delegate to any other

person any fiduciary responsibility with respect to the PLAN. The PLAN ADMINISTRATOR may appoint and delegate to one or more individuals the power and duty to handle the day-to-day administration, including financial administration, of the PLAN. Such individuals need not be members of the Committee and shall serve at the pleasure of the Committee.

 The PLAN ADMINISTRATOR shall also maintain such records and make such rules, computations, interpretations, and decisions as may be necessary or desirable for the proper administration of the PLAN. The PLAN ADMINISTRATOR shall maintain for inspection by eligible employees copies of the PLAN, the latest annual report, PLAN description and summary description, and any amendments or changes in any of these documents. On written request, eligible employees may obtain from the PLAN ADMINISTRATOR a copy of any of these documents at a cost established by the PLAN ADMINISTRATOR from time to time.

The PLAN ADMINISTRATOR may employ counsel and agents, as well as clerical, actuarial, and accounting services as it may require in carrying out the provisions of the PLAN or complying with the requirements of ERISA.

 3.04    Eligibility Claims and Appeals Procedures.

 If a claim which relates to an eligible employee’s length of SERVICE, status, or membership in the PLAN is denied in whole or in part, the PLAN ADMINISTRATOR shall furnish to the claimant a written notice setting forth:

  (a)   specific reason(s) for the denial;

  (b)   the PLAN provision(s) on which the denial is based;

  (c)   a description of any material or information, if any, necessary for the claimant to perfect the claim, and an explanation of why such material or information is necessary; and

  (d)   information concerning the steps to be taken if claimant wishes to submit a claim for review.

 The above information shall be furnished to the claimant within 60 days after the claim is received by the PLAN ADMINISTRATOR.

 If a claimant is not satisfied with the written notice described in the preceding paragraph, such claimant may request a full and fair review by the EBAC by so notifying the PLAN ADMINISTRATOR in writing within 90 days after receiving such notice. If a review is requested, the claimant shall also be entitled, upon written request, to review pertinent documents and to submit issues and comments in writing. The EBAC shall furnish the claimant with a written final decision within 60 days after receipt of the request for review, unless due to special circumstances, an extension is required. If an extension is required, a written extension notice will be furnished to the claimant before the end of the initial 60-day period. The extension may not exceed 60 days. The extension notice will indicate the special circumstances requiring an extension of time and the date by which the EBAC expects to render a decision. If the EBAC denies the appeal, the claimant will be provided a written notice setting forth:

  (a)   specific reason(s) for the denial;

  (b)   the PLAN provision(s) on which the denial is based; and

  (c)   a statement of the claimant’s right to bring an action under section 502(a) of ERISA.

 3.05    Amendment Procedures.

 The COMPANY reserves the right to modify or discontinue the PLAN at any time. Any modification or termination of the PLAN shall not affect benefits payable to BENEFICIARIES prior to the date of modification or termination.

 3.06    Code Section 409A.

  (a)    Notwithstanding anything to the contrary set forth herein, to the extent (i) any compensation or benefits to which an eligible employee becomes entitled hereunder, in connection with the eligible employee’s SEPARATION FROM SERVICE constitute deferred compensation subject to (and not exempt from) Section 409A and the

regulations and other guidance promulgated thereunder and (ii) the eligible employee is deemed at the time of such separation to be a “specified employee” under Section 409A, then such compensation or benefits shall not be made or commence until the earlier of (A) six (6)-months after such separation or (B) the date of the eligible employee’s death following such separation; provided, however, that such delay shall only be effected to the extent required to avoid adverse tax treatment to the eligible employee under Section 409A(a)(1) in the absence of such delay. Upon the expiration of the applicable delay period, any compensation or benefits which would have otherwise been paid during that period (whether in a single sum or in installments) in the absence of this paragraph shall be paid to the eligible employee or the eligible employee’s BENEFICIARY in one lump sum on the first business day immediately following the end of such delay period.

  (b)    Each payment and benefit under the PLAN shall be treated as a “separate payment” for purposes of SECTION 409A.

ATTACHMENT A

SCHEDULE OF POSTRETIREMENT LIFE

INSURANCE PLAN BENEFITS

I. Level One Benefits.    Level One benefits are available to MANAGEMENT EMPLOYEES and WEEKLY-PAID NON-BARGAINING UNIT EMPLOYEES who retire with fewer than 15 years of SERVICE, and BARGAINING UNIT EMPLOYEES. Such a MANAGEMENT EMPLOYEE, BARGAINING UNIT EMPLOYEE, or a WEEKLY-PAID NON-BARGAINING UNIT EMPLOYEE who retires under the terms of the Retirement Plan becomes an eligible employee entitled to receive a life insurance benefit with coverage equal to $8,000. Level One benefits for BARGAINING UNIT EMPLOYEES are the same as, rather than in addition to, the Postretirement Life Insurance provided under the GROUP LIFE INSURNACE PLAN. The Level One life insurance benefit is effective on the 32nd day following the eligible employee’s ACTUAL RETIREMENT DATE. No benefit will be payable under this PLAN if an eligible employee should die prior to the 32nd day following ACTUAL RETIREMENT DATE.

II. Level Two Benefits.    Level Two benefits are available to MANAGEMENT EMPLOYEES and WEEKLY-PAID NON-BARGAINING UNIT EMPLOYEES who are hired or promoted into a non-bargaining-unit position after December 31, 1985, and who retire under the terms of Part 1 of the COMPANY’s Retirement Plan with at least 15 years of SERVICE.

A MANAGEMENT EMPLOYEE OR WEEKLY-PAID NON-BARGAINING UNIT EMPLOYEE who is eligible for Level Two benefits becomes an eligible employee entitled to receive a life insurance benefit with coverage equal to the lesser of: a) the last 12 months of COMPENSATION received prior to the eligible employee’s ACTUAL RETIREMENT DATE, or b) $50,000. The Level Two life insurance is effective on the 32nd day following the eligible employee’s ACTUAL RETIREMENT DATE. No benefit will be payable under this PLAN if an eligible employee should die prior to the 32nd day following ACTUAL RETIREMENT DATE.

A MANAGEMENT EMPLOYEE who was eligible for the Level Two Life Insurance Benefit, but who was reclassified

into a WEEKLY PAID NON-BARGAINING UNIT position on or after January 1, 2011 and who retired before March 15, 2012 shall continue to be eligible for the Level Two benefit notwithstanding such reclassification.

III. Level Three Benefits.    Level Three benefits are available to MANAGEMENT EMPLOYEES and WEEKLY PAID NON-BARGAINING UNIT EMPLOYEES who:

a) were hired or promoted into a MANAGEMENT position before January 1, 1986;

b) retire under the terms of Part 1 of the Retirement Plan in a position which is classified as MANAGEMENT or WEEKLY PAID NON-BARGAINING UNIT; and

c) who have at least 15 years of SERVICE.

A MANAGEMENT EMPLOYEE OR WEEKLY PAID NON-BARGAINING UNIT who is eligible for Level Three benefits becomes an eligible employee entitled to receive a life insurance benefit with coverage equal to the last 12 months of COMPENSATION received prior to the eligible employee’s ACTUAL RETIREMENT DATE. The Level Three life insurance benefit is effective on the 32nd day following the eligible employee’s ACTUAL RETIREMENT DATE. No benefit will be payable under this PLAN if an eligible employee should die prior to the 32nd day following ACTUAL RETIREMENT DATE.

In the alternative, by filing an appropriate election form with the PLAN ADMINISTRATOR at least 30 days’ prior to the eligible employee’s ACTUAL RETIREMENT DATE, an eligible employee may irrevocably elect to receive a Level Two benefit in lieu of a Level Three benefit, provided, however, that the Level Two benefit is less than the Level Three benefit.

A MANAGEMENT EMPLOYEE who was eligible for the Level Three life insurance benefit, but who was reclassified into a WEEKLY PAID, non-bargaining unit position on or after January 1, 2011 and who retired before March 15, 2012 shall continue to be eligible for the Level Three benefit notwithstanding such reclassification.

IV.    Level Four Benefits.    Level Four benefits are available to MANAGEMENT EMPLOYEES who:

a) were hired or promoted into a management position before January 1, 1986;

b) who retire under the terms of the Retirement Plan in a position which is classified as a Level 12(or equivalent level) or above; and

c) who have at least 15 years of SERVICE.

A MANAGEMENT EMPLOYEE who is eligible for Level Four benefits is entitled to a life insurance benefit with coverage equal to the last 12 months of COMPENSATION received prior to the eligible employee’s ACTUAL RETIREMENT DATE. The Level Four benefit is effective on the 32nd day following the eligible employee’s ACTUAL RETIREMENT DATE. No benefit will be payable under this PLAN if an eligible employee should die prior to the 32nd day following ACTUAL RETIREMENT DATE.

Prior to January 1, 2008, MANAGEMENT EMPLOYEES elgibile for Level Four benefits may have been offered an opportunity to select alternative benefits, pursuant to 3.01(b) of the PLAN, in which case those elected benefits will apply.

V. Level Five Benefits.    Level Five benefits are available for MANAGEMENT EMPLOYEES who were hired prior to January 1, 1986, and who retire under the terms of the Retirement Plan as an Officer of the COMPANY at the vice presidential level or above, or as the corporate secretary, controller, or the treasurer, and who have at least 15 years of SERVICE. An eligible employee who is eligible for Level Five benefits is entitled to receive a life insurance benefit equal to the last 12 months of COMPENSATION received prior to the eligible employee’s ACTUAL RETIREMENT DATE. The Level Five benefit is effective on the 32nd day following the eligible employee’s ACTUAL RETIREMENT DATE. No benefit will be payable under this PLAN if an eligible employee should die prior to the 32nd day following ACTUAL RETIREMENT DATE.

Prior to January 1, 2008, MANAGEMENT EMPLOYEES elgibile for Level Five benefits may have been offered an opportunity to select alternative

benefits, pursuant to 3.01(b) of the PLAN, in which case those elected benefits will apply.

  VI. Level Six Benefits.    Level Six benefits are available for MANAGEMENT EMPLOYEES who were hired after December 31, 1985, and who retire under the terms of the Retirement Plan as an Officer of the COMPANY at the vice presidential level or above, or as the corporate secretary, controller, or the treasurer, and who have at least 15 years of SERVICE. An eligible employee who is eligible for Level Six benefits is entitled to receive the Level Five benefits, up to a maximum amount of life insurance coverage of $50,000.

Prior to January 1, 2008, MANAGEMENT EMPLOYEES elgibile for Level Six benefits may have been offered an opportunity to select alternative benefits, pursuant to 3.01(b) of the PLAN, in which case those elected benefits will apply.

EX-12.1

EXHIBIT 12.1

PACIFIC GAS AND ELECTRIC COMPANY

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	Three Months
	Ended
	March 31,		Year ended December 31,
	2012		2011		2010		2009		2008		2007
Earnings:
Net income		$ 231		$ 845		$ 1,121		$ 1,250		$ 1,199		$ 1,024
Income taxes provision		113		480		574		482		488		571
Net fixed charges		213		880		799		817		860		889
Total earnings		$ 557		$ 2,205		$ 2,494		$ 2,549		$ 2,547		$ 2,484
Fixed charges:
Interest on short-term borrowings and long-term debt, net		$ 197		$ 824		$ 731		$ 754		$ 794		$ 834
Interest on capital leases		4		16		18		19		22		23
AFUDC debt		12		40		50		44		44		32
Total fixed charges		$ 213		$ 880		$ 799		$ 817		$ 860		$ 889
Ratios of earnings to fixed charges		2.62		2.51		3.12		3.12		2.96		2.79

Note:

For the purpose of computing Pacific Gas and Electric Company’s ratios of earnings to fixed charges, “earnings” represent net income adjusted for the income or loss from equity investees of less than 100% owned affiliates, equity in undistributed income or losses of less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). “Fixed charges” include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest on capital leases, AFUDC debt, and earnings required to cover the preferred stock dividend requirements. Fixed charges exclude interest on tax liabilities.

EX-12.2

EXHIBIT 12.2

PACIFIC GAS AND ELECTRIC COMPANY

COMPUTATION OF RATIOS OF EARNINGS TO COMBINED

FIXED CHARGES AND PREFERRED STOCK DIVIDENDS

	Three Months
	Ended
	March 31,		Year ended December 31,
Earnings:	2012		2011		2010		2009		2008		2007
Net income		$ 231		$ 845		$ 1,121		$ 1,250		$ 1,199		$ 1,024
Income taxes provision		113		480		574		482		488		571
Fixed charges		213		880		799		817		860		889
Total earnings		$ 557		$ 2,205		$ 2,494		$ 2,549		$ 2,547		$ 2,484
Fixed charges:
Interest on short-term borrowings and long-term debt, net		$ 197		$ 824		$ 731		$ 754		$ 794		$ 834
Interest on capital leases		4		16		18		19		22		23
AFUDC debt		12		40		50		44		44		32
Total fixed charges		$ 213		$ 880		$ 799		$ 817		$ 860		$ 889
Preferred stock dividends:
Tax deductible dividends		$ 2		$ 9		$ 9		$ 9		$ 9		$ 9
Pre-tax earnings required to cover non-tax deductible preferred stock dividend requirements		1		8		7		7		7		8
Total preferred stock dividends		$ 3		$ 17		$ 16		$ 16		$ 16		$ 17
Total combined fixed charges and preferred stock dividends		$ 216		$ 897		$ 815		$ 833		$ 876		$ 906
Ratios of earnings to combined fixed charges and preferred stock dividends		2.58		2.46		3.06		3.06		2.91		2.74

Note:

For the purpose of computing Pacific Gas and Electric Company’s ratios of earnings to combined fixed charges and preferred stock dividends, “earnings” represent net income adjusted for the income or loss from equity investees of less than 100% owned affiliates, equity in undistributed income or losses of less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized interest). “Fixed charges” include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest on capital leases, AFUDC debt, and earnings required to cover the preferred stock dividend requirements. “Preferred stock dividends” represent tax deductible dividends and pre-tax earnings that are required to pay the dividends on outstanding preferred securities. Fixed charges exclude interest on tax liabilities.

EX-12.3

EXHIBIT 12.3

PG&E CORPORATION

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

	Three Months
	Ended
	March 31,			Year Ended December 31,
	2012			2011			2010			2009			2008			2007
Earnings:
Incoming from continuing operations		$ 236			$ 858			$ 1,113			$ 1,234			$ 1,198			$ 1,020
Income taxes provision		104			440			547			460			425			539
Fixed charges		221			919			850			877			907			937
Pre-tax earnings required to cover the preferred stock dividend of consolidated subsidiaries		(3	)		(17	)		(16	)		(16	)		(16	)		(17)
Total earnings		$ 558			$ 2,200			$ 2,494			$ 2,555			$ 2,514			$ 2,479
Fixed charges:
Interest and amortization of premiums, discounts and capitalized expenses related to short-term borrowings and long-term debt, net		$ 202			$ 846			$ 766			$ 798			$ 825			$ 865
Interest on capital leases		4			16			18			19			22			23
AFUDC debt		12			40			50			44			44			32
Pre-tax earnings required to cover the preferred stock dividend of consolidated subsidiaries		3			17			16			16			16			17
Total fixed charges		$ 221			$ 919			$ 850			$ 877			$ 907			$ 937
Ratios of earnings to fixed charges		2.52			2.39			2.93			2.91			2.77			2.65

Note:

For the purpose of computing PG&E Corporation's ratios of earnings to fixed charges, “earnings” represent income from continuing operations adjusted for income taxes, fixed charges (excluding capitalized interest), and pre-tax earnings required to cover the preferred stock dividend of consolidated subsidiaries. “Fixed charges” include interest on long-term debt and short-term borrowings (including a representative portion of rental expense), amortization of bond premium, discount and expense, interest on capital leases, AFUDC debt, and earnings required to cover preferred stock dividends of consolidated subsidiaries. Fixed charges exclude interest on tax liabilities.

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Anthony F. Earley, Jr., certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended March 31, 2012 of PG&E Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 2, 2012	ANTHONY F. EARLEY, JR.
	Anthony F. Earley, Jr.
	Chairman, Chief Executive Officer and President

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Kent M. Harvey, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended March 31, 2012 of PG&E Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 2, 2012	KENT M. HARVEY
	Kent M. Harvey
	Senior Vice President and Chief Financial Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Christopher P. Johns, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended March 31, 2012 of Pacific Gas and Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 2, 2012	CHRISTOPHER P. JOHNS
	Christopher P. Johns
	President

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Dinyar B. Mistry, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended March 31, 2012 of Pacific Gas and Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 2, 2012	DINYAR B. MISTRY
	Dinyar B. Mistry
	Vice President, Chief Financial Officer and Controller

EX-32.1

Exhibit 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended March 31, 2012 (“Form 10-Q”), I, Anthony F. Earley, Jr., Chairman, Chief Executive Officer and President of PG&E Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1) the Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of PG&E Corporation.

  ANTHONY F. EARLEY, JR.

  ANTHONY F. EARLEY, JR.

  Chairman, Chief Executive Officer and President

May 2, 2012

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended March 31, 2012 (“Form 10-Q”), I, Kent M. Harvey, Senior Vice President and Chief Financial Officer of PG&E Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1) the Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of PG&E Corporation.

  KENT M. HARVEY

  KENT M. HARVEY

  Senior Vice President and

  Chief Financial Officer

May 2, 2012

EX-32.2

Exhibit 32.2

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended March 31, 2012 (“Form 10-Q”), I, Christopher P. Johns, President of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1) the Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company.

  CHRISTOPHER P. JOHNS

  CHRISTOPHER P. JOHNS

  President

May 2, 2012

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Annual Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended March 31, 2012 (“Form 10-Q”), I, Dinyar B. Mistry, Vice President, Chief Financial Officer and Controller of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1) the Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company.

  DINYAR B. MISTRY

  DINYAR B. MISTRY

  Vice President, Chief Financial Officer and

  Controller

May 2, 2012

XML

Derivatives (Outstanding Derivative Balances) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	$ (774)	$ (720)
Cash Collateral	516	478
Total Derivative Balance	(258)	(242)
Other Current Assets [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	42	54
Netting	(27)	(39)
Cash Collateral	97	103
Total Derivative Balance	112	118
Other Noncurrent Assets [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	96	113
Netting	(43)	(59)
Total Derivative Balance	53	54
Other Current Liabilities [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	(515)	(489)
Netting	27	39
Cash Collateral	318	274
Total Derivative Balance	(170)	(176)
Other Noncurrent Liabilities [Member]
Derivatives And Hedging Activities [Line Items]
Gross Derivative Balance	(397)	(398)
Netting	43	59
Cash Collateral	101	101
Total Derivative Balance	$ (253)	$ (238)

XML

Commitments And Contingencies (Nuclear Fuel Storage) (Details) (USD $) In Millions, unless otherwise specified		96 Months Ended
	Mar. 31, 2012	Dec. 31, 2012 Pacific Gas And Electric Company [Member]	Aug. 03, 2010 Pacific Gas And Electric Company [Member]	Mar. 30, 2010 Pacific Gas And Electric Company [Member]	Dec. 31, 2004 Pacific Gas And Electric Company [Member]
Primary remaining exposure relating to potential environmental obligations of former subsidiary	$ 150
Costs incurred that the Utility sought recovery					92
Amount of costs awarded by U.S. Court of Federal Claims				89
Number of complaints filed			2
Costs incurred to build on-site spent nuclear fuel storage facilities		$ 205

XML

Fair Value Measurements (Schedule Of Activity For Debt And Equity Securities) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Fair Value Measurements [Abstract]
Proceeds from sales and maturities of nuclear decommissioning trust investments	$ 351	$ 726
Gross realized gains on sales of securities held as available-for-sale	7	20
Gross realized losses on sales of securities held as available-for-sale	$ (3)	$ (4)

XML

Commitments And Contingencies (Nuclear Insurance) (Details) (USD $)	3 Months Ended
	Mar. 31, 2012
Long-term Purchase Commitment [Line Items]
Additional annual insurance premium due in conjunction with prolonged outage	$ 40,000,000
Full insurance policy limit	3,200,000,000
Humboldt Bay Unit 3 liability insurance	53,000,000
Coverage for purchased public liability insurance, per incident	375,000,000
Diablo Canyon [Member]
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	3,200,000,000
Amount of property damage coverage provided by NEIL	2,700,000,000
Business interruption	490,000,000
Maximum public liability per nuclear incident under Price-Anderson Act	12,600,000,000
Maximum available public liability insurance for Diablo Canyon as required by Price-Anderson Act	375,000,000
Maximum public liability claims amount per nuclear event	12,600,000,000
Maximum total payment incurred per event under the loss sharing program	235,000,000
Maximum annual payment incurred per event under the loss sharing program	35,000,000
Humboldt Bay Unit [Member]
Long-term Purchase Commitment [Line Items]
Amount of property damage coverage provided by NEIL	131,000,000
Amount of indemnification from the NRC for public liability arising from nuclear incidents	500,000,000
Amount of liability insurance for Humboldt Bay Unit 3	$ 53,000,000

XML

Fair Value Measurements (Schedule Of Unrealized Gains (Losses) Related To Available-For-Sale Investments) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012		Dec. 31, 2011
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	$ 1,516		$ 1,478
Total Unrealized Gains	870		756
Total Unrealized Losses	(4)		(5)
Total Fair Value	2,382	[1]	2,229	[1]
Amount primarily related to deferred taxes on appreciation of investment value	248		188
U.S. Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	319		334
Total Unrealized Gains	616		518
Total Unrealized Losses	(1)		(3)
Total Fair Value	934	[1]	849	[1]
Non-U.S. Equity Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	197		194
Total Unrealized Gains	162		131
Total Unrealized Losses	(1)		(2)
Total Fair Value	358	[1]	323	[1]
U.S. Government And Agency Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	787		798
Total Unrealized Gains	86		102
Total Unrealized Losses	(1)
Total Fair Value	872	[1]	900	[1]
Municipal Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	66		56
Total Unrealized Gains	3		2
Total Unrealized Losses	(1)
Total Fair Value	68	[1]	58	[1]
Other Fixed-Income Securities [Member]
Schedule of Available-for-sale Securities [Line Items]
Amortized Cost	147		96
Total Unrealized Gains	3		3
Total Unrealized Losses
Total Fair Value	$ 150	[1]	$ 99	[1]

[1] Excludes $248 million and $188 million at March 31, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value.

XML

Regulatory Assets, Liabilities, And Balancing Accounts (Current Regulatory Balancing Accounts, Net) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 784	$ 708
Utility Generation [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	412	241
Distribution Revenue Adjustment Mechanism [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	422	223
Public Purpose Programs [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	96	97
Hazardous Substance [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	56	57
Gas Fixed Cost [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	(101)	16
Energy Procurement [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	(129)	(48)
Other Current Balancing Accounts [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	136	227
Energy Recovery Bonds [Member]
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ (108)	$ (105)

XML

Commitments And Contingencies (Change In Accruals Related To Third-Party Claims) (Details) (Pacific Gas And Electric Company [Member], USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pacific Gas And Electric Company [Member]
Beginning Balance	$ 277	$ 214	$ 0
Loss accrued			220
Additional loss accrued		155
Less: Payments	(34)	(92)	(6)
Ending Balance	$ 243	$ 277	$ 214

XML

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2012

Fair Value Measurements [Abstract]

Assets And Liabilities Measured At Fair Value On A Recurring Basis

	Fair Value Measurements
	At March 31, 2012											At December 31, 2011
(in millions)	Level 1		Level 2		Level 3		Netting (1)			Total		Level 1		Level 2		Level 3		Netting (1)			Total
Assets:
Money market investments		$ 206		$ -		$ -		$ -			$ 206		$ 206		$ -		$ -		$ -			$ 206
Nuclear decommissioning trusts
U.S. equity securities		925		9		-		-			934		841		8		-		-			849
Non-U.S. equity securities		358		-		-		-			358		323		-		-		-			323
U.S. government and agency securities		734		138		-		-			872		744		156		-		-			900
Municipal securities		-		68		-		-			68		-		58		-		-			58
Other fixed-income securities		-		150		-		-			150		-		99		-		-			99
Total nuclear decommissioning trusts (2)		2,017		365		-		-			2,382		1,908		321		-		-			2,229
Price risk management instruments (Note 7)
Electricity		-		68		67		27			162		-		92		69		8			169
Gas		-		3		-		-			3		-		6		-		(3	)		3
Total price risk management instruments		-		71		67		27			165		-		98		69		5			172
Rabbi trusts
Fixed-income securities		-		26		-		-			26		-		25		-		-			25
Life insurance contracts		-		68		-		-			68		-		67		-		-			67
Total rabbi trusts		-		94		-		-			94		-		92		-		-			92
Long-term disability trust
U.S. equity securities		5		13		-		-			18		13		15		-		-			28
Non-U.S. equity securities		-		15		-		-			15		-		9		-		-			9
Fixed-income securities		-		142		-		-			142		-		145		-		-			145
Total long-term disability trust		5		170		-		-			175		13		169		-		-			182
Total assets		$ 2,228		$ 700		$ 67		$ 27			$ 3,022		$ 2,127		$ 680		$ 69		$ 5			$ 2,881
Liabilities:
Price risk management instruments (Note 7)
Electricity		$ 436		$ 284		$ 166		$ (471	)		$ 415		$ 411		$ 289		$ 143		$ (441	)		$ 402
Gas		15		11		-		(18	)		8		31		13		-		(32	)		12
Total liabilities		$ 451		$ 295		$ 166		$ (489	)		$ 423		$ 442		$ 302		$ 143		$ (473	)		$ 414

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

⁽²⁾ Excludes $248 million and $188 million at March 31, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value.

Level 3 Measurements And Sensitivity Analysis

(in millions)	Fair Value at March 31, 2012					Valuation Technique	Unobservable Input	Range
Fair Value Measurement	Assets		Liabilities
Congestion revenue rights		$ 67		$ (8	)	Market approach	CRR auction prices	$ (6.30) - $ 5.10
Power purchase agreements		$ -		$ (158	)	Discounted cash flow	Forward prices	$ 2.00 - $ 61.05

Level 3 Reconciliation

	Price Risk Management Instruments
(in millions)	2012			2011
Liability balance as of January 1		$ (74	)		$ (399	)
Realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)		(25	)		87
Liability balance as of March 31		$ (99	)		$ (312	)

⁽¹⁾ Price risk management activity is recoverable through customer rates. Therefore, net income was not impacted by realized amounts. Unrealized gains and losses are deferred in regulatory liabilities and assets.

Carrying Amount And Fair Value Of Financial Instruments

	March 31, 2012				December 31, 2011
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation		$ 349		$ 382		$ 349		$ 380
Utility		10,546		12,412		10,545		12,543
Energy recovery bonds (Note 4)		321		327		423		433

Schedule Of Unrealized Gains (Losses) Related To Available-For-Sale Investments

(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Total Fair Value (1)
As of March 31, 2012
Equity securities
U.S.		$ 319		$ 616		$ (1	)		$ 934
Non-U.S.		197		162		(1	)		358
Debt securities
U.S. government and agency securities		787		86		(1	)		872
Municipal securities		66		3		(1	)		68
Other fixed-income securities		147		3		-			150
Total		$ 1,516		$ 870		$ (4	)		$ 2,382
As of December 31, 2011
Equity securities
U.S.		$ 334		$ 518		$ (3	)		$ 849
Non-U.S.		194		131		(2	)		323
Debt securities
U.S. government and agency securities		798		102		-			900
Municipal securities		56		2		-			58
Other fixed-income securities		96		3		-			99
Total		$ 1,478		$ 756		$ (5	)		$ 2,229

⁽¹⁾ Excludes $248 million and $188 million at March 31, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value.

Schedule Of Maturities On Debt Instruments

(in millions)	As of March 31, 2012
Less than 1 year		$ 29
1–5 years		408
5–10 years		264
More than 10 years		389
Total maturities of debt securities		$ 1,090

Schedule Of Activity For Debt And Equity Securities

	Three Months Ended
(in millions)	March 31, 2012			March 31, 2011
Proceeds from sales and maturities of nuclear decommissioning trust investments		$ 351			$ 726
Gross realized gains on sales of securities held as available-for-sale		7			20
Gross realized losses on sales of securities held as available-for-sale		(3	)		(4	)

XML

Commitments And Contingencies (Third-Party Power Purchases) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Long-term Purchase Commitment [Line Items]
2012	$ 1,810
2013	2,860
2014	3,010
2015	3,007
2016	2,917
Thereafter	32,120
Total	45,724
Cost incurred by the Utility under power purchase agreements	435	587
Capital leases, future minimum lease payments	115
Total minimum lease payments terminated	$ 136
Minimum [Member]
Long-term Purchase Commitment [Line Items]
Long-term agreements range, years	10
Maximum [Member]
Long-term Purchase Commitment [Line Items]
Long-term agreements range, years	25

XML

Fair Value Measurements (Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011		Mar. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Amount primarily related to deferred taxes on appreciation of investment value	$ 188		$ 248
Fair Value Measurements, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	206		206
Total assets	2,127		2,228
Total liabilities	442		451
Fair Value Measurements, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	680		700
Total liabilities	302		295
Fair Value Measurements, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	69		67
Total liabilities	143		166
Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments		[1]
Nuclear decomissioning trusts		[1]
Total assets	5	[1]	27	[1]
Total liabilities	(473)	[1]	(489)	[1]
Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market investments	206		206
Total assets	2,881		3,022
Total liabilities	414		423
Nuclear Decommissioning Trusts [Member] | Fair Value Measurements, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
U.S. equity securities	841		925
Non-U.S. equity securities	323		358
U.S. government and agency securities	744		734
Total assets	1,908	[2]	2,017	[2]
Nuclear Decommissioning Trusts [Member] | Fair Value Measurements, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
U.S. equity securities	8		9
U.S. government and agency securities	156		138
Municipal securities	58		68
Other fixed-income securities	99		150
Total assets	321	[2]	365	[2]
Nuclear Decommissioning Trusts [Member] | Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
U.S. equity securities		[1]
Non-U.S. equity securities		[1]
U.S. government and agency securities		[1]
Municipal securities		[1]
Other fixed-income securities		[1]
Total assets		[1],[2]
Nuclear Decommissioning Trusts [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
U.S. equity securities	849		934
Non-U.S. equity securities	323		358
U.S. government and agency securities	900		872
Municipal securities	58		68
Other fixed-income securities	99		150
Total assets	2,229	[2]	2,382	[2]
Price Risk Management Instruments [Member] | Fair Value Measurements, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Electricity, Liabilities	411		436
Gas, Liabilities	31		15
Price Risk Management Instruments [Member] | Fair Value Measurements, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	98		71
Electricity, Assets	92		68
Gas, Assets	6		3
Electricity, Liabilities	289		284
Gas, Liabilities	13		11
Price Risk Management Instruments [Member] | Fair Value Measurements, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	69		67
Electricity, Assets	69		67
Electricity, Liabilities	143		166
Price Risk Management Instruments [Member] | Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	5	[1]	27	[1]
Electricity, Assets	8	[1]	27	[1]
Gas, Assets	(3)	[1]
Electricity, Liabilities	(441)	[1]	(471)	[1]
Gas, Liabilities	(32)	[1]	(18)	[1]
Price Risk Management Instruments [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total assets	172		165
Electricity, Assets	169		162
Gas, Assets	3		3
Electricity, Liabilities	402		415
Gas, Liabilities	12		8
Rabbi Trusts [Member] | Fair Value Measurements, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other fixed-income securities	25		26
Life insurance contracts	67		68
Total assets	92		94
Rabbi Trusts [Member] | Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other fixed-income securities		[1]
Life insurance contracts		[1]
Total assets		[1]
Rabbi Trusts [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other fixed-income securities	25		26
Life insurance contracts	67		68
Total assets	92		94
Long-Term Disability Trust [Member] | Fair Value Measurements, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
U.S. equity securities	13		5
Total assets	13		5
Long-Term Disability Trust [Member] | Fair Value Measurements, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
U.S. equity securities	15		13
Non-U.S. equity securities	9		15
Fixed-income securities	145		142
Total assets	169		170
Long-Term Disability Trust [Member] | Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
U.S. equity securities		[1]
Non-U.S. equity securities		[1]
Fixed-income securities		[1]
Total assets		[1]
Long-Term Disability Trust [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
U.S. equity securities	28		18
Non-U.S. equity securities	9		15
Fixed-income securities	145		142
Total assets	$ 182		$ 175

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

[2] Excludes $248 million and $188 million at March 31, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value.

XML

Earnings Per Share (Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Common Shares Outstanding For Calculating Diluted EPS) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Earnings Per Share [Abstract]
Income available for common shareholders	$ 233	$ 199
Weighted average common shares outstanding, basic	414	396
Employee share-based compensation	2	1
Weighted average common shares outstanding, diluted	416	397
Total earnings per common share, diluted	$ 0.56	$ 0.50

XML

Commitments And Contingencies (Nuclear Fuel Agreements) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Long-term Purchase Commitment [Line Items]
2012	$ 1,810
2013	2,860
2014	3,010
2015	3,007
2016	2,917
Thereafter	32,120
Total	45,724
Pacific Gas And Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Payments for nuclear fuel	19	29
Length of contract terms, minimum (in years)	1
Length of contract terms, maximum (in years)	14
Percentage coverage of reactor requirements through 2016	100.00%
Percentage coverage of reactor requirements through 2017	100.00%
Nuclear Fuel Agreements [Member]
Long-term Purchase Commitment [Line Items]
2012	67
2013	86
2014	127
2015	193
2016	147
Thereafter	1,011
Total	$ 1,631

XML

Fair Value Measurements (Schedule Of Maturities On Debt Securities) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012
Fair Value Measurements [Abstract]
Less than 1 year	$ 29
1-5 years	408
5-10 years	264
More than 10 years	389
Total maturities of debt securities	$ 1,090

XML

Organization And Basis Of Presentation

3 Months Ended

Mar. 31, 2012

Organization And Basis Of Presentation

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

PG&E Corporation is a holding company that conducts its business 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 statements 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, 2011 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 2011 Annual Report on Form 10-K filed with the SEC on February 16, 2012. PG&E Corporation's and the Utility's combined 2011 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 "2011 Annual Report." This quarterly report should be read in conjunction with the 2011 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, legal and regulatory contingencies, environmental remediation liabilities, asset retirement obligations ("ARO"), and pension and other postretirement benefit plans 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.

Pacific Gas And Electric Company [Member]

Organization And Basis Of Presentation

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

PG&E Corporation is a holding company that conducts its business 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 statements 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, 2011 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 2011 Annual Report on Form 10-K filed with the SEC on February 16, 2012. PG&E Corporation's and the Utility's combined 2011 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 "2011 Annual Report." This quarterly report should be read in conjunction with the 2011 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, legal and regulatory contingencies, environmental remediation liabilities, asset retirement obligations ("ARO"), and pension and other postretirement benefit plans 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.

XML

Fair Value Measurements (Level 3 Measurements And Sensitivity Analysis) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Congestion Revenue Rights [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets, Fair Value	$ 67
Liabilities, Fair Value	(8)
Fair value measurement valuation technique	Market approach
Fair value measurement unobservable input	CRR auction prices
Power Purchase Agreements [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Liabilities, Fair Value	$ (158)
Fair value measurement valuation technique	Discounted cash flow
Fair value measurement unobservable input	Forward prices
Minimum [Member] | CRR Auction Prices [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value measurement unobservable input range	(6.30)
Minimum [Member] | Forward Prices [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value measurement unobservable input range	2.00
Maximum [Member] | CRR Auction Prices [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value measurement unobservable input range	5.10
Maximum [Member] | Forward Prices [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value measurement unobservable input range	61.05

XML

New And Significant Accounting Policies (Components Of Net Periodic Benefit Cost) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	$ 99		$ 82
Interest cost	164		164
Expected return on plan assets	(149)		(167)
Amortization of prior service cost	5		9
Amortization of unrecognized loss	31		12
Net periodic benefit cost	150		100
Less: transfer to regulatory account	(75)	[1]	(36)	[1]
Total	75		64
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	12		11
Interest cost	21		23
Expected return on plan assets	(19)		(20)
Amortization of transition obligation	6		6
Amortization of prior service cost	6		6
Amortization of unrecognized loss	1		1
Net periodic benefit cost	27		27
Total	$ 27		$ 27

[1] The Utility recorded $75 million and $36 million for the three months ended March 31, 2012 and 2011, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates.

XML

New And Significant Accounting Policies (Narrative) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012
Public Utility, Property, Plant and Equipment [Line Items]
Benefits and customers payments received on tax equity agreements	$ 160
Pacific Gas And Electric Company [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Utility's equity investment in PERF	100.00%
PERF [Member]
Public Utility, Property, Plant and Equipment [Line Items]
PERF assets	382
PERF liabilities	321
Residential And Commercial Retail Solar Energy Installations [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Payments made under tax equity agreements	396
Lease Payments And Investment Contributions [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Payments made under tax equity agreements	$ 360

XML

Commitments And Contingencies (Legal And Regulatory Contingencies) (Details) (USD $)	3 Months Ended	12 Months Ended		3 Months Ended	12 Months Ended	3 Months Ended				3 Months Ended	12 Months Ended	3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Apr. 19, 2012	Mar. 31, 2012 PGE Corporation And Utility [Member]	Dec. 31, 2011 PGE Corporation And Utility [Member]	Mar. 31, 2012 Pacific Gas And Electric Company [Member]	Dec. 31, 2011 Pacific Gas And Electric Company [Member]	Dec. 31, 2010 Pacific Gas And Electric Company [Member]	Dec. 31, 2009 Pacific Gas And Electric Company [Member]	Mar. 31, 2012 Utility [Member]	Dec. 31, 2011 Utility [Member]	Mar. 31, 2012 CPUC Investigations- Maximum Penalties Per Day [Member]	Mar. 31, 2012 San Bruno Explosion [Member]	Mar. 31, 2012 San Bruno Explosion [Member] Pacific Gas And Electric Company [Member]	Mar. 31, 2012 San Bruno Explosion [Member] San Mateo County Superior Court [Member] plaintiff	Mar. 31, 2012 San Bruno Explosion [Member] Tort Lawsuits [Member] San Mateo County Superior Court [Member] lawsuit	Mar. 31, 2012 San Bruno Explosion [Member] Class Action Lawsuits [Member] San Mateo County Superior Court [Member] lawsuit
Loss Contingencies [Line Items]
Accrued legal liabilities				$ 36,000,000	$ 52,000,000	$ 243,000,000	$ 277,000,000	$ 214,000,000	$ 0
Penalty due to plat maps being misplaced		17,000,000
Number of self-reports filed with the CPUC	12
Citation to be paid upon final resolution			17,000,000
Time limit for citation to be paid (days)			30
Number of gas distribution maps	16
Additional number of gas distribution maps, not considered	46
Per violation penalty that may be imposed prior to the maximum statutory penalty increase												20,000
Per violation penalty that may be imposed subsequent to the maximum statutory penalty increase												50,000
Probable penalty amount				200,000,000	200,000,000
Number of lawsuits																110	2
Number of plaintiffs															380
Cumulative charge														375,000,000
Estimated possible additional loss contingency liability														225,000,000
Insurance recoveries for cost incurred related to third-party claims										11,000,000	99,000,000
Estimated maximum amount for third-party claims for San Bruno													600,000,000
Utility liability insurance for damages						992,000,000
Utility liability insurance deductible						$ 10,000,000

XML

Fair Value Measurements (Level 3 Reconciliation) (Details) (Fair Value Measurements, Level 3 [Member], Price Risk Management Instruments [Member], USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
Fair Value Measurements, Level 3 [Member] | Price Risk Management Instruments [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Liability balance as of January 1	$ (74)		$ (399)
Realized and unrealized gains (losses): Included in regulatory assets and liabilities or balancing accounts	(25)	[1]	87	[1]
Liability balance as of March 31	$ (99)		$ (312)

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

XML

Regulatory Assets, Liabilities, And Balancing Accounts (Narrative) (Details) (USD $)	Mar. 31, 2012	Dec. 31, 2011
Regulatory Assets [Line Items]
Current regulatory assets	$ 1,024,000,000	$ 1,090,000,000
Undepreciated conventional electromechanical meters regulatory assets recovery maximum (months)	12
Book value of undepreciated conventional electromechanical meters	50,000,000
Deferred income taxes regulatory asset recovery minimum (years)	1
Amortization of underlying retained generation regulatory assets	62,000,000
Amortization of underlying generation facilities expected to recovered (months)	12
Deferred income taxes regulatory asset recovery maximum (years)	44
Utility retained generation asset costs	1,200,000,000
Unrealized losses related to price risk management derivative instruments	12
Weighted average remaining life of Utility's retained generation assets (years)	13
Environmental compliance costs regulatory asset recovery (years)	32
Price risk management regulatory asset recovery (years)	10
Recovery of costs related to debt reacquired or redeemed prior to maturity (years)	14
Term of a terminated power purchase agreement (years)	30
Current regulatory liabilities	83,000,000	161,000,000
Period of time expected to receive authorized rate adjustments (months)	12
Period of time exceeded for regulatory balancing accounts to be recorded in other noncurrent assets (months)	12
Recovery of remediation costs, percentage	90.00%
Recovery of energy procurement costs, percentage	100.00%
Electromechanical Meters [Member]
Regulatory Assets [Line Items]
Expected recovery of regulated asset (years)	4
Energy Recovery Bonds [Member]
Regulatory Assets [Line Items]
Current regulatory assets	227,000,000	336,000,000
Price Risk Management Derivative Instruments [Member]
Regulatory Assets [Line Items]
Current regulatory assets	$ 488,000,000

XML

Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Assets) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 6,565	$ 6,506
Pension Benefits [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	2,939	2,899
Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	1,483	1,444
Utility Retained Generation [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	598	613
Environmental Compliance Costs [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	535	520
Price Risk Management [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	354	339
Electromechanical Meters [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	234	247
Unamortized Loss, Net Of Gain, On Reacquired Debt [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	157	163
Other Long-Term Regulatory Assets [Member]
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 265	$ 281

XML

Condensed Consolidated Statements Of Cash Flows (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Cash Flows from Financing Activities
Net (repayments) issuances of commercial paper, discount	$ 1	$ 1
Pacific Gas And Electric Company [Member]
Cash Flows from Financing Activities
Net (repayments) issuances of commercial paper, discount	$ 1	$ 1

XML

Regulatory Assets, Liabilities, And Balancing Accounts (Long-Term Regulatory Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 4,927	$ 4,733
Cost Of Removal Obligations [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	3,524	3,460
Recoveries In Excess Of AROs [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	707	611
Public Purpose Programs [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	526	499
Other Long-Term Regulatory Liabilities [Member]
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 170	$ 163

XML

Derivatives (Gains And Losses On Derivative Instruments) (Details) (PGE Corporation And Utility [Member], USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
PGE Corporation And Utility [Member]
Unrealized (loss) gain-regulatory assets and liabilities	$ (54)	[1]	$ 137	[1]
Realized loss - cost of electricity	(151)	[2]	(136)	[2]
Realized loss - cost of natural gas	(22)	[2]	(55)	[2]
Total commodity risk instruments	$ (227)		$ (54)

[1] Unrealized gains and losses on derivatives are deferred 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 recovered from customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.

XML

Commitments And Contingencies (Other Commitments) (Details) (Office Space [Member], USD $) In Millions, unless otherwise specified	Mar. 31, 2012 sqft Y
Office Space [Member]
Operating Leased Assets [Line Items]
Lease agreement, duration (years)	10
Area of office space leased (square feet)	250,000
Future minimum commitment for operating lease	$ 67

XML

Condensed Consolidated Statements Of Income (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Operating Revenues
Electric	$ 2,772	$ 2,617
Natural gas	869	980
Total operating revenues	3,641	3,597
Operating Expenses
Cost of electricity	859	888
Cost of natural gas	343	508
Operating and maintenance	1,368	1,226
Depreciation, amortization, and decommissioning	584	491
Total operating expenses	3,154	3,113
Operating Income	487	484
Interest income	1	2
Interest expense	(174)	(177)
Other income, net	26	17
Income Before Income Taxes	340	326
Income tax provision	104	124
Net Income	236	202
Preferred stock dividend requirement of subsidiary	3	3
Income Available for Common Shareholders	233	199
Weighted Average Common Shares Outstanding, Basic	414	396
Weighted Average Common Shares Outstanding, Diluted	416	397
Net Earnings Per Common Share, Basic	$ 0.56	$ 0.50
Net Earnings Per Common Share, Diluted	$ 0.56	$ 0.50
Dividends Declared Per Common Share	$ 0.46	$ 0.46
Pacific Gas And Electric Company [Member]
Operating Revenues
Electric	2,771	2,616
Natural gas	869	980
Total operating revenues	3,640	3,596
Operating Expenses
Cost of electricity	859	888
Cost of natural gas	343	508
Operating and maintenance	1,366	1,226
Depreciation, amortization, and decommissioning	584	490
Total operating expenses	3,152	3,112
Operating Income	488	484
Interest income	1	2
Interest expense	(168)	(171)
Other income, net	23	17
Income Before Income Taxes	344	332
Income tax provision	113	131
Net Income	231	201
Preferred stock dividend requirement	3	3
Income Available for Common Shareholders	$ 228	$ 198

XML

Fair Value Measurements (Carrying Amount And Fair Value Of Financial Instruments) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Carrying Amount [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	$ 349	$ 349
Energy recovery bonds	321	423
Carrying Amount [Member] | Pacific Gas And Electric Company [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	10,546	10,545
Fair Value Measurements, Level 2 [Member] | Fair Value [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	382	380
Energy recovery bonds	327	433
Fair Value Measurements, Level 2 [Member] | Fair Value [Member] | Pacific Gas And Electric Company [Member]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]
Debt financial instrument	$ 12,412	$ 12,543

XML

Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Restricted cash	$ 385	$ 380
Allowance for doubtful accounts	80	81
Regulatory assets current	1,024	1,090
Common stock, par value
Common stock, shares authorized	800,000,000	800,000,000
Common stock, shares outstanding	421,777,738	412,257,082
Energy Recovery Bonds [Member]
Restricted cash	56	51
Regulatory assets current	227	336
Pacific Gas And Electric Company [Member]
Restricted cash	385	380
Allowance for doubtful accounts	80	81
Regulatory assets current	1,024	1,090
Common stock, par value	$ 5	$ 5
Common stock, shares authorized	800,000,000	800,000,000
Common stock, shares outstanding	264,374,809	264,374,809
Pacific Gas And Electric Company [Member] | Energy Recovery Bonds [Member]
Restricted cash	56	51
Regulatory assets current	$ 227	$ 336

XML

Commitments And Contingencies (Environmental Remediation Contingencies) (Details) (USD $)			3 Months Ended
	Mar. 31, 2012	Oct. 31, 2011	Mar. 31, 2012 Pacific Gas And Electric Company [Member]	Dec. 31, 2011 Pacific Gas And Electric Company [Member]	Mar. 31, 2012 Hinkley Natural Gas Compressor Station [Member]	Dec. 31, 2011 Hinkley Natural Gas Compressor Station [Member]	Mar. 31, 2012 Hinkley Natural Gas Compressor Station [Member] Pacific Gas And Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Requisite parts for permanent water system replacement, in ppb		3.1
Eligible resident households for voluntary program	300
Amount of environmental loss accrual expected to be recovered	$ 50,000,000		$ 427,000,000
Additional environmental recoveries receivable	99,000,000
Authorized recovery of hazardous waste remediation costs							90.00%
Recovery of remediation costs for decommissioning fossil-fueled sites			100.00%
Increase in undiscounted future costs in the event other potentially responsible parties are not able to contribute			1,600,000,000
Utility undiscounted future costs			$ 921,000,000	$ 785,000,000	$ 218,000,000	$ 149,000,000

XML

Equity (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified	0 Months Ended	3 Months Ended
	Mar. 20, 2012	Mar. 31, 2012	Mar. 31, 2012 Pacific Gas And Electric Company [Member]	Mar. 31, 2011 Pacific Gas And Electric Company [Member]
Stock issued during period for stock options exercised and under 401(K) plan and DRSPP		3,363,617
Cash proceeds from employee stock options exercised		$ 133
Net of fees and commissions		1
Equity distribution agreement amount		219
Sale of common stock in an underwritten public offering	5,900,000
Cash proceeds from sale of common shares in an underwritten public offering	254
Equity contribution			$ 385	$ 65
Common equity ratio percentage		52.00%
Debt and preferred stock ratio percentage		48.00%

XML

Equity (Tables)

3 Months Ended

Mar. 31, 2012

Equity [Abstract]

Changes In Equity

	PG&E Corporation			Utility
(in millions)	Total Equity			Total Shareholders'  Equity
Balance at December 31, 2011		$ 12,353			$ 12,384
Comprehensive income		246			241
Common stock issued		393			-
Share-based compensation expense		16			-
Common stock dividends declared		(193	)		(179	)
Preferred stock dividend requirement		-			(3	)
Preferred stock dividend requirement of subsidiary		(3	)		-
Equity contributions		-			385
Balance at March 31, 2012		$ 12,812			$ 12,828

XML

Equity (Changes In Equity) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Balance at December 31, 2011	$ 12,353
Comprehensive income	246	211
Common stock issued	393
Share-based compensation expense	16
Common stock dividends declared	(193)
Preferred stock dividend requirement of subsidiary	(3)	(3)
Balance at March 31, 2012	12,812
Pacific Gas And Electric Company [Member]
Balance at December 31, 2011	12,384
Comprehensive income	241	210
Common stock dividends declared	(179)
Preferred stock dividend requirement	(3)	(3)
Equity contribution	385	65
Balance at March 31, 2012	$ 12,828

XML

Derivatives (Tables)

3 Months Ended

Mar. 31, 2012

Derivatives [Abstract]

Volumes Of Outstanding Derivative Contracts

		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		439,441,427		166,878,481		4,280,000		-
	Options		231,380,020		280,200,000		-		-
Electricity (Megawatt-hours)	Forwards and Swaps		4,141,223		4,696,221		2,009,505		3,421,832
	Options		1,248,000		140,510		239,233		218,013
	Congestion Revenue Rights		75,532,338		73,123,024		73,190,271		54,209,541

⁽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 2017 and 2022.

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

⁽⁴⁾ Million British Thermal Units.

Outstanding Derivative Balances

	Gross  Derivative Balance			Netting			Cash Collateral		Total  Derivative Balance
(in millions)	Commodity Risk (PG&E Corporation and the Utility)
Current assets – other		$ 42			$ (27	)		$ 97		$ 112
Other noncurrent assets – other		96			(43	)		-		53
Current liabilities – other		(515	)		27			318		(170	)
Noncurrent liabilities – other		(397	)		43			101		(253	)
Total commodity risk		$ (774	)		$ -			$ 516		$ (258	)

At December 31, 2011, PG&E Corporation's and the Utility's outstanding derivative balances were as follows:

		$0000.0			$0000.0			$0000.0		$0000.0
	Gross  Derivative Balance			Netting			Cash Collateral		Total  Derivative Balance
(in millions)	Commodity Risk (PG&E Corporation and the Utility)
Current assets – other		$ 54			$ (39	)		$ 103		$ 118
Other noncurrent assets – other		113			(59	)		-		54
Current liabilities – other		(489	)		39			274		(176	)
Noncurrent liabilities – other		(398	)		59			101		(238	)
Total commodity risk		$ (720	)		$ -			$ 478		$ (242	)

Gains And Losses On Derivative Instruments

	Commodity Risk (PG&E  Corporation and Utility)
	Three months ended March 31,
(in millions)	2012			2011
Unrealized (loss) gain – regulatory assets and liabilities (1)		$ (54	)		$ 137
Realized loss – cost of electricity (2)		(151	)		(136	)
Realized loss – cost of natural gas (2)		(22	)		(55	)
Total commodity risk instruments		$ (227	)		$ (54	)

⁽¹⁾ Unrealized gains and losses on derivatives are deferred 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 recovered from customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.

Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered

(in millions)
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized	$ (134	)
Related derivatives in an asset position	2
Collateral posting in the normal course of business related to these derivatives	33
Net position of derivative contracts/additional collateral posting requirements (1)	$ (99	)

⁽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.

XML

Condensed Consolidated Statements Of Cash Flows (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Cash Flows from Operating Activities
Net income	$ 236	$ 202
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	584	491
Allowance for equity funds used during construction	(27)	(20)
Deferred income taxes and tax credits, net	146	99
Other	73	44
Effect of changes in operating assets and liabilities:
Accounts receivable	221	35
Inventories	50	65
Accounts payable	(213)	182
Income taxes receivable/payable	29	34
Other current assets and liabilities	(70)	(205)
Regulatory assets, liabilities, and balancing accounts, net	(171)	(10)
Other noncurrent assets and liabilities	73	171
Net cash provided by operating activities	931	1,088
Cash Flows from Investing Activities
Capital expenditures	(1,094)	(945)
(Increase) decrease in restricted cash	(5)	132
Proceeds from sales and maturities of nuclear decommissioning trust investments	351	726
Purchases of nuclear decommissioning trust investments	(370)	(735)
Other	25	(61)
Net cash used in investing activities	(1,093)	(883)
Cash Flows from Financing Activities
Net (repayments) issuances of commercial paper, net of discount of $1 in 2012 and in 2011	(245)	415
Long-term debt matured		(500)
Energy recovery bonds matured	(102)	(97)
Common stock issued	387	82
Common stock dividends paid	(182)	(174)
Other	48	18
Net used in financing activities	(94)	(256)
Net change in cash and cash equivalents	(256)	(51)
Cash and cash equivalents at January 1	513	291
Cash and cash equivalents at March 31	257	240
Cash received (paid) for:
Interest, net of amounts capitalized	(204)	(215)
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	193	181
Capital expenditures financed through accounts payable	276	174
Noncash common stock issuances	6	6
Terminated capital leases	136
Pacific Gas And Electric Company [Member]
Cash Flows from Operating Activities
Net income	231	201
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	584	490
Allowance for equity funds used during construction	(27)	(20)
Deferred income taxes and tax credits, net	153	99
Other	57	29
Effect of changes in operating assets and liabilities:
Accounts receivable	218	69
Inventories	50	65
Accounts payable	(182)	190
Income taxes receivable/payable	30	34
Other current assets and liabilities	(69)	(196)
Regulatory assets, liabilities, and balancing accounts, net	(171)	(10)
Other noncurrent assets and liabilities	75	144
Net cash provided by operating activities	949	1,095
Cash Flows from Investing Activities
Capital expenditures	(1,094)	(945)
(Increase) decrease in restricted cash	(5)	132
Proceeds from sales and maturities of nuclear decommissioning trust investments	351	726
Purchases of nuclear decommissioning trust investments	(370)	(735)
Other	3	7
Net cash used in investing activities	(1,115)	(815)
Cash Flows from Financing Activities
Net (repayments) issuances of commercial paper, net of discount of $1 in 2012 and in 2011	(245)	415
Long-term debt matured		(500)
Energy recovery bonds matured	(102)	(97)
Preferred stock dividends paid	(3)	(4)
Common stock dividends paid	(179)	(179)
Equity contribution	385	65
Other	51	21
Net used in financing activities	(93)	(279)
Net change in cash and cash equivalents	(259)	1
Cash and cash equivalents at January 1	304	51
Cash and cash equivalents at March 31	45	52
Cash received (paid) for:
Interest, net of amounts capitalized	(204)	(215)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	276	174
Terminated capital leases	$ 136

XML

Condensed Consolidated Statements Of Comprehensive Income (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Net Income	$ 236	$ 202
Other comprehensive income
Unrecognized prior service credit (net of income tax of $5 in 2012 and 2011)	6	10
Unrecognized net gain (net of income tax of $11 and $6 in 2012 and 2011, respectively	21	7
Unrecognized net transition obligation (net of income tax of $2 in 2012 and 2011)	4	4
Transfer to regulatory account (net of income tax of $15 and $8 in 2012 and 2011, respectively)	(21)	(12)
Other comprehensive income	10	9
Comprehensive income	246	211
Preferred stock dividend requirement of subsidiary	3	3
Comprehensive income attributable to common shareholders	243	208
Pacific Gas And Electric Company [Member]
Net Income	231	201
Other comprehensive income
Unrecognized prior service credit (net of income tax of $5 in 2012 and 2011)	6	10
Unrecognized net gain (net of income tax of $11 and $6 in 2012 and 2011, respectively	21	7
Unrecognized net transition obligation (net of income tax of $2 in 2012 and 2011)	4	4
Transfer to regulatory account (net of income tax of $15 and $8 in 2012 and 2011, respectively)	(21)	(12)
Other comprehensive income	10	9
Comprehensive income	$ 241	$ 210

XML

Resolution Of Remaining Chapter 11 Disputed Claims

3 Months Ended

Mar. 31, 2012

Resolution Of Remaining Chapter 11 Disputed Claims

NOTE 9: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

Various electricity suppliers filed claims in the Utility's Chapter 11 proceeding seeking payment for energy supplied to the Utility's customers through the wholesale electricity markets operated by the CAISO and the California Power Exchange ("PX") between May 2000 and June 2001. These claims, which the Utility disputes, are being addressed in various FERC and judicial proceedings in which the State of California, the Utility, and other electricity purchasers are seeking refunds from electricity suppliers, including municipal and governmental entities, for overcharges incurred in the CAISO and the PX wholesale electricity markets between May 2000 and June 2001. Hearings at the FERC commenced on April 11, 2012 to address the Utility's and other electricity purchasers' refund claims for the May through September 2000 period. The Utility is unable to determine the outcome of the hearings at this time.

While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers. The Utility entered into a number of settlement agreements 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 settlement amounts, net of deductions for contingencies based on the outcome of the various refund offset and interest issues being considered by the FERC, are 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 electricity suppliers through resolution of the remaining disputed claims, either through settlement or the conclusion of the various FERC and judicial proceedings, will also be refunded to customers.

At March 31, 2012 and December 31, 2011, the Utility held $320 million in escrow, including interest earned, for payment of the remaining net disputed claims. These amounts are included within restricted cash on the Condensed Consolidated Balance Sheets.

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

(in millions)
Balance at December 31, 2011	$	848
Interest accrued		7
Less: electricity supplier settlements		(23	)
Balance at March 31, 2012	$	832

At March 31, 2012, the Utility's remaining net disputed claims liability was $832 million, consisting of $658 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 $668 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).

On April 10, 2012, the PX and the Utility reached an agreement that provides the Utility with the legal right to offset the Utility's remaining disputed claims with the Utility's accounts receivable from the CAISO and the PX. In future periods, the Utility will present the net amount of these balances on the Condensed Consolidated Balance Sheets within accounts payable – disputed claims and customer refunds.

Interest accrues on the remaining net disputed claims liability 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 the remaining net disputed claims liability, 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 determined amounts with respect to the remaining net disputed claims liability and when such interest is paid.

Pacific Gas And Electric Company [Member]

Resolution Of Remaining Chapter 11 Disputed Claims

NOTE 9: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

Various electricity suppliers filed claims in the Utility's Chapter 11 proceeding seeking payment for energy supplied to the Utility's customers through the wholesale electricity markets operated by the CAISO and the California Power Exchange ("PX") between May 2000 and June 2001. These claims, which the Utility disputes, are being addressed in various FERC and judicial proceedings in which the State of California, the Utility, and other electricity purchasers are seeking refunds from electricity suppliers, including municipal and governmental entities, for overcharges incurred in the CAISO and the PX wholesale electricity markets between May 2000 and June 2001. Hearings at the FERC commenced on April 11, 2012 to address the Utility's and other electricity purchasers' refund claims for the May through September 2000 period. The Utility is unable to determine the outcome of the hearings at this time.

While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers. The Utility entered into a number of settlement agreements 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 settlement amounts, net of deductions for contingencies based on the outcome of the various refund offset and interest issues being considered by the FERC, are 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 electricity suppliers through resolution of the remaining disputed claims, either through settlement or the conclusion of the various FERC and judicial proceedings, will also be refunded to customers.

At March 31, 2012 and December 31, 2011, the Utility held $320 million in escrow, including interest earned, for payment of the remaining net disputed claims. These amounts are included within restricted cash on the Condensed Consolidated Balance Sheets.

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

(in millions)
Balance at December 31, 2011	$	848
Interest accrued		7
Less: electricity supplier settlements		(23	)
Balance at March 31, 2012	$	832

At March 31, 2012, the Utility's remaining net disputed claims liability was $832 million, consisting of $658 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 $668 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).

On April 10, 2012, the PX and the Utility reached an agreement that provides the Utility with the legal right to offset the Utility's remaining disputed claims with the Utility's accounts receivable from the CAISO and the PX. In future periods, the Utility will present the net amount of these balances on the Condensed Consolidated Balance Sheets within accounts payable – disputed claims and customer refunds.

Interest accrues on the remaining net disputed claims liability 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 the remaining net disputed claims liability, 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 determined amounts with respect to the remaining net disputed claims liability and when such interest is paid.

XML

Document And Entity Information	3 Months Ended
	Mar. 31, 2012	Apr. 24, 2012
Document Type	10-Q
Document Period End Date	Mar. 31, 2012
Amendment Flag	false
Entity Filer Category	Large Accelerated Filer
Entity Registrant Name	PG&E CORP
Entity Central Index Key	0001004980
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
PG&E Corporation [Member]
Entity Common Stock, Shares Outstanding		422,320,110
Pacific Gas And Electric Company [Member]
Document Type	10-Q
Document Period End Date	Mar. 31, 2012
Amendment Flag	false
Entity Filer Category	Non-accelerated Filer
Entity Registrant Name	PACIFIC GAS & ELECTRIC Co
Entity Central Index Key	0000075488
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
Entity Common Stock, Shares Outstanding		264,374,809

XML

Commitments And Contingencies

3 Months Ended

Mar. 31, 2012

Commitments And Contingencies

NOTE 10: COMMITMENTS AND CONTINGENCIES

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

Commitments

Third-Party Power Purchase Agreements

As part of the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either gas or electricity at the date of purchase. The Utility's obligations under a significant portion of these agreements are contingent on the third party's development of new generation facilities to provide the power to be purchased by the Utility under these agreements. The table below excludes future expected payments related to agreements ranging from 10 to 25 years in length that are cancellable if the construction of a new generation facility have not met certain contractual milestones with respect to construction. Based on the Utility's experience with these types of facilities, the Utility has determined that there is more than a remote chance that contracts could be cancelled until the generation facilities have commenced construction.

At March 31, 2012, the undiscounted future expected payment obligations were as follows:

(in millions)
2012	$ 1,810
2013	2,860
2014	3,010
2015	3,007
2016	2,917
Thereafter	32,120
Total	$ 45,724

Costs incurred by the Utility under power purchase agreements amounted to $435 million and $587 million for the three months ended March 31, 2012 and 2011, respectively.

Some of the power purchase agreements that the Utility entered into with independent power producers that are qualifying facilities are treated as capital leases. During the three months ended March 31, 2012, the Utility terminated several agreements with total minimum lease payments of approximately $136 million. As of March 31, 2012, future minimum lease payments associated with capital leases were approximately $115 million.

Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the U.S. 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, the U.S. Rocky Mountain supply area, and the southwestern U.S.) to the points at which the Utility's natural gas transportation system begins. In addition, the Utility has contracted for natural gas storage services in northern California in order to better meet core customers' winter peak loads.

At March 31, 2012, the Utility's undiscounted future expected payment obligations were as follows:

(in millions)
2012	$ 475
2013	331
2014	196
2015	187
2016	153
Thereafter	974
Total	$ 2,316

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage amounted to $378 million and $433 million for the three months ended March 31, 2012 and 2011, 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 nuclear 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 March 31, 2012, the undiscounted future expected payment obligations were as follows:

(in millions)
2012	$ 67
2013	86
2014	127
2015	193
2016	147
Thereafter	1,011
Total	$ 1,631

Payments for nuclear fuel amounted to $19 million and $29 million for the three months ended March 31, 2012 and 2011, respectively.

Other Commitments

In March 2012, the Utility entered into a 10-year facility lease agreement for 250,000 square feet of office space in San Ramon, California. As of March 31, 2012, the future minimum commitment for this operating lease was approximately $67 million.

Contingencies

PG&E Corporation

PG&E Corporation retains a guarantee related to certain obligations of its former subsidiary, National Energy & Gas Transmission, Inc. ("NEGT"), that were issued to the purchaser of an NEGT subsidiary company in 2000. 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 if it were required to satisfy its obligations under this guarantee any required payments would not have a material impact on its financial condition, results of operations, or cash flows.

Utility

Spent Nuclear Fuel Storage Proceedings

Under federal law, the U.S. Department of Energy ("DOE") was required to dispose of spent nuclear fuel and high-level radioactive waste from electric utilities with commercial nuclear power plants no later than January 31, 1998, in exchange for fees paid by the utilities. The DOE failed to meet its contractual obligation to dispose of nuclear waste from the Utility's nuclear generating facility at Diablo Canyon and its retired facility at Humboldt Bay ("Humboldt Bay Unit 3"). As a result, the Utility constructed an interim 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 storage facilities. The Utility sought to recover $92 million of costs that it incurred through 2004. After several years of litigation, the U.S. Court of Federal Claims awarded the Utility $89 million on March 30, 2010. On February 21, 2012, the Federal Circuit Court of Appeals denied the DOE's appeal from May 2010 and affirmed the $89 million award. The deadline for the DOE to petition for a rehearing of the Court's decision is May 21, 2012. The Utility has not recorded any receivable for the award as of March 31, 2012.

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 refunded to customers.

Nuclear Insurance

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

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

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

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

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

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

Legal and Regulatory Contingencies

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits. In addition, 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 loss when it is both probable that a loss 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 losses and record a provision 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 (or reasonably possible losses in excess of the amounts accrued), 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, penalties, and other legal matters (other than third-party claims and penalties related to natural gas matters discussed below) totaled $36 million at March 31, 2012 and $52 million at December 31, 2011 and are 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 and regulatory contingencies would have a material impact on their financial condition, results of operations, or cash flows.

Natural Gas Matters

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 (the "San Bruno accident"). The ensuing explosion and fire resulted in the deaths of eight people, numerous personal injuries, and extensive property damage. Following the San Bruno accident, various regulatory proceedings, investigations, and lawsuits were commenced.

Pending CPUC Investigations and Enforcement Matters

On February 24, 2011, the CPUC commenced an investigation pertaining to safety recordkeeping for Line 132, as well as for the Utility's entire gas transmission system. Among other matters, the investigation will determine whether the San Bruno accident would have been preventable by the exercise of safe procedures and /or accurate and technical recordkeeping in compliance with the law. On March 12, 2012, the CPUC's Consumer Protection and Safety Division ("CPSD") filed testimony that consisted of reports by the CPSD's records management consultant and an engineering consultant. Among other findings, the consultants' reports concluded that: the Utility's recordkeeping practices have been deficient and have diminished pipeline safety; the San Bruno accident may have been prevented had the Utility managed its records properly over the years; and that the Utility has been operating, and continues to operate, without a functional integrity management program. On March 30, 2012, the CPSD filed supplemental testimony to address additional recordkeeping items and to list specific violations the CPSD alleges that the Utility committed based on the findings of the consultants' reports. The Utility's responses to the CPSD's reports are due on June 25, 2012. Evidentiary hearings are scheduled for September 2012 with a final decision expected in February 2013. If the CPUC finds that the Utility has violated any rule, regulation or law, it will schedule a second phase to assess penalties. See "Penalties Conclusion" below.

On November 10, 2011, the CPUC commenced an investigation pertaining to the Utility's operation of its natural gas transmission pipeline system in or near locations of higher population density. Under federal and state regulations, the class location designation of a pipeline is based on the types of buildings, population density, or level of human activity near the segment of pipeline, and is used to determine the maximum allowable operating pressure ("MAOP") up to which a pipeline can be operated. On April 2, 2012, in its second response to the CPUC investigation, the Utility reported that 159 miles of pipeline (as compared to 162 miles previously reported) had a current class location designation that was higher than reflected in the Utility's Geographic Information System. Most of these misclassifications were attributable to the Utility's failure to correctly identify development or well-defined areas near the pipeline. The Utility had also previously determined it had not timely performed a class location study for certain segments and did not confirm the MAOP of those segments for which the Utility had not timely identified a change in class location. The Utility also reported that it could not confirm that all transmission lines were patrolled as required by the Utility's procedures and that the Utility has begun a system-wide review of patrol records for all transmission pipelines. Evidentiary hearings are scheduled for August 2012. See "Penalties Conclusion" below.

On January 12, 2012, the CPUC commenced an investigation to determine whether the Utility violated applicable laws and requirements in connection with the San Bruno accident, as alleged by the CPSD. In its investigation report, the CPSD had alleged that the San Bruno accident was caused by the Utility's failure to follow accepted industry practice when installing the section of pipe that failed, the Utility's failure to comply with federal pipeline integrity management requirements, the Utility's inadequate record keeping practices, deficiencies in the Utility's data collection and reporting system, inadequate procedures to handle emergencies and abnormal conditions, the Utility's deficient emergency response actions after the incident, and a systemic failure of the Utility's corporate culture that emphasized profits over safety. The CPUC stated that the scope of the investigation will include all past operations, practices and other events or courses of conduct that could have led to or contributed to the San Bruno accident, as well as, the Utility's compliance with CPUC orders and resolutions issued since the date of the San Bruno accident. The CPUC noted that the CPSD's investigation is ongoing and the CPSD could raise additional concerns that it could request the CPUC to consider. Evidentiary hearings are scheduled for September and October 2012 with a final decision expected in January 2013. See "Penalties Conclusion" below.

In December 2011, the CPUC delegated authority to its staff to enforce compliance with certain state and federal regulations related to the safety of natural gas facilities and utilities' natural gas operating practices, including the authority to issue citations and impose penalties. The CPUC also established a requirement that California gas corporations provide notice to the CPUC of any self-identified or self-corrected violations of these regulations. Since the citation program was adopted, the Utility has filed 12 self-reports with the CPUC. In one of these self-reports, the Utility reported that it failed to conduct periodic leak surveys because the Utility had not included 16 gas distribution maps in its leak survey schedule. In response to this self-report, the CPSD issued a citation to the Utility that included a penalty of approximately $17 million. On April 19, 2012, the CPUC denied the Utility's appeal of the $17 million penalty and concluded that the CPSD had appropriately determined the number of violations. The Utility was ordered to pay the penalty within 30 days. The CPSD has not yet taken action with respect to the Utility's other self-reports, including a follow-up report stating that the Utility had not considered an additional 46 gas distribution maps in its leak survey schedule. (The Utility has completed all of the missed leak surveys.) The CPSD may issue additional citations and impose penalties on the Utility associated with these or future reports that the Utility may file. See "Penalties Conclusion" below.

Penalties Conclusion

The CPUC can impose penalties of up to $20,000 per day, per violation, for violations of applicable laws, rules, and orders in connection with the pending investigations described above. For violations that are considered to have occurred on or after January 1, 2012, the statutory penalty has increased to a maximum of $50,000 per day, per violation. (Under the CPUC's delegation of authority, the CPSD is required to impose the maximum statutory penalty.) The CPUC and CPSD have wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the number of violations; the length of time the violations existed; the severity of the violations, including the type of harm caused by the violations and the number of persons affected; conduct taken to prevent, detect, disclose or rectify the violations; and the financial resources of the regulated entity. The CPUC has stated that it is prepared to impose very significant penalties if the evidence adduced at hearing establishes that the Utility's policies and practices contributed to the loss of life, injuries, or loss of property resulting from the San Bruno accident.

PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties of at least $200 million on the Utility as a result of these investigations and the Utility's self-reports and have accrued this amount as of March 31, 2012 and December 31, 2011. (The amount accrued included the $17 million penalty described above.) In reaching this conclusion, management has considered, among other factors, the findings and allegations contained in the CPSD's reports; the Utility's self-reports to the CPUC; and the outcome of prior CPUC investigations of other matters. PG&E Corporation and the Utility are unable to estimate the reasonably possible amount of penalties in excess of the amount accrued, and such amounts could be material. The ultimate amount of penalties imposed on the Utility will be affected by many factors, including how many violations the CPUC will find the Utility has committed; whether the penalties will be calculated separately for each matter above or in the aggregate; whether the CPSD issues additional citations based on the Utility's self-reports; and whether and how the CPUC will consider the broader impacts of the San Bruno accident on the Utility's results of operations, financial condition, and cash flows.

The Utility's estimates and assumptions are subject to change as the CPUC investigations progress and more information becomes known, and such changes could have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

Criminal Investigation

The U.S. Department of Justice, the California Attorney General's Office, and the San Mateo County District Attorney's Office are conducting an investigation of the San Bruno accident. The Utility is cooperating with the investigation. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any civil or criminal penalties that could be imposed on the Utility.

Third-Party Claims

Approximately 110 lawsuits involving third-party claims for personal injury and property damage in connection with the San Bruno accident, including two class action lawsuits, have been filed against PG&E Corporation and the Utility on behalf of approximately 380 plaintiffs. The lawsuits seek compensation for these third-party claims and other relief, including punitive damages. These cases have been coordinated and assigned to one judge in the San Mateo County Superior Court. The judge overseeing the coordinated San Bruno accident civil litigation has set a trial date of July 23, 2012 for the first of these lawsuits.

On April 6, 2012, PG&E Corporation and the Utility filed various motions to request that the Court dismiss certain claims, including plaintiffs' claims for punitive damages, based upon a lack of evidence to support such claims. Plaintiffs' oppositions to the motions are due on June 8, 2012. The court will hold a hearing on June 22, 2012 to consider the motions.

As of March 31, 2012, the Utility has incurred a cumulative charge of $375 million for third-party claims and estimates that it is reasonably possible it will incur up to an additional $225 million, for a total possible loss of $600 million. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with punitive damages, if any, related to these matters. As more information becomes known, estimates and assumptions regarding the amount of liability incurred may be subject to further changes. Future changes in estimates may have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows in the period during which they are recorded. The Utility has publicly stated that it is liable for the San Bruno accident and will take financial responsibility to compensate all of the victims for the injuries they suffered as a result of the accident.

The following table presents the changes in third-party claims liability since the San Bruno accident in 2010, which is included in other current liabilities in PG&E Corporation's and the Utility's Condensed Consolidated Balance Sheets:

(in millions)
Balance at January 1, 2010	$ 0
Loss accrued	220
Less: Payments	(6)
Balance at December 31, 2010	214
Additional loss accrued	155
Less: Payments	(92)
Balance at December 31, 2011	277
Less: Payments	(34)
Balance at March 31, 2012	$ 243

Additionally, the Utility has liability insurance from various insurers who provide coverage at different policy limits that are triggered in sequential order or "layers." Generally, as the policy limit for a layer is exhausted the next layer of insurance becomes available. The aggregate amount of this insurance coverage is approximately $992 million in excess of a $10 million deductible. The Utility submitted insurance claims to certain insurers for the lower layers and recognized $11 million for insurance recoveries during the three months ended March 31, 2012. This is in addition to the $99 million recognized for insurance recoveries during 2011. Although the Utility believes 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 future insurance recoveries.

Environmental Remediation Contingencies

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

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

The following table presents the changes in the environmental remediation liability from December 31, 2011:

(in millions)
Balance at December 31, 2011	$ 785
Additional remediation costs accrued:
Transfer to regulatory account for recovery	77
Amounts not recoverable in customer rates	81
Less: Payments	(22)
Balance at March 31, 2012	$ 921

The $921 million accrued at March 31, 2012 consisted of the following:

• $218 million for remediation at the Utility's natural gas compressor site located near Hinkley, California ("Hinkley natural gas compressor site"), as described below;

• $240 million for remediation at the Utility's natural gas compressor site located on the California border, near Topock, Arizona;

• $80 million related to a remediation liability that the Utility retained after selling certain fossil fuel-fired generation facilities in 1998 and 1999;

• $168 million related to remediation costs for the Utility's generation facilities (other than remediation costs for fossil fuel-fired generation), other facilities, and for third-party disposal sites;

• $165 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

• $50 million related to remediation costs for decommissioning fossil fuel-fired generation facilities and sites.

Hinkley Natural Gas Compressor Site

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Hinkley natural gas compressor site. The Utility is also required to take measures to abate the effects of the contamination on the environment. The Utility's remediation and abatement efforts are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region ("Regional Board"). The Regional Board has issued several orders directing the Utility to implement interim remedial measures to reduce the mass of the underground plume of hexavalent chromium, monitor and control movement of the plume, and provide replacement water to affected residents.

In October 2011, the Regional Board ordered the Utility to provide an interim and permanent replacement water system for certain resident households that have domestic wells containing hexavalent chromium concentrations above the 3.1 parts per billion background level. Following the issuance of this order, the Utility filed a petition with the California State Water Resources Control Board ("State Board") to contest certain provisions of the order. On April 9, 2012, the Utility informed the Regional Board that the Utility would provide approximately 300 resident households located up to one mile from the chromium plume boundary with two options for a replacement water supply. Eligible residents may have an individual water treatment system on the property or, where feasible, have a deeper well installed to draw water from a lower aquifer. Alternatively, eligible residents may choose to have the Utility purchase their properties. The Utility expects to begin implementing this program later in 2012. The Utility will continue the program until the State of California has adopted a drinking water standard specifically for hexavalent chromium or for up to five years at which time the program will be evaluated. The Utility has requested the Regional Board's acknowledgement that the Utility's program complies with the October 2011 order.

The Regional Board is also evaluating the Utility's final groundwater remediation plan that proposes using a combination of remedial methods, including using pumped groundwater from extraction wells to irrigate agricultural land and in-situ treatment of the contaminated water. The Regional Board stated it anticipates releasing a draft environmental impact report ("EIR") in the second half of 2012 and that it will consider certification of the final EIR, which will include the final approved remediation plan, by the end of 2012.

As of March 31, 2012, $218 million was accrued in PG&E Corporation's and the Utility's Condensed Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Hinkley natural gas compressor site, compared to $149 million accrued at December 31, 2011. The increase primarily reflects the Utility's best estimate of future probable costs associated with providing water replacement systems to eligible residents or purchasing property from eligible residents, as described above. Remediation costs for the Hinkley natural gas compressor site are not recovered from customers.

Future costs will depend on many factors, including when and whether the Regional Board certifies the final remediation plan, the extent of the groundwater chromium plume, the levels of hexavalent chromium the Utility is required to use as the standard for remediation, and the number of eligible residents who participate in the Utility's program described above. As more information becomes known regarding these factors, estimates and assumptions regarding the amount of liability incurred may be subject to further changes. Future changes in estimates may have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

Reasonably Possible Environmental Contingencies

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, the Utility's undiscounted future costs could increase to as much as $1.6 billion (including amounts related to the Hinkley natural gas compressor site) if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on PG&E Corporation's and the Utility's results of operations during the period in which they are recorded.

Recoveries of Environmental Remediation Costs

The CPUC has authorized the Utility to recover 90% of its hazardous substance remediation costs from customers without a reasonableness review for certain approved sites (excluding any remediation costs associated with the Hinkley natural gas compressor site). The Utility expects to recover $427 million through this ratemaking mechanism. The CPUC has historically authorized the Utility to recover 100% of its remediation costs for decommissioning fossil fuel-fired generation facilities and sites through decommissioning funds collected in rates, and the Utility believes it is probable that it will continue to recover these costs in the future. The Utility expects to recover $50 million through this ratemaking mechanism and an additional $99 million from other ratemaking mechanisms. Finally, the Utility also recovers these costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility's ultimate obligations may be subject to refund to customers.

Tax Matters

In 2008, PG&E Corporation began participating in the Compliance Assurance Process ("CAP"), a real-time Internal Revenue Service ("IRS") audit intended to expedite resolution of tax matters. The CAP audit culminates with a letter from the IRS indicating its acceptance of the return. The IRS partially accepted the 2008 return, withholding two matters for further review. In December 2010, the IRS accepted the 2009 tax return without change. In September 2011, the IRS partially accepted the 2010 return, withholding two matters for further review. The IRS has not completed the CAP audit for 2011.

The most significant of the matters withheld for further review relates to a tax accounting method change filed by PG&E Corporation to accelerate the amount of deductible repairs. In the fourth quarter 2011, the IRS agreed to allow PG&E Corporation to file claims for 2008-2010 for the repairs method change. The IRS has not completed its review of these claims.

The IRS is continuing to work with the utility industry to provide consistent repairs deduction guidance for natural gas transmission, natural gas distribution, and electric generation businesses. PG&E Corporation and the Utility expect the IRS to release this guidance in 2012.

The 2005 through 2007 tax years are currently under Appeals with the IRS. PG&E Corporation expects to complete the Appeals process in 2012. PG&E Corporation believes that the final resolution of open audits will not have a material impact on its financial condition or results of operations.

PG&E Corporation and the Utility are unable to determine the potential impact of future changes to the unrecognized tax benefits at this time.

Pacific Gas And Electric Company [Member]

Commitments And Contingencies

NOTE 10: COMMITMENTS AND CONTINGENCIES

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

Commitments

Third-Party Power Purchase Agreements

As part of the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either gas or electricity at the date of purchase. The Utility's obligations under a significant portion of these agreements are contingent on the third party's development of new generation facilities to provide the power to be purchased by the Utility under these agreements. The table below excludes future expected payments related to agreements ranging from 10 to 25 years in length that are cancellable if the construction of a new generation facility have not met certain contractual milestones with respect to construction. Based on the Utility's experience with these types of facilities, the Utility has determined that there is more than a remote chance that contracts could be cancelled until the generation facilities have commenced construction.

At March 31, 2012, the undiscounted future expected payment obligations were as follows:

(in millions)
2012	$ 1,810
2013	2,860
2014	3,010
2015	3,007
2016	2,917
Thereafter	32,120
Total	$ 45,724

Costs incurred by the Utility under power purchase agreements amounted to $435 million and $587 million for the three months ended March 31, 2012 and 2011, respectively.

Some of the power purchase agreements that the Utility entered into with independent power producers that are qualifying facilities are treated as capital leases. During the three months ended March 31, 2012, the Utility terminated several agreements with total minimum lease payments of approximately $136 million. As of March 31, 2012, future minimum lease payments associated with capital leases were approximately $115 million.

Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the U.S. 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, the U.S. Rocky Mountain supply area, and the southwestern U.S.) to the points at which the Utility's natural gas transportation system begins. In addition, the Utility has contracted for natural gas storage services in northern California in order to better meet core customers' winter peak loads.

At March 31, 2012, the Utility's undiscounted future expected payment obligations were as follows:

(in millions)
2012	$ 475
2013	331
2014	196
2015	187
2016	153
Thereafter	974
Total	$ 2,316

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage amounted to $378 million and $433 million for the three months ended March 31, 2012 and 2011, 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 nuclear 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 March 31, 2012, the undiscounted future expected payment obligations were as follows:

(in millions)
2012	$ 67
2013	86
2014	127
2015	193
2016	147
Thereafter	1,011
Total	$ 1,631

Payments for nuclear fuel amounted to $19 million and $29 million for the three months ended March 31, 2012 and 2011, respectively.

Other Commitments

In March 2012, the Utility entered into a 10-year facility lease agreement for 250,000 square feet of office space in San Ramon, California. As of March 31, 2012, the future minimum commitment for this operating lease was approximately $67 million.

Contingencies

PG&E Corporation

PG&E Corporation retains a guarantee related to certain obligations of its former subsidiary, National Energy & Gas Transmission, Inc. ("NEGT"), that were issued to the purchaser of an NEGT subsidiary company in 2000. 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 if it were required to satisfy its obligations under this guarantee any required payments would not have a material impact on its financial condition, results of operations, or cash flows.

Utility

Spent Nuclear Fuel Storage Proceedings

Under federal law, the U.S. Department of Energy ("DOE") was required to dispose of spent nuclear fuel and high-level radioactive waste from electric utilities with commercial nuclear power plants no later than January 31, 1998, in exchange for fees paid by the utilities. The DOE failed to meet its contractual obligation to dispose of nuclear waste from the Utility's nuclear generating facility at Diablo Canyon and its retired facility at Humboldt Bay ("Humboldt Bay Unit 3"). As a result, the Utility constructed an interim 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 storage facilities. The Utility sought to recover $92 million of costs that it incurred through 2004. After several years of litigation, the U.S. Court of Federal Claims awarded the Utility $89 million on March 30, 2010. On February 21, 2012, the Federal Circuit Court of Appeals denied the DOE's appeal from May 2010 and affirmed the $89 million award. The deadline for the DOE to petition for a rehearing of the Court's decision is May 21, 2012. The Utility has not recorded any receivable for the award as of March 31, 2012.

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 refunded to customers.

Nuclear Insurance

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

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

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

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

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

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

Legal and Regulatory Contingencies

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits. In addition, 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 loss when it is both probable that a loss 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 losses and record a provision 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 (or reasonably possible losses in excess of the amounts accrued), 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, penalties, and other legal matters (other than third-party claims and penalties related to natural gas matters discussed below) totaled $36 million at March 31, 2012 and $52 million at December 31, 2011 and are 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 and regulatory contingencies would have a material impact on their financial condition, results of operations, or cash flows.

Natural Gas Matters

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 (the "San Bruno accident"). The ensuing explosion and fire resulted in the deaths of eight people, numerous personal injuries, and extensive property damage. Following the San Bruno accident, various regulatory proceedings, investigations, and lawsuits were commenced.

Pending CPUC Investigations and Enforcement Matters

On February 24, 2011, the CPUC commenced an investigation pertaining to safety recordkeeping for Line 132, as well as for the Utility's entire gas transmission system. Among other matters, the investigation will determine whether the San Bruno accident would have been preventable by the exercise of safe procedures and /or accurate and technical recordkeeping in compliance with the law. On March 12, 2012, the CPUC's Consumer Protection and Safety Division ("CPSD") filed testimony that consisted of reports by the CPSD's records management consultant and an engineering consultant. Among other findings, the consultants' reports concluded that: the Utility's recordkeeping practices have been deficient and have diminished pipeline safety; the San Bruno accident may have been prevented had the Utility managed its records properly over the years; and that the Utility has been operating, and continues to operate, without a functional integrity management program. On March 30, 2012, the CPSD filed supplemental testimony to address additional recordkeeping items and to list specific violations the CPSD alleges that the Utility committed based on the findings of the consultants' reports. The Utility's responses to the CPSD's reports are due on June 25, 2012. Evidentiary hearings are scheduled for September 2012 with a final decision expected in February 2013. If the CPUC finds that the Utility has violated any rule, regulation or law, it will schedule a second phase to assess penalties. See "Penalties Conclusion" below.

On November 10, 2011, the CPUC commenced an investigation pertaining to the Utility's operation of its natural gas transmission pipeline system in or near locations of higher population density. Under federal and state regulations, the class location designation of a pipeline is based on the types of buildings, population density, or level of human activity near the segment of pipeline, and is used to determine the maximum allowable operating pressure ("MAOP") up to which a pipeline can be operated. On April 2, 2012, in its second response to the CPUC investigation, the Utility reported that 159 miles of pipeline (as compared to 162 miles previously reported) had a current class location designation that was higher than reflected in the Utility's Geographic Information System. Most of these misclassifications were attributable to the Utility's failure to correctly identify development or well-defined areas near the pipeline. The Utility had also previously determined it had not timely performed a class location study for certain segments and did not confirm the MAOP of those segments for which the Utility had not timely identified a change in class location. The Utility also reported that it could not confirm that all transmission lines were patrolled as required by the Utility's procedures and that the Utility has begun a system-wide review of patrol records for all transmission pipelines. Evidentiary hearings are scheduled for August 2012. See "Penalties Conclusion" below.

On January 12, 2012, the CPUC commenced an investigation to determine whether the Utility violated applicable laws and requirements in connection with the San Bruno accident, as alleged by the CPSD. In its investigation report, the CPSD had alleged that the San Bruno accident was caused by the Utility's failure to follow accepted industry practice when installing the section of pipe that failed, the Utility's failure to comply with federal pipeline integrity management requirements, the Utility's inadequate record keeping practices, deficiencies in the Utility's data collection and reporting system, inadequate procedures to handle emergencies and abnormal conditions, the Utility's deficient emergency response actions after the incident, and a systemic failure of the Utility's corporate culture that emphasized profits over safety. The CPUC stated that the scope of the investigation will include all past operations, practices and other events or courses of conduct that could have led to or contributed to the San Bruno accident, as well as, the Utility's compliance with CPUC orders and resolutions issued since the date of the San Bruno accident. The CPUC noted that the CPSD's investigation is ongoing and the CPSD could raise additional concerns that it could request the CPUC to consider. Evidentiary hearings are scheduled for September and October 2012 with a final decision expected in January 2013. See "Penalties Conclusion" below.

In December 2011, the CPUC delegated authority to its staff to enforce compliance with certain state and federal regulations related to the safety of natural gas facilities and utilities' natural gas operating practices, including the authority to issue citations and impose penalties. The CPUC also established a requirement that California gas corporations provide notice to the CPUC of any self-identified or self-corrected violations of these regulations. Since the citation program was adopted, the Utility has filed 12 self-reports with the CPUC. In one of these self-reports, the Utility reported that it failed to conduct periodic leak surveys because the Utility had not included 16 gas distribution maps in its leak survey schedule. In response to this self-report, the CPSD issued a citation to the Utility that included a penalty of approximately $17 million. On April 19, 2012, the CPUC denied the Utility's appeal of the $17 million penalty and concluded that the CPSD had appropriately determined the number of violations. The Utility was ordered to pay the penalty within 30 days. The CPSD has not yet taken action with respect to the Utility's other self-reports, including a follow-up report stating that the Utility had not considered an additional 46 gas distribution maps in its leak survey schedule. (The Utility has completed all of the missed leak surveys.) The CPSD may issue additional citations and impose penalties on the Utility associated with these or future reports that the Utility may file. See "Penalties Conclusion" below.

Penalties Conclusion

The CPUC can impose penalties of up to $20,000 per day, per violation, for violations of applicable laws, rules, and orders in connection with the pending investigations described above. For violations that are considered to have occurred on or after January 1, 2012, the statutory penalty has increased to a maximum of $50,000 per day, per violation. (Under the CPUC's delegation of authority, the CPSD is required to impose the maximum statutory penalty.) The CPUC and CPSD have wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the number of violations; the length of time the violations existed; the severity of the violations, including the type of harm caused by the violations and the number of persons affected; conduct taken to prevent, detect, disclose or rectify the violations; and the financial resources of the regulated entity. The CPUC has stated that it is prepared to impose very significant penalties if the evidence adduced at hearing establishes that the Utility's policies and practices contributed to the loss of life, injuries, or loss of property resulting from the San Bruno accident.

PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties of at least $200 million on the Utility as a result of these investigations and the Utility's self-reports and have accrued this amount as of March 31, 2012 and December 31, 2011. (The amount accrued included the $17 million penalty described above.) In reaching this conclusion, management has considered, among other factors, the findings and allegations contained in the CPSD's reports; the Utility's self-reports to the CPUC; and the outcome of prior CPUC investigations of other matters. PG&E Corporation and the Utility are unable to estimate the reasonably possible amount of penalties in excess of the amount accrued, and such amounts could be material. The ultimate amount of penalties imposed on the Utility will be affected by many factors, including how many violations the CPUC will find the Utility has committed; whether the penalties will be calculated separately for each matter above or in the aggregate; whether the CPSD issues additional citations based on the Utility's self-reports; and whether and how the CPUC will consider the broader impacts of the San Bruno accident on the Utility's results of operations, financial condition, and cash flows.

The Utility's estimates and assumptions are subject to change as the CPUC investigations progress and more information becomes known, and such changes could have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

Criminal Investigation

The U.S. Department of Justice, the California Attorney General's Office, and the San Mateo County District Attorney's Office are conducting an investigation of the San Bruno accident. The Utility is cooperating with the investigation. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any civil or criminal penalties that could be imposed on the Utility.

Third-Party Claims

Approximately 110 lawsuits involving third-party claims for personal injury and property damage in connection with the San Bruno accident, including two class action lawsuits, have been filed against PG&E Corporation and the Utility on behalf of approximately 380 plaintiffs. The lawsuits seek compensation for these third-party claims and other relief, including punitive damages. These cases have been coordinated and assigned to one judge in the San Mateo County Superior Court. The judge overseeing the coordinated San Bruno accident civil litigation has set a trial date of July 23, 2012 for the first of these lawsuits.

On April 6, 2012, PG&E Corporation and the Utility filed various motions to request that the Court dismiss certain claims, including plaintiffs' claims for punitive damages, based upon a lack of evidence to support such claims. Plaintiffs' oppositions to the motions are due on June 8, 2012. The court will hold a hearing on June 22, 2012 to consider the motions.

As of March 31, 2012, the Utility has incurred a cumulative charge of $375 million for third-party claims and estimates that it is reasonably possible it will incur up to an additional $225 million, for a total possible loss of $600 million. PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with punitive damages, if any, related to these matters. As more information becomes known, estimates and assumptions regarding the amount of liability incurred may be subject to further changes. Future changes in estimates may have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows in the period during which they are recorded. The Utility has publicly stated that it is liable for the San Bruno accident and will take financial responsibility to compensate all of the victims for the injuries they suffered as a result of the accident.

The following table presents the changes in third-party claims liability since the San Bruno accident in 2010, which is included in other current liabilities in PG&E Corporation's and the Utility's Condensed Consolidated Balance Sheets:

(in millions)
Balance at January 1, 2010	$ 0
Loss accrued	220
Less: Payments	(6)
Balance at December 31, 2010	214
Additional loss accrued	155
Less: Payments	(92)
Balance at December 31, 2011	277
Less: Payments	(34)
Balance at March 31, 2012	$ 243

Additionally, the Utility has liability insurance from various insurers who provide coverage at different policy limits that are triggered in sequential order or "layers." Generally, as the policy limit for a layer is exhausted the next layer of insurance becomes available. The aggregate amount of this insurance coverage is approximately $992 million in excess of a $10 million deductible. The Utility submitted insurance claims to certain insurers for the lower layers and recognized $11 million for insurance recoveries during the three months ended March 31, 2012. This is in addition to the $99 million recognized for insurance recoveries during 2011. Although the Utility believes 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 future insurance recoveries.

Environmental Remediation Contingencies

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

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

The following table presents the changes in the environmental remediation liability from December 31, 2011:

(in millions)
Balance at December 31, 2011	$ 785
Additional remediation costs accrued:
Transfer to regulatory account for recovery	77
Amounts not recoverable in customer rates	81
Less: Payments	(22)
Balance at March 31, 2012	$ 921

The $921 million accrued at March 31, 2012 consisted of the following:

• $218 million for remediation at the Utility's natural gas compressor site located near Hinkley, California ("Hinkley natural gas compressor site"), as described below;

• $240 million for remediation at the Utility's natural gas compressor site located on the California border, near Topock, Arizona;

• $80 million related to a remediation liability that the Utility retained after selling certain fossil fuel-fired generation facilities in 1998 and 1999;

• $168 million related to remediation costs for the Utility's generation facilities (other than remediation costs for fossil fuel-fired generation), other facilities, and for third-party disposal sites;

• $165 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

• $50 million related to remediation costs for decommissioning fossil fuel-fired generation facilities and sites.

Hinkley Natural Gas Compressor Site

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Hinkley natural gas compressor site. The Utility is also required to take measures to abate the effects of the contamination on the environment. The Utility's remediation and abatement efforts are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region ("Regional Board"). The Regional Board has issued several orders directing the Utility to implement interim remedial measures to reduce the mass of the underground plume of hexavalent chromium, monitor and control movement of the plume, and provide replacement water to affected residents.

In October 2011, the Regional Board ordered the Utility to provide an interim and permanent replacement water system for certain resident households that have domestic wells containing hexavalent chromium concentrations above the 3.1 parts per billion background level. Following the issuance of this order, the Utility filed a petition with the California State Water Resources Control Board ("State Board") to contest certain provisions of the order. On April 9, 2012, the Utility informed the Regional Board that the Utility would provide approximately 300 resident households located up to one mile from the chromium plume boundary with two options for a replacement water supply. Eligible residents may have an individual water treatment system on the property or, where feasible, have a deeper well installed to draw water from a lower aquifer. Alternatively, eligible residents may choose to have the Utility purchase their properties. The Utility expects to begin implementing this program later in 2012. The Utility will continue the program until the State of California has adopted a drinking water standard specifically for hexavalent chromium or for up to five years at which time the program will be evaluated. The Utility has requested the Regional Board's acknowledgement that the Utility's program complies with the October 2011 order.

The Regional Board is also evaluating the Utility's final groundwater remediation plan that proposes using a combination of remedial methods, including using pumped groundwater from extraction wells to irrigate agricultural land and in-situ treatment of the contaminated water. The Regional Board stated it anticipates releasing a draft environmental impact report ("EIR") in the second half of 2012 and that it will consider certification of the final EIR, which will include the final approved remediation plan, by the end of 2012.

As of March 31, 2012, $218 million was accrued in PG&E Corporation's and the Utility's Condensed Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Hinkley natural gas compressor site, compared to $149 million accrued at December 31, 2011. The increase primarily reflects the Utility's best estimate of future probable costs associated with providing water replacement systems to eligible residents or purchasing property from eligible residents, as described above. Remediation costs for the Hinkley natural gas compressor site are not recovered from customers.

Future costs will depend on many factors, including when and whether the Regional Board certifies the final remediation plan, the extent of the groundwater chromium plume, the levels of hexavalent chromium the Utility is required to use as the standard for remediation, and the number of eligible residents who participate in the Utility's program described above. As more information becomes known regarding these factors, estimates and assumptions regarding the amount of liability incurred may be subject to further changes. Future changes in estimates may have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, and cash flows.

Reasonably Possible Environmental Contingencies

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, the Utility's undiscounted future costs could increase to as much as $1.6 billion (including amounts related to the Hinkley natural gas compressor site) if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on PG&E Corporation's and the Utility's results of operations during the period in which they are recorded.

Recoveries of Environmental Remediation Costs

The CPUC has authorized the Utility to recover 90% of its hazardous substance remediation costs from customers without a reasonableness review for certain approved sites (excluding any remediation costs associated with the Hinkley natural gas compressor site). The Utility expects to recover $427 million through this ratemaking mechanism. The CPUC has historically authorized the Utility to recover 100% of its remediation costs for decommissioning fossil fuel-fired generation facilities and sites through decommissioning funds collected in rates, and the Utility believes it is probable that it will continue to recover these costs in the future. The Utility expects to recover $50 million through this ratemaking mechanism and an additional $99 million from other ratemaking mechanisms. Finally, the Utility also recovers these costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility's ultimate obligations may be subject to refund to customers.

Tax Matters

In 2008, PG&E Corporation began participating in the Compliance Assurance Process ("CAP"), a real-time Internal Revenue Service ("IRS") audit intended to expedite resolution of tax matters. The CAP audit culminates with a letter from the IRS indicating its acceptance of the return. The IRS partially accepted the 2008 return, withholding two matters for further review. In December 2010, the IRS accepted the 2009 tax return without change. In September 2011, the IRS partially accepted the 2010 return, withholding two matters for further review. The IRS has not completed the CAP audit for 2011.

The most significant of the matters withheld for further review relates to a tax accounting method change filed by PG&E Corporation to accelerate the amount of deductible repairs. In the fourth quarter 2011, the IRS agreed to allow PG&E Corporation to file claims for 2008-2010 for the repairs method change. The IRS has not completed its review of these claims.

The IRS is continuing to work with the utility industry to provide consistent repairs deduction guidance for natural gas transmission, natural gas distribution, and electric generation businesses. PG&E Corporation and the Utility expect the IRS to release this guidance in 2012.

The 2005 through 2007 tax years are currently under Appeals with the IRS. PG&E Corporation expects to complete the Appeals process in 2012. PG&E Corporation believes that the final resolution of open audits will not have a material impact on its financial condition or results of operations.

PG&E Corporation and the Utility are unable to determine the potential impact of future changes to the unrecognized tax benefits at this time.

XML

Condensed Consolidated Statements Of Comprehensive Income (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Unrecognized prior service credit, income tax	$ 5	$ 5
Unrecognized net gain, income tax	11	6
Unrecognized net transition obligation, income tax	2	2
Transfer to regulatory account, income tax	15	8
Pacific Gas And Electric Company [Member]
Unrecognized prior service credit, income tax	5	5
Unrecognized net gain, income tax	11	6
Unrecognized net transition obligation, income tax	2	2
Transfer to regulatory account, income tax	$ 15	$ 8

XML

Debt

3 Months Ended

Mar. 31, 2012

Debt

NOTE 4: DEBT

Revolving Credit Facilities – PG&E Corporation and the Utility

At March 31, 2012, PG&E Corporation had neither cash borrowings nor letters of credit outstanding under its $300 million revolving credit facility.

At March 31, 2012, the Utility had no cash borrowings and $367 million of letters of credit outstanding under its $3.0 billion revolving credit facility.

At March 31, 2012, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

Utility

Senior Notes

On April 16, 2012, the Utility issued $400 million principal amount of 4.45% Senior Notes due April 15, 2042.

Pollution Control Bonds

At March 31, 2012, the interest rates on the $614 million principal amount of pollution control bonds Series 1996 C, E, F, and 1997 B and the related loan agreements ranged from 0.19% to 0.22%. At March 31, 2012, the interest rates on the $309 million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements ranged from 0.12% to 0.17%.

On April 2, 2012, the Utility repurchased all of the $50 million principal amount of pollution control bonds Series 2010 E that were subject to mandatory tender on that same date. The Utility will hold the bonds until they are remarketed to investors or retired.

Commercial Paper Program

At March 31, 2012, the Utility had $1.1 billion of commercial paper outstanding.

Other Short-Term Borrowings

At March 31, 2012, the interest rate on the Utility's $250 million principal amount of Floating Rate Senior Notes, due November 20, 2012, was 0.94%.

Energy Recovery Bonds

In 2005, PERF issued two separate series of ERBs in the aggregate amount of $2.7 billion to refinance a regulatory asset provided for in the Chapter 11 Settlement Agreement. The proceeds of the ERBs were used by PERF to purchase from the Utility the right (known as "recovery property") to be paid a specified amount from a dedicated rate component ("DRC") to be collected from the Utility's electricity customers. DRC charges are authorized by the CPUC under state legislation and will be paid by the Utility's electricity customers until the ERBs are fully retired. Under the terms of a recovery property servicing agreement, DRC charges are collected by the Utility and remitted to PERF for payment of principal, interest, and miscellaneous expenses associated with the ERBs.

At March 31, 2012, the total amount of ERB principal outstanding was $321 million.

While PERF is a wholly owned consolidated 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.

Pacific Gas And Electric Company [Member]

Debt

NOTE 4: DEBT

Revolving Credit Facilities – PG&E Corporation and the Utility

At March 31, 2012, PG&E Corporation had neither cash borrowings nor letters of credit outstanding under its $300 million revolving credit facility.

At March 31, 2012, the Utility had no cash borrowings and $367 million of letters of credit outstanding under its $3.0 billion revolving credit facility.

At March 31, 2012, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

Utility

Senior Notes

On April 16, 2012, the Utility issued $400 million principal amount of 4.45% Senior Notes due April 15, 2042.

Pollution Control Bonds

At March 31, 2012, the interest rates on the $614 million principal amount of pollution control bonds Series 1996 C, E, F, and 1997 B and the related loan agreements ranged from 0.19% to 0.22%. At March 31, 2012, the interest rates on the $309 million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements ranged from 0.12% to 0.17%.

On April 2, 2012, the Utility repurchased all of the $50 million principal amount of pollution control bonds Series 2010 E that were subject to mandatory tender on that same date. The Utility will hold the bonds until they are remarketed to investors or retired.

Commercial Paper Program

At March 31, 2012, the Utility had $1.1 billion of commercial paper outstanding.

Other Short-Term Borrowings

At March 31, 2012, the interest rate on the Utility's $250 million principal amount of Floating Rate Senior Notes, due November 20, 2012, was 0.94%.

Energy Recovery Bonds

In 2005, PERF issued two separate series of ERBs in the aggregate amount of $2.7 billion to refinance a regulatory asset provided for in the Chapter 11 Settlement Agreement. The proceeds of the ERBs were used by PERF to purchase from the Utility the right (known as "recovery property") to be paid a specified amount from a dedicated rate component ("DRC") to be collected from the Utility's electricity customers. DRC charges are authorized by the CPUC under state legislation and will be paid by the Utility's electricity customers until the ERBs are fully retired. Under the terms of a recovery property servicing agreement, DRC charges are collected by the Utility and remitted to PERF for payment of principal, interest, and miscellaneous expenses associated with the ERBs.

At March 31, 2012, the total amount of ERB principal outstanding was $321 million.

While PERF is a wholly owned consolidated 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.

XML

Regulatory Assets, Liabilities, And Balancing Accounts

3 Months Ended

Mar. 31, 2012

Regulatory Assets, Liabilities, And Balancing Accounts

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 regulatory assets, 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 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 records differences between customer billings and the Utility's authorized revenue requirements since a significant portion of recovery is independent, or "decoupled," from the volume of electricity and natural gas sales. The Utility also records differences between incurred costs and customer billings or authorized revenue requirements meant to recover those costs. To the extent these differences are probable of recovery or refund, the Utility records a regulatory balancing account asset or liability, respectively.

To the extent that portions of the Utility's operations cease to be subject to cost-of-service rate regulation, or recovery is no longer probable as a result of changes in regulations or other reasons, the related regulatory assets and liabilities are written-off.

Regulatory Assets

Current Regulatory Assets

At March 31, 2012 and December 31, 2011, the Utility had current regulatory assets of $1,024 million and $1,090 million, respectively, primarily consisting of price risk management regulatory assets, the Utility's retained generation regulatory assets, the electromechanical meters regulatory asset, and the ERB regulatory asset. The current portion of price risk management regulatory assets of $488 million represents the expected future recovery of unrealized losses related to price risk management derivative instruments over the next 12 months. (See Note 7 below.) The Utility expects to recover these losses as part of its energy procurement costs as they are realized over the next 12 months. The current portion of the Utility's retained generation regulatory assets of $62 million represents the amortization of the underlying generation facilities expected to be recovered over the next 12 months. (See "Long-Term Regulatory Assets" below.) The current portion of the electromechanical meters regulatory asset of $50 million represents the net book value of electromechanical meters expected to be recovered over the next 12 months. (See "Long-Term Regulatory Assets" below). The ERB regulatory asset of $227 million represents the refinancing of a regulatory asset provided for in the Chapter 11 Settlement Agreement. (See Note 4 below.) The Utility expects to fully recover this asset by the end of 2012, when the ERBs mature.

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

	Balance at
(in millions)	March 31, 2012		December 31, 2011
Pension benefits	$	2,939	$	2,899
Deferred income taxes		1,483		1,444
Utility retained generation		598		613
Environmental compliance costs		535		520
Price risk management		354		339
Electromechanical meters		234		247
Unamortized loss, net of gain, on reacquired debt		157		163
Other		265		281
Total long-term regulatory assets	$	6,565	$	6,506

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 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 2011 Annual Report.)

The regulatory asset for deferred income taxes represents 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. Based on current regulatory ratemaking and income tax laws, the Utility expects to recover the regulatory asset over the average plant depreciation lives of 1 to 44 years.

In connection with the 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 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 environmental compliance costs represents 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.)

The regulatory asset for price risk management represents the expected future recovery of unrealized losses related to price risk management derivative instruments beyond the next 12 months. The Utility expects to recover these losses as they are realized over the next 10 years. (See Note 7 below.)

The regulatory asset for electromechanical meters represents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter™ devices. The Utility expects to recover the regulatory asset over the next four years.

The regulatory asset for unamortized loss, net of gain, on reacquired debt represents the expected future recovery of 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 14 years, which is the remaining amortization period of the reacquired debt. The Utility expects to fully recover these costs by 2026.

At March 31, 2012 and December 31, 2011, "other" primarily consisted of regulatory assets related to ARO expenses for the decommissioning of the Utility's fossil fuel-fired generation facilities that are probable of future recovery through rates, costs that the Utility incurred in terminating a 30-year power purchase agreement that are amortized and collected in rates through September 2014, and costs incurred related to the Utility's plan of reorganization under Chapter 11 that became effective in April 2004 and are amortized and collected in rates through April 2034.

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

Regulatory Liabilities

Current Regulatory Liabilities

At March 31, 2012 and December 31, 2011, the Utility had current regulatory liabilities of $83 million and $161 million, respectively, primarily consisting of amounts that the Utility expects to refund to customers under electricity supplier settlement agreements. (See Note 9 below.) Current regulatory liabilities are included within current liabilities – other in the Condensed Consolidated Balance Sheets.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

	Balance at
(in millions)	March 31, 2012		December 31, 2011
Cost of removal obligations		$ 3,524		$ 3,460
Recoveries in excess of AROs		707		611
Public purpose programs		526		499
Other		170		163
Total long-term regulatory liabilities		$ 4,927		$ 4,733

The regulatory liability for cost of removal obligations represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.

The regulatory liability for recoveries in excess of AROs represents the cumulative differences between ARO expenses and amounts collected in rates primarily for the decommissioning of the Utility's nuclear power facilities. Decommissioning costs recovered through rates are primarily placed in nuclear decommissioning trusts. The regulatory liability also represents the deferral of realized and unrealized gains and losses on the nuclear decommissioning trust investments. (See Note 8 below.)

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, primarily related to energy efficiency programs designed to encourage the manufacture, design, distribution, and customer-use of energy efficient appliances and other energy-using products, the California Solar Initiative program to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties, and the Self-Generation Incentive program to promote distributed generation technologies installed on the customer's side of the utility meter.

At March 31, 2012 and December 31, 2011, "other" 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 and price risk management regulatory liabilities representing the expected future refund to customers 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 collected from or refunded to customers through authorized rate adjustments over the next 12 months. Regulatory balancing accounts that the Utility does not expect to collect or refund over the next 12 months are included in other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Condensed Consolidated Balance Sheets.

Current Regulatory Balancing Accounts, Net

	Receivable (Payable)
	Balance at
(in millions)	March 31, 2012			December 31, 2011
Distribution revenue adjustment mechanism		$ 422			$ 223
Utility generation		412			241
Public purpose programs		96			97
Hazardous substance		56			57
Gas fixed cost		(101	)		16
Energy recovery bonds		(108	)		(105	)
Energy procurement		(129	)		(48	)
Other		136			227
Total regulatory balancing accounts, net		$ 784			$ 708

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 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 recovery of these revenue requirements is decoupled from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers fluctuates 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 a lower volume of electricity sales and lower rates. During the warmer months of summer, there is generally an over-collection due to a higher volume of electricity sales and higher rates.

The public purpose programs balancing accounts are primarily used to record and recover 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 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 record and recover hazardous substance remediation costs. A CPUC-approved ratemaking mechanism authorizes the Utility to recover 90% of such costs for certain sites. The balance represents eligible costs incurred by the Utility that are expected to be recovered over the next 12 months. (See Note 10 below.)

The gas fixed cost balancing account is used to record and recover authorized gas distribution revenue requirements and certain other gas distribution-related authorized costs. Similar to the utility generation and the distribution revenue adjustment mechanism balancing accounts discussed above, the recovery of these revenue requirements is decoupled from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers fluctuates depending on the volume of gas sales. During the colder months of winter, there is generally an over-collection in this balancing account primarily due to higher natural gas sales. During the warmer months of summer, there is generally an under-collection primarily due to lower natural gas sales.

The ERBs balancing account is used to record and refund to customers the net refunds, claim offsets, and other credits received by the Utility from electricity suppliers related to the Chapter 11 disputed claims and to record and recover authorized ERB servicing costs. (See Note 9 below.)

The Utility is generally authorized to recover 100% of its prudently incurred 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 over the following year. The Utility's electric rates are set to recover such expected costs.

At March 31, 2012 and December 31, 2011, "other" consisted of various balancing accounts, such as the SmartMeter^TM advanced metering project balancing account, which tracks the recovery of the related authorized revenue requirements and costs, and balancing accounts that track the recovery of authorized meter reading costs.

Pacific Gas And Electric Company [Member]

Regulatory Assets, Liabilities, And Balancing Accounts

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 regulatory assets, 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 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 records differences between customer billings and the Utility's authorized revenue requirements since a significant portion of recovery is independent, or "decoupled," from the volume of electricity and natural gas sales. The Utility also records differences between incurred costs and customer billings or authorized revenue requirements meant to recover those costs. To the extent these differences are probable of recovery or refund, the Utility records a regulatory balancing account asset or liability, respectively.

To the extent that portions of the Utility's operations cease to be subject to cost-of-service rate regulation, or recovery is no longer probable as a result of changes in regulations or other reasons, the related regulatory assets and liabilities are written-off.

Regulatory Assets

Current Regulatory Assets

At March 31, 2012 and December 31, 2011, the Utility had current regulatory assets of $1,024 million and $1,090 million, respectively, primarily consisting of price risk management regulatory assets, the Utility's retained generation regulatory assets, the electromechanical meters regulatory asset, and the ERB regulatory asset. The current portion of price risk management regulatory assets of $488 million represents the expected future recovery of unrealized losses related to price risk management derivative instruments over the next 12 months. (See Note 7 below.) The Utility expects to recover these losses as part of its energy procurement costs as they are realized over the next 12 months. The current portion of the Utility's retained generation regulatory assets of $62 million represents the amortization of the underlying generation facilities expected to be recovered over the next 12 months. (See "Long-Term Regulatory Assets" below.) The current portion of the electromechanical meters regulatory asset of $50 million represents the net book value of electromechanical meters expected to be recovered over the next 12 months. (See "Long-Term Regulatory Assets" below). The ERB regulatory asset of $227 million represents the refinancing of a regulatory asset provided for in the Chapter 11 Settlement Agreement. (See Note 4 below.) The Utility expects to fully recover this asset by the end of 2012, when the ERBs mature.

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

	Balance at
(in millions)	March 31, 2012		December 31, 2011
Pension benefits	$	2,939	$	2,899
Deferred income taxes		1,483		1,444
Utility retained generation		598		613
Environmental compliance costs		535		520
Price risk management		354		339
Electromechanical meters		234		247
Unamortized loss, net of gain, on reacquired debt		157		163
Other		265		281
Total long-term regulatory assets	$	6,565	$	6,506

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 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 2011 Annual Report.)

The regulatory asset for deferred income taxes represents 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. Based on current regulatory ratemaking and income tax laws, the Utility expects to recover the regulatory asset over the average plant depreciation lives of 1 to 44 years.

In connection with the 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 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 environmental compliance costs represents 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.)

The regulatory asset for price risk management represents the expected future recovery of unrealized losses related to price risk management derivative instruments beyond the next 12 months. The Utility expects to recover these losses as they are realized over the next 10 years. (See Note 7 below.)

The regulatory asset for electromechanical meters represents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter devices. The Utility expects to recover the regulatory asset over the next four years.

The regulatory asset for unamortized loss, net of gain, on reacquired debt represents the expected future recovery of 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 14 years, which is the remaining amortization period of the reacquired debt. The Utility expects to fully recover these costs by 2026.

At March 31, 2012 and December 31, 2011, "other" primarily consisted of regulatory assets related to ARO expenses for the decommissioning of the Utility's fossil fuel-fired generation facilities that are probable of future recovery through rates, costs that the Utility incurred in terminating a 30-year power purchase agreement that are amortized and collected in rates through September 2014, and costs incurred related to the Utility's plan of reorganization under Chapter 11 that became effective in April 2004 and are amortized and collected in rates through April 2034.

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

Regulatory Liabilities

Current Regulatory Liabilities

At March 31, 2012 and December 31, 2011, the Utility had current regulatory liabilities of $83 million and $161 million, respectively, primarily consisting of amounts that the Utility expects to refund to customers under electricity supplier settlement agreements. (See Note 9 below.) Current regulatory liabilities are included within current liabilities other in the Condensed Consolidated Balance Sheets.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

	Balance at
(in millions)	March 31, 2012		December 31, 2011
Cost of removal obligations		$ 3,524		$ 3,460
Recoveries in excess of AROs		707		611
Public purpose programs		526		499
Other		170		163
Total long-term regulatory liabilities		$ 4,927		$ 4,733

The regulatory liability for cost of removal obligations represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.

The regulatory liability for recoveries in excess of AROs represents the cumulative differences between ARO expenses and amounts collected in rates primarily for the decommissioning of the Utility's nuclear power facilities. Decommissioning costs recovered through rates are primarily placed in nuclear decommissioning trusts. The regulatory liability also represents the deferral of realized and unrealized gains and losses on the nuclear decommissioning trust investments. (See Note 8 below.)

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, primarily related to energy efficiency programs designed to encourage the manufacture, design, distribution, and customer-use of energy efficient appliances and other energy-using products, the California Solar Initiative program to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties, and the Self-Generation Incentive program to promote distributed generation technologies installed on the customer's side of the utility meter.

At March 31, 2012 and December 31, 2011, "other" 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 and price risk management regulatory liabilities representing the expected future refund to customers 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 collected from or refunded to customers through authorized rate adjustments over the next 12 months. Regulatory balancing accounts that the Utility does not expect to collect or refund over the next 12 months are included in other noncurrent assets regulatory assets or noncurrent liabilities regulatory liabilities, respectively, in the Condensed Consolidated Balance Sheets.

Current Regulatory Balancing Accounts, Net

	Receivable (Payable)
	Balance at
(in millions)	March 31, 2012			December 31, 2011
Distribution revenue adjustment mechanism		$ 422			$ 223
Utility generation		412			241
Public purpose programs		96			97
Hazardous substance		56			57
Gas fixed cost		(101	)		16
Energy recovery bonds		(108	)		(105	)
Energy procurement		(129	)		(48	)
Other		136			227
Total regulatory balancing accounts, net		$ 784			$ 708

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 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 recovery of these revenue requirements is decoupled from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers fluctuates 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 a lower volume of electricity sales and lower rates. During the warmer months of summer, there is generally an over-collection due to a higher volume of electricity sales and higher rates.

The public purpose programs balancing accounts are primarily used to record and recover 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 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 record and recover hazardous substance remediation costs. A CPUC-approved ratemaking mechanism authorizes the Utility to recover 90% of such costs for certain sites. The balance represents eligible costs incurred by the Utility that are expected to be recovered over the next 12 months. (See Note 10 below.)

The gas fixed cost balancing account is used to record and recover authorized gas distribution revenue requirements and certain other gas distribution-related authorized costs. Similar to the utility generation and the distribution revenue adjustment mechanism balancing accounts discussed above, the recovery of these revenue requirements is decoupled from the volume of sales; therefore, the Utility recognizes revenue evenly over the year, even though the level of cash collected from customers fluctuates depending on the volume of gas sales. During the colder months of winter, there is generally an over-collection in this balancing account primarily due to higher natural gas sales. During the warmer months of summer, there is generally an under-collection primarily due to lower natural gas sales.

The ERBs balancing account is used to record and refund to customers the net refunds, claim offsets, and other credits received by the Utility from electricity suppliers related to the Chapter 11 disputed claims and to record and recover authorized ERB servicing costs. (See Note 9 below.)

The Utility is generally authorized to recover 100% of its prudently incurred 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 over the following year. The Utility's electric rates are set to recover such expected costs.

At March 31, 2012 and December 31, 2011, "other" consisted of various balancing accounts, such as the SmartMeter^TM advanced metering project balancing account, which tracks the recovery of the related authorized revenue requirements and costs, and balancing accounts that track the recovery of authorized meter reading costs.

XML

Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2012

Earnings Per Share [Abstract]

Reconciliation Of PG&E Corporation's Income Available For Common Shareholders And Weighted Average Common Shares Outstanding For Calculating Diluted EPS

	Three Months Ended
	March 31,
(in millions, except per share amounts)	2012		2011
Diluted
Income available for common shareholders	$	233	$	199
Weighted average common shares outstanding, basic		414		396
Add incremental shares from assumed conversions:
Employee share-based compensation		2		1
Weighted average common shares outstanding, diluted		416		397
Total earnings per common share, diluted	$	0.56	$	0.50

XML

New And Significant Accounting Policies (Policy)

3 Months Ended

Mar. 31, 2012

New And Significant Accounting Policies [Abstract]

Pension And Other Postretirement Benefits

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") and 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 have elected that certain of the trusts underlying these plans be treated under the Internal Revenue Code ("Code") as qualified trusts. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain Code limitations. PG&E Corporation and the Utility use a December 31 measurement date for all plans.

Net periodic benefit cost as reflected in PG&E Corporation's Condensed Consolidated Statements of Income for the three months ended March 31, 2012 and 2011 is as follows:

	Pension Benefits						Other Benefits
	Three Months Ended March 31,						Three Months Ended March 31,
(in millions)	2012			2011			2012			2011
Service cost for benefits earned	$	99		$	82		$	12		$	11
Interest cost		164			164			21			23
Expected return on plan assets		(149	)		(167	)		(19	)		(20	)
Amortization of transition obligation		-			-			6			6
Amortization of prior service cost		5			9			6			6
Amortization of unrecognized loss		31			12			1			1
Net periodic benefit cost		150			100			27			27
Less: transfer to regulatory account (1)		(75	)		(36	)		-			-
Total	$	75		$	64		$	27		$	27

⁽¹⁾  The Utility recorded $75 million and $36 million for the three months ended March 31, 2012 and 2011, 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 and the Utility for the information disclosed above.

Variable Interest Entities

Variable Interest Entities

PG&E Corporation and the Utility evaluate whether any entity is a variable interest entity ("VIE") that could require consolidation. PG&E Corporation and the Utility use a qualitative approach to determine who has a controlling financial interest in a VIE and perform ongoing assessments of whether an entity is the primary beneficiary of a VIE.

PG&E Corporation and the Utility are required to consolidate any entities that they control. In most cases, control can be determined based on majority ownership or voting interests. However, for certain entities, control is difficult to discern based on ownership or voting interests alone. These entities are referred to as VIEs. A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise has a controlling financial interest if it has the obligation to absorb expected losses or receive expected gains that could potentially be significant to a VIE and the power to direct the activities that are most significant to a VIE's economic performance. An enterprise that has a controlling financial interest is known as the VIE's primary beneficiary and is required to consolidate the VIE.

Some of the counterparties to the Utility's power purchase agreements are considered VIEs. In determining whether the Utility has a controlling financial interest in a VIE, the Utility assesses whether it absorbs any of the VIE's expected losses or receives any portion of the VIE's expected residual returns, as a result of the power purchase agreement. This assessment includes an evaluation of how the risks and rewards associated with the power plant's activities are absorbed by variable interest holders, as well as an analysis of the variability in the VIE's gross margin and the impact of the power purchase agreement on the gross margin. For each variable interest, the Utility assesses whether it has the power to direct the activities of the power plant that most directly impact the VIE's economic performance.

The Utility can hold a variable interest in entities that own power plants that generate electricity for sale to the Utility under power purchase agreements. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility utilizing various technologies such as natural gas, wind, solar photovoltaic, solar thermal, and hydroelectric. Under each of these power purchase agreements, the Utility is obligated to purchase electricity or capacity, or both, from the VIE. The Utility does not provide any other support to these VIEs, and the Utility's financial exposure is limited to the amount it pays for delivered electricity and capacity. (See Note 10 below.) The Utility does not have the power to direct the activities that are most significant to these VIE's economic performance. This assessment considers 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. As a result, the Utility does not have a controlling financial interest in any of these VIEs. Therefore, at March 31, 2012, the Utility was not the primary beneficiary of, and did not consolidate, any of these VIEs.

The Utility continued to consolidate PG&E Energy Recovery Funding LLC ("PERF") at March 31, 2012, as the Utility is the primary beneficiary of PERF. In 2005, PERF was formed as a wholly owned subsidiary of the Utility to issue energy recovery bonds ("ERB"s) in connection with the settlement agreement entered into between PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the remaining disputed claims made by electricity suppliers in the Utility's proceeding under Chapter 11 of the U.S. Bankruptcy Code ("Chapter 11 Settlement Agreement"). The Utility has a controlling financial interest in PERF since 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, which was an activity that was significant to PERF's economic performance. The assets of PERF were $382 million at March 31, 2012 and primarily consisted of assets related to ERBs, which are included in other current assets – regulatory assets in the Condensed Consolidated Balance Sheets. The liabilities of PERF were $321 million at March 31, 2012 and consisted of ERBs, which are included in current liabilities in the Condensed Consolidated Balance Sheets. (See Note 4 below.)

As of March 31, 2012, PG&E Corporation 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 $396 million to these companies in exchange for the right to receive benefits from local rebates, federal 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 March 31, 2012, PG&E Corporation had made total payments of $360 million under these agreements and received $160 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 March 31, 2012. 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 agreements is generally limited to its lease payments and investment contributions to these companies.

XML

Derivatives

3 Months Ended

Mar. 31, 2012

Derivatives

NOTE 7: DERIVATIVES

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 costs related to price risk management activities.

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 and option contracts that require payments from counterparties if market prices exceed a predetermined price.

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

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. As long as the current 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, in rates, all costs related to derivatives. 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 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 or refund to customers.

The Utility elects the normal purchase and sale exception for qualifying derivatives. Derivatives that require 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 derivatives that are eligible for the normal purchase and sales exception are not reflected in the Condensed Consolidated Balance Sheets.

Electricity Procurement

The Utility enters into third-party power purchase agreements for 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 derivatives. The Utility elects the normal purchase and sale exception for eligible derivatives.

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

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. The CAISO imposes congestion charges on market participants to manage transmission congestion. The revenue generated from congestion charges is allocated to holders of congestion revenue rights ("CRR"s). CRRs 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. CRRs are considered derivatives.

Natural Gas Procurement (Electric Fuels Portfolio)

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

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 natural 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 natural gas prices during peak winter months. These financial instruments are considered derivatives.

Volume of Derivative Activity

At March 31, 2012, the volumes of PG&E Corporation's and the Utility's outstanding derivatives 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		439,441,427		166,878,481		4,280,000		-
	Options		231,380,020		280,200,000		-		-
Electricity (Megawatt-hours)	Forwards and Swaps		4,141,223		4,696,221		2,009,505		3,421,832
	Options		1,248,000		140,510		239,233		218,013
	Congestion Revenue Rights		75,532,338		73,123,024		73,190,271		54,209,541

⁽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 2017 and 2022.

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

⁽⁴⁾ Million British Thermal Units.

Presentation of Derivative Instruments in the Financial Statements

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

At March 31, 2012, PG&E Corporation's and the Utility's outstanding derivative balances were as follows:

	Gross  Derivative Balance			Netting			Cash Collateral		Total  Derivative Balance
(in millions)	Commodity Risk (PG&E Corporation and the Utility)
Current assets – other		$ 42			$ (27	)		$ 97		$ 112
Other noncurrent assets – other		96			(43	)		-		53
Current liabilities – other		(515	)		27			318		(170	)
Noncurrent liabilities – other		(397	)		43			101		(253	)
Total commodity risk		$ (774	)		$ -			$ 516		$ (258	)

At December 31, 2011, PG&E Corporation's and the Utility's outstanding derivative balances were as follows:

		$0000.0			$0000.0			$0000.0		$0000.0
	Gross  Derivative Balance			Netting			Cash Collateral		Total  Derivative Balance
(in millions)	Commodity Risk (PG&E Corporation and the Utility)
Current assets – other		$ 54			$ (39	)		$ 103		$ 118
Other noncurrent assets – other		113			(59	)		-		54
Current liabilities – other		(489	)		39			274		(176	)
Noncurrent liabilities – other		(398	)		59			101		(238	)
Total commodity risk		$ (720	)		$ -			$ 478		$ (242	)

Gains and losses recorded on PG&E Corporation's and the Utility's derivatives were as follows:

	Commodity Risk (PG&E  Corporation and Utility)
	Three months ended March 31,
(in millions)	2012			2011
Unrealized (loss) gain – regulatory assets and liabilities (1)		$ (54	)		$ 137
Realized loss – cost of electricity (2)		(151	)		(136	)
Realized loss – cost of natural gas (2)		(22	)		(55	)
Total commodity risk instruments		$ (227	)		$ (54	)

⁽¹⁾  Unrealized gains and losses on derivatives are deferred 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 recovered from customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.

Cash inflows and outflows associated with derivatives 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 derivatives contain collateral posting provisions tied to the Utility's credit rating from each of the major credit rating agencies. As of March 31, 2012, 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 post immediately additional cash to collateralize fully some of its net liability derivative positions.

At March 31, 2012, the additional cash collateral that the Utility would be required to post if the 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	$ (134	)
Related derivatives in an asset position	2
Collateral posting in the normal course of business related to these derivatives	33
Net position of derivative contracts/additional collateral posting requirements (1)	$ (99	)

⁽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.

Pacific Gas And Electric Company [Member]

Derivatives

NOTE 7: DERIVATIVES

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 costs related to price risk management activities.

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 and option contracts that require payments from counterparties if market prices exceed a predetermined price.

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

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. As long as the current 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, in rates, all costs related to derivatives. 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 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 or refund to customers.

The Utility elects the normal purchase and sale exception for qualifying derivatives. Derivatives that require 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 derivatives that are eligible for the normal purchase and sales exception are not reflected in the Condensed Consolidated Balance Sheets.

Electricity Procurement

The Utility enters into third-party power purchase agreements for 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 derivatives. The Utility elects the normal purchase and sale exception for eligible derivatives.

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

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. The CAISO imposes congestion charges on market participants to manage transmission congestion. The revenue generated from congestion charges is allocated to holders of congestion revenue rights ("CRR"s). CRRs 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. CRRs are considered derivatives.

Natural Gas Procurement (Electric Fuels Portfolio)

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

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 natural 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 natural gas prices during peak winter months. These financial instruments are considered derivatives.

Volume of Derivative Activity

At March 31, 2012, the volumes of PG&E Corporation's and the Utility's outstanding derivatives 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		439,441,427		166,878,481		4,280,000		-
	Options		231,380,020		280,200,000		-		-
Electricity (Megawatt-hours)	Forwards and Swaps		4,141,223		4,696,221		2,009,505		3,421,832
	Options		1,248,000		140,510		239,233		218,013
	Congestion Revenue Rights		75,532,338		73,123,024		73,190,271		54,209,541

⁽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 2017 and 2022.

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

⁽⁴⁾ Million British Thermal Units.

Presentation of Derivative Instruments in the Financial Statements

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

At March 31, 2012, PG&E Corporation's and the Utility's outstanding derivative balances were as follows:

	Gross  Derivative Balance			Netting			Cash Collateral		Total  Derivative Balance
(in millions)	Commodity Risk (PG&E Corporation and the Utility)
Current assets – other		$ 42			$ (27	)		$ 97		$ 112
Other noncurrent assets – other		96			(43	)		-		53
Current liabilities – other		(515	)		27			318		(170	)
Noncurrent liabilities – other		(397	)		43			101		(253	)
Total commodity risk		$ (774	)		$ -			$ 516		$ (258	)

At December 31, 2011, PG&E Corporation's and the Utility's outstanding derivative balances were as follows:

		$0000.0			$0000.0			$0000.0		$0000.0
	Gross  Derivative Balance			Netting			Cash Collateral		Total  Derivative Balance
(in millions)	Commodity Risk (PG&E Corporation and the Utility)
Current assets – other		$ 54			$ (39	)		$ 103		$ 118
Other noncurrent assets – other		113			(59	)		-		54
Current liabilities – other		(489	)		39			274		(176	)
Noncurrent liabilities – other		(398	)		59			101		(238	)
Total commodity risk		$ (720	)		$ -			$ 478		$ (242	)

Gains and losses recorded on PG&E Corporation's and the Utility's derivatives were as follows:

	Commodity Risk (PG&E  Corporation and Utility)
	Three months ended March 31,
(in millions)	2012			2011
Unrealized (loss) gain – regulatory assets and liabilities (1)		$ (54	)		$ 137
Realized loss – cost of electricity (2)		(151	)		(136	)
Realized loss – cost of natural gas (2)		(22	)		(55	)
Total commodity risk instruments		$ (227	)		$ (54	)

⁽¹⁾ Unrealized gains and losses on derivatives are deferred 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 recovered from customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.

Cash inflows and outflows associated with derivatives 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 derivatives contain collateral posting provisions tied to the Utility's credit rating from each of the major credit rating agencies. As of March 31, 2012, 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 post immediately additional cash to collateralize fully some of its net liability derivative positions.

At March 31, 2012, the additional cash collateral that the Utility would be required to post if the 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	$ (134	)
Related derivatives in an asset position	2
Collateral posting in the normal course of business related to these derivatives	33
Net position of derivative contracts/additional collateral posting requirements (1)	$ (99	)

⁽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.

XML

Equity

3 Months Ended

Mar. 31, 2012

Equity

NOTE 5: EQUITY

PG&E Corporation's and the Utility's changes in equity for the three months ended March 31, 2012 were as follows:

	PG&E Corporation			Utility
(in millions)	Total Equity			Total Shareholders'  Equity
Balance at December 31, 2011		$ 12,353			$ 12,384
Comprehensive income		246			241
Common stock issued		393			-
Share-based compensation expense		16			-
Common stock dividends declared		(193	)		(179	)
Preferred stock dividend requirement		-			(3	)
Preferred stock dividend requirement of subsidiary		(3	)		-
Equity contributions		-			385
Balance at March 31, 2012		$ 12,812			$ 12,828

During the three months ended March 31, 2012, PG&E Corporation issued 3,363,617 shares of its common stock under the Equity Distribution Agreement executed in November 2011, its 401(k) plan, its Dividend Reinvestment and Stock Purchase Plan, and upon exercises of employee stock options for total cash proceeds of $133 million, net of fees and commissions of $1 million. At March 31, 2012, PG&E Corporation had the ability to issue an additional $219 million of its common stock under the Equity Distribution Agreement.

On March 20, 2012, PG&E Corporation sold 5,900,000 shares of its common stock in an underwritten public offering for cash proceeds of $254 million, net of fees and commissions.

During the three months ended March 31, 2012, PG&E Corporation contributed equity of $385 million to the Utility to maintain its CPUC-authorized capital structure, which consists of 52% common equity and 48% debt and preferred stock.

Pacific Gas And Electric Company [Member]

Equity

NOTE 5: EQUITY

PG&E Corporation's and the Utility's changes in equity for the three months ended March 31, 2012 were as follows:

	PG&E Corporation			Utility
(in millions)	Total Equity			Total Shareholders'  Equity
Balance at December 31, 2011		$ 12,353			$ 12,384
Comprehensive income		246			241
Common stock issued		393			-
Share-based compensation expense		16			-
Common stock dividends declared		(193	)		(179	)
Preferred stock dividend requirement		-			(3	)
Preferred stock dividend requirement of subsidiary		(3	)		-
Equity contributions		-			385
Balance at March 31, 2012		$ 12,812			$ 12,828

During the three months ended March 31, 2012, PG&E Corporation issued 3,363,617 shares of its common stock under the Equity Distribution Agreement executed in November 2011, its 401(k) plan, its Dividend Reinvestment and Stock Purchase Plan, and upon exercises of employee stock options for total cash proceeds of $133 million, net of fees and commissions of $1 million. At March 31, 2012, PG&E Corporation had the ability to issue an additional $219 million of its common stock under the Equity Distribution Agreement.

On March 20, 2012, PG&E Corporation sold 5,900,000 shares of its common stock in an underwritten public offering for cash proceeds of $254 million, net of fees and commissions.

During the three months ended March 31, 2012, PG&E Corporation contributed equity of $385 million to the Utility to maintain its CPUC-authorized capital structure, which consists of 52% common equity and 48% debt and preferred stock.

XML

Earnings Per Share

3 Months Ended

Mar. 31, 2012

Earnings Per Share

NOTE 6: EARNINGS PER SHARE

PG&E Corporation's basic earnings per common share ("EPS") is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation's income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS:

	Three Months Ended
	March 31,
(in millions, except per share amounts)	2012		2011
Diluted
Income available for common shareholders	$	233	$	199
Weighted average common shares outstanding, basic		414		396
Add incremental shares from assumed conversions:
Employee share-based compensation		2		1
Weighted average common shares outstanding, diluted		416		397
Total earnings per common share, diluted	$	0.56	$	0.50

For each of the periods presented above, options and securities that were antidilutive were immaterial.

Pacific Gas And Electric Company [Member]

Earnings Per Share

NOTE 6: EARNINGS PER SHARE

PG&E Corporation's basic earnings per common share ("EPS") is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation's income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS:

	Three Months Ended
	March 31,
(in millions, except per share amounts)	2012		2011
Diluted
Income available for common shareholders	$	233	$	199
Weighted average common shares outstanding, basic		414		396
Add incremental shares from assumed conversions:
Employee share-based compensation		2		1
Weighted average common shares outstanding, diluted		416		397
Total earnings per common share, diluted	$	0.56	$	0.50

For each of the periods presented above, options and securities that were antidilutive were immaterial.

XML

Fair Value Measurements

3 Months Ended

Mar. 31, 2012

Fair Value Measurements

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.

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):

	Fair Value Measurements
	At March 31, 2012											At December 31, 2011
(in millions)	Level 1		Level 2		Level 3		Netting (1)			Total		Level 1		Level 2		Level 3		Netting (1)			Total
Assets:
Money market investments		$ 206		$ -		$ -		$ -			$ 206		$ 206		$ -		$ -		$ -			$ 206
Nuclear decommissioning trusts
U.S. equity securities		925		9		-		-			934		841		8		-		-			849
Non-U.S. equity securities		358		-		-		-			358		323		-		-		-			323
U.S. government and agency securities		734		138		-		-			872		744		156		-		-			900
Municipal securities		-		68		-		-			68		-		58		-		-			58
Other fixed-income securities		-		150		-		-			150		-		99		-		-			99
Total nuclear decommissioning trusts (2)		2,017		365		-		-			2,382		1,908		321		-		-			2,229
Price risk management instruments (Note 7)
Electricity		-		68		67		27			162		-		92		69		8			169
Gas		-		3		-		-			3		-		6		-		(3	)		3
Total price risk management instruments		-		71		67		27			165		-		98		69		5			172
Rabbi trusts
Fixed-income securities		-		26		-		-			26		-		25		-		-			25
Life insurance contracts		-		68		-		-			68		-		67		-		-			67
Total rabbi trusts		-		94		-		-			94		-		92		-		-			92
Long-term disability trust
U.S. equity securities		5		13		-		-			18		13		15		-		-			28
Non-U.S. equity securities		-		15		-		-			15		-		9		-		-			9
Fixed-income securities		-		142		-		-			142		-		145		-		-			145
Total long-term disability trust		5		170		-		-			175		13		169		-		-			182
Total assets		$ 2,228		$ 700		$ 67		$ 27			$ 3,022		$ 2,127		$ 680		$ 69		$ 5			$ 2,881
Liabilities:
Price risk management instruments (Note 7)
Electricity		$ 436		$ 284		$ 166		$ (471	)		$ 415		$ 411		$ 289		$ 143		$ (441	)		$ 402
Gas		15		11		-		(18	)		8		31		13		-		(32	)		12
Total liabilities		$ 451		$ 295		$ 166		$ (489	)		$ 423		$ 442		$ 302		$ 143		$ (473	)		$ 414

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

⁽²⁾ Excludes $248 million and $188 million at March 31, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value.

Valuation Techniques

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

Money Market Investments

PG&E Corporation invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, such as U.S. Treasury bills, U.S. 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 prices 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, debt securities, and life insurance policies. In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.

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

Debt securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market 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 ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

Price Risk Management Instruments

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

Power purchase agreements, forwards and swaps are valued using a discounted cash flow model. Exchange-traded forwards and swaps that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Forwards and swaps transacted in the over-the-counter market that are identical to exchange-traded forwards and swaps or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available.

Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. Over-the-counter options are classified as Level 3 and are valued using a standard option pricing model which includes forward prices for the underlying commodity, time value at a risk-free rate, and volatility. For periods where market data is not available, the Utility extrapolates observable data using internal models.

The Utility holds CRRs to hedge financial risk of CAISO-imposed congestion charges in the day-ahead market. CRRs are valued based on prices observed in the CAISO auction which are discounted at the risk free rate. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility uses models to forecast CRR prices for those periods not covered in the auctions. 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 transfers between levels for the three months ended March 31, 2012.

Level 3 Measurements and Sensitivity Analysis

The Utility's Market and Credit Risk Management department is responsible for determining the fair value of the Utility's price risk management derivatives. Market and Credit Risk Management reports to the Chief Risk Officer of the Utility. Market and Credit Risk Management utilizes models to derive pricing inputs for the valuation of the Utility's Level 3 instruments. These models use pricing inputs from brokers and historical data. The Market and Credit Risk Management department and the Controller's organization collaborate to determine the appropriate fair value methodologies and classification for each derivative. Inputs used and fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness. Valuation models and techniques are reviewed periodically.

CRRs and power purchase agreements are valued using historical prices or significant unobservable inputs derived from internally-developed models. Unobservable inputs include forward electricity prices. Historical prices include CRR auction prices. Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. (See Note 7 above.)

(in millions)	Fair Value at March 31, 2012					Valuation Technique	Unobservable Input	Range
Fair Value Measurement	Assets		Liabilities
Congestion revenue rights		$ 67		$ (8	)	Market approach	CRR auction prices	$ (6.30) - $ 5.10
Power purchase agreements		$ -		$ (158	)	Discounted cash flow	Forward prices	$ 2.00 - $ 61.05

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the three months ended March 31, 2012 and 2011.

	Price Risk Management Instruments
(in millions)	2012			2011
Liability balance as of January 1		$ (74	)		$ (399	)
Realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)		(25	)		87
Liability balance as of March 31		$ (99	)		$ (312	)

⁽¹⁾ Price risk management activity is recoverable through customer rates. Therefore, net income was not impacted by realized amounts. Unrealized gains and losses are deferred in regulatory liabilities and assets.

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, 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 March 31, 2012 and December 31, 2011, 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 ERBs issued by PERF were based on quoted market prices at March 31, 2012 and December 31, 2011.

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):

	March 31, 2012				December 31, 2011
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation		$ 349		$ 382		$ 349		$ 380
Utility		10,546		12,412		10,545		12,543
Energy recovery bonds (Note 4)		321		327		423		433

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 does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, through customer rates. 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.)

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

(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Total Fair Value (1)
As of March 31, 2012
Equity securities
U.S.		$ 319		$ 616		$ (1	)		$ 934
Non-U.S.		197		162		(1	)		358
Debt securities
U.S. government and agency securities		787		86		(1	)		872
Municipal securities		66		3		(1	)		68
Other fixed-income securities		147		3		-			150
Total		$ 1,516		$ 870		$ (4	)		$ 2,382
As of December 31, 2011
Equity securities
U.S.		$ 334		$ 518		$ (3	)		$ 849
Non-U.S.		194		131		(2	)		323
Debt securities
U.S. government and agency securities		798		102		-			900
Municipal securities		56		2		-			58
Other fixed-income securities		96		3		-			99
Total		$ 1,478		$ 756		$ (5	)		$ 2,229

⁽¹⁾ Excludes $248 million and $188 million at March 31, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value. The debt securities mature on the following schedule:

(in millions)	As of March 31, 2012
Less than 1 year		$ 29
1–5 years		408
5–10 years		264
More than 10 years		389
Total maturities of debt securities		$ 1,090

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

	Three Months Ended
(in millions)	March 31, 2012			March 31, 2011
Proceeds from sales and maturities of nuclear decommissioning trust investments		$ 351			$ 726
Gross realized gains on sales of securities held as available-for-sale		7			20
Gross realized losses on sales of securities held as available-for-sale		(3	)		(4	)

Pacific Gas And Electric Company [Member]

Fair Value Measurements

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.

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):

	Fair Value Measurements
	At March 31, 2012											At December 31, 2011
(in millions)	Level 1		Level 2		Level 3		Netting (1)			Total		Level 1		Level 2		Level 3		Netting (1)			Total
Assets:
Money market investments		$ 206		$ -		$ -		$ -			$ 206		$ 206		$ -		$ -		$ -			$ 206
Nuclear decommissioning trusts
U.S. equity securities		925		9		-		-			934		841		8		-		-			849
Non-U.S. equity securities		358		-		-		-			358		323		-		-		-			323
U.S. government and agency securities		734		138		-		-			872		744		156		-		-			900
Municipal securities		-		68		-		-			68		-		58		-		-			58
Other fixed-income securities		-		150		-		-			150		-		99		-		-			99
Total nuclear decommissioning trusts (2)		2,017		365		-		-			2,382		1,908		321		-		-			2,229
Price risk management instruments (Note 7)
Electricity		-		68		67		27			162		-		92		69		8			169
Gas		-		3		-		-			3		-		6		-		(3	)		3
Total price risk management instruments		-		71		67		27			165		-		98		69		5			172
Rabbi trusts
Fixed-income securities		-		26		-		-			26		-		25		-		-			25
Life insurance contracts		-		68		-		-			68		-		67		-		-			67
Total rabbi trusts		-		94		-		-			94		-		92		-		-			92
Long-term disability trust
U.S. equity securities		5		13		-		-			18		13		15		-		-			28
Non-U.S. equity securities		-		15		-		-			15		-		9		-		-			9
Fixed-income securities		-		142		-		-			142		-		145		-		-			145
Total long-term disability trust		5		170		-		-			175		13		169		-		-			182
Total assets		$ 2,228		$ 700		$ 67		$ 27			$ 3,022		$ 2,127		$ 680		$ 69		$ 5			$ 2,881
Liabilities:
Price risk management instruments (Note 7)
Electricity		$ 436		$ 284		$ 166		$ (471	)		$ 415		$ 411		$ 289		$ 143		$ (441	)		$ 402
Gas		15		11		-		(18	)		8		31		13		-		(32	)		12
Total liabilities		$ 451		$ 295		$ 166		$ (489	)		$ 423		$ 442		$ 302		$ 143		$ (473	)		$ 414

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

⁽²⁾ Excludes $248 million and $188 million at March 31, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value.

Valuation Techniques

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

Money Market Investments

PG&E Corporation invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, such as U.S. Treasury bills, U.S. 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 prices 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, debt securities, and life insurance policies. In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.

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

Debt securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market 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 ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

Price Risk Management Instruments

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

Power purchase agreements, forwards and swaps are valued using a discounted cash flow model. Exchange-traded forwards and swaps that are valued using observable market forward prices for the underlying commodity are classified as Level 1. Forwards and swaps transacted in the over-the-counter market that are identical to exchange-traded forwards and swaps or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2. Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available.

Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. Over-the-counter options are classified as Level 3 and are valued using a standard option pricing model which includes forward prices for the underlying commodity, time value at a risk-free rate, and volatility. For periods where market data is not available, the Utility extrapolates observable data using internal models.

The Utility holds CRRs to hedge financial risk of CAISO-imposed congestion charges in the day-ahead market. CRRs are valued based on prices observed in the CAISO auction which are discounted at the risk free rate. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility uses models to forecast CRR prices for those periods not covered in the auctions. 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 transfers between levels for the three months ended March 31, 2012.

Level 3 Measurements and Sensitivity Analysis

The Utility's Market and Credit Risk Management department is responsible for determining the fair value of the Utility's price risk management derivatives. Market and Credit Risk Management reports to the Chief Risk Officer of the Utility. Market and Credit Risk Management utilizes models to derive pricing inputs for the valuation of the Utility's Level 3 instruments. These models use pricing inputs from brokers and historical data. The Market and Credit Risk Management department and the Controller's organization collaborate to determine the appropriate fair value methodologies and classification for each derivative. Inputs used and fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness. Valuation models and techniques are reviewed periodically.

CRRs and power purchase agreements are valued using historical prices or significant unobservable inputs derived from internally-developed models. Unobservable inputs include forward electricity prices. Historical prices include CRR auction prices. Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. (See Note 7 above.)

(in millions)	Fair Value at March 31, 2012					Valuation Technique	Unobservable Input	Range
Fair Value Measurement	Assets		Liabilities
Congestion revenue rights		$ 67		$ (8	)	Market approach	CRR auction prices	$ (6.30) - $ 5.10
Power purchase agreements		$ -		$ (158	)	Discounted cash flow	Forward prices	$ 2.00 - $ 61.05

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the three months ended March 31, 2012 and 2011.

	Price Risk Management Instruments
(in millions)	2012			2011
Liability balance as of January 1		$ (74	)		$ (399	)
Realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)		(25	)		87
Liability balance as of March 31		$ (99	)		$ (312	)

⁽¹⁾ Price risk management activity is recoverable through customer rates. Therefore, net income was not impacted by realized amounts. Unrealized gains and losses are deferred in regulatory liabilities and assets.

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, 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 March 31, 2012 and December 31, 2011, 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 ERBs issued by PERF were based on quoted market prices at March 31, 2012 and December 31, 2011.

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):

	March 31, 2012				December 31, 2011
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation		$ 349		$ 382		$ 349		$ 380
Utility		10,546		12,412		10,545		12,543
Energy recovery bonds (Note 4)		321		327		423		433

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 does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, through customer rates. 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.)

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

(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Total Fair Value (1)
As of March 31, 2012
Equity securities
U.S.		$ 319		$ 616		$ (1	)		$ 934
Non-U.S.		197		162		(1	)		358
Debt securities
U.S. government and agency securities		787		86		(1	)		872
Municipal securities		66		3		(1	)		68
Other fixed-income securities		147		3		-			150
Total		$ 1,516		$ 870		$ (4	)		$ 2,382
As of December 31, 2011
Equity securities
U.S.		$ 334		$ 518		$ (3	)		$ 849
Non-U.S.		194		131		(2	)		323
Debt securities
U.S. government and agency securities		798		102		-			900
Municipal securities		56		2		-			58
Other fixed-income securities		96		3		-			99
Total		$ 1,478		$ 756		$ (5	)		$ 2,229

⁽¹⁾ Excludes $248 million and $188 million at March 31, 2012 and December 31, 2011, respectively, primarily related to deferred taxes on appreciation of investment value.

The debt securities mature on the following schedule:

(in millions)	As of March 31, 2012
Less than 1 year		$ 29
1–5 years		408
5–10 years		264
More than 10 years		389
Total maturities of debt securities		$ 1,090

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

	Three Months Ended
(in millions)	March 31, 2012			March 31, 2011
Proceeds from sales and maturities of nuclear decommissioning trust investments		$ 351			$ 726
Gross realized gains on sales of securities held as available-for-sale		7			20
Gross realized losses on sales of securities held as available-for-sale		(3	)		(4	)

XML

Debt (Details) (USD $)	3 Months Ended					3 Months Ended
	Mar. 31, 2012	Apr. 16, 2012 Utility [Member]	Apr. 02, 2012 Utility [Member]	Mar. 31, 2012 Utility [Member]	Mar. 31, 2012 PGE Corporation And Utility [Member]	Mar. 31, 2012 Floating Rate Senior Notes [Member]	Mar. 31, 2012 Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member]	Mar. 31, 2012 Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member] Minimum [Member]	Mar. 31, 2012 Pollution Control Bonds Series 1996 C, E, F, And 1997 B [Member] Maximum [Member]	Mar. 31, 2012 Pollution Control Bonds Series 2009 A-D [Member]	Mar. 31, 2012 Pollution Control Bonds Series 2009 A-D [Member] Minimum [Member]	Mar. 31, 2012 Pollution Control Bonds Series 2009 A-D [Member] Maximum [Member]	Mar. 31, 2012 Energy Recovery Bonds [Member]	Dec. 31, 2005 Energy Recovery Bonds [Member]
Debt [Line Items]
Line of credit facility, maximum borrowing capacity				$ 3,000,000,000	$ 300,000,000
Letters of credit outstanding				367,000,000
Senior Notes		400,000,000
Debt instrument, face amount						250,000,000	614,000,000			309,000,000
Debt instrument, interest rate		4.45%						0.19%	0.22%		0.12%	0.17%
Senior notes maturity period	April 15, 2042					November 20, 2012
Repurchase of principal amount			50,000,000
Commercial paper outstanding				1,100,000,000
Interest rate for the Floating Rate Senior Notes						0.94%
Energy Recovery Bonds issued to refinance a regulatory asset														2,700,000,000
ERB, principal outstanding													$ 321,000,000

XML

Commitments And Contingencies (Natural Gas Supply, Transportation And Storage Commitments) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Long-term Purchase Commitment [Line Items]
2012	$ 1,810
2013	2,860
2014	3,010
2015	3,007
2016	2,917
Thereafter	32,120
Total	45,724
Pacific Gas And Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Cost of natural gas purchases	378	433
Natural Gas, Gas Transportation and Gas Storage Purchases [Member]
Long-term Purchase Commitment [Line Items]
2012	475
2013	331
2014	196
2015	187
2016	153
Thereafter	974
Total	$ 2,316

XML

Regulatory Assets, Liabilities, And Balancing Accounts (Tables)

3 Months Ended

Mar. 31, 2012

Regulatory Assets, Liabilities, And Balancing Accounts [Abstract]

Long-Term Regulatory Assets

	Balance at
(in millions)	March 31, 2012		December 31, 2011
Pension benefits	$	2,939	$	2,899
Deferred income taxes		1,483		1,444
Utility retained generation		598		613
Environmental compliance costs		535		520
Price risk management		354		339
Electromechanical meters		234		247
Unamortized loss, net of gain, on reacquired debt		157		163
Other		265		281
Total long-term regulatory assets	$	6,565	$	6,506

Long-Term Regulatory Liabilities

	Balance at
(in millions)	March 31, 2012		December 31, 2011
Cost of removal obligations		$ 3,524		$ 3,460
Recoveries in excess of AROs		707		611
Public purpose programs		526		499
Other		170		163
Total long-term regulatory liabilities		$ 4,927		$ 4,733

Current Regulatory Balancing Accounts, Net

	Receivable (Payable)
	Balance at
(in millions)	March 31, 2012			December 31, 2011
Distribution revenue adjustment mechanism		$ 422			$ 223
Utility generation		412			241
Public purpose programs		96			97
Hazardous substance		56			57
Gas fixed cost		(101	)		16
Energy recovery bonds		(108	)		(105	)
Energy procurement		(129	)		(48	)
Other		136			227
Total regulatory balancing accounts, net		$ 784			$ 708

XML

Resolution Of Remaining Chapter 11 Disputed Claims (Tables)

3 Months Ended

Mar. 31, 2012

Resolution Of Remaining Chapter 11 Disputed Claims [Abstract]

Changes In The Remaining Net Disputed Claims Liability

(in millions)
Balance at December 31, 2011	$	848
Interest accrued		7
Less: electricity supplier settlements		(23	)
Balance at March 31, 2012	$	832

XML

Resolution Of Remaining Chapter 11 Disputed Claims (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
Escrow for payment of remaining net disputed claims	$ 320	$ 320
Balance at December 31, 2011	848
Interest accrued	7
Less: electricity supplier settlements	(23)
Balance at March 31, 2012	832
Interest accrued on disputed claims	668
Pacific Gas And Electric Company [Member]
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
Balance at March 31, 2012	832
Remaining disputed claims	658
CAISO And PX [Member]
Resolution Of Remaining Chapter Eleven Disputed Claims [Line Items]
Carrying amounts due from CAISO and PX as of the balance sheet date for disputed claims related to the Chapter 11 Filing	$ 494

XML

Derivatives (Additional Cash Collateral The Utility Would Be Required To Post If Its Credit Risk-Related Contingency Features Were Triggered) (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012
Derivatives [Abstract]
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized	$ (134)
Related derivatives in an asset position	2
Collateral posting in the normal course of business related to these derivatives	33
Net position of derivative contracts/additional collateral posting requirements	$ (99)	[1]

[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.

XML

Condensed Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Current Assets
Cash and cash equivalents	$ 257	$ 513
Restricted cash ($56 and $51 related to energy recovery bonds at March 31, 2012 and December 31, 2011)	385	380
Accounts receivable
Customers (net of allowance for doubtful accounts of $80 and $81 at March 31, 2012 and December 31, 2011)	926	992
Accrued unbilled revenue	614	763
Regulatory balancing accounts	1,425	1,082
Other	817	839
Regulatory assets ($227 and $336 related to energy recovery bonds at March 31, 2012 and December 31, 2011)	1,024	1,090
Inventories
Gas stored underground and fuel oil	97	159
Materials and supplies	273	261
Income taxes receivable	154	183
Other	194	218
Total current assets	6,166	6,480
Property, Plant, and Equipment
Electric	36,329	35,851
Gas	12,015	11,931
Construction work in progress	2,011	1,770
Other	1	15
Total property, plant, and equipment	50,356	49,567
Accumulated depreciation	(16,107)	(15,912)
Net property, plant, and equipment	34,249	33,655
Other Noncurrent Assets
Regulatory assets	6,565	6,506
Nuclear decommissioning trusts	2,134	2,041
Income taxes receivable	412	386
Other	662	682
Total other noncurrent assets	9,773	9,615
TOTAL ASSETS	50,188	49,750
Current Liabilities
Short-term borrowings	1,401	1,647
Long-term debt, classified as current	50	50
Energy recovery bonds, classified as current	321	423
Accounts payable
Trade creditors	873	1,177
Disputed claims and customer refunds	658	673
Regulatory balancing accounts	641	374
Other	494	420
Interest payable	798	843
Income taxes payable	110	110
Deferred income taxes	160	196
Other	1,769	1,836
Total current liabilities	7,275	7,749
Noncurrent Liabilities
Long-term debt	11,767	11,766
Regulatory liabilities	4,927	4,733
Pension and other postretirement benefits	3,464	3,396
Asset retirement obligations	1,620	1,609
Deferred income taxes	6,190	6,008
Other	2,133	2,136
Total noncurrent liabilities	30,101	29,648
Commitments and Contingencies (Note 10)
Shareholders' Equity
Preferred stock
Common stock	8,011	7,602
Reinvested earnings	4,752	4,712
Accumulated other comprehensive loss	(203)	(213)
Total shareholders' equity	12,560	12,101
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	12,812	12,353
TOTAL LIABILITIES AND EQUITY	50,188	49,750
Pacific Gas And Electric Company [Member]
Current Assets
Cash and cash equivalents	45	304
Restricted cash ($56 and $51 related to energy recovery bonds at March 31, 2012 and December 31, 2011)	385	380
Accounts receivable
Customers (net of allowance for doubtful accounts of $80 and $81 at March 31, 2012 and December 31, 2011)	926	992
Accrued unbilled revenue	614	763
Regulatory balancing accounts	1,425	1,082
Other	821	840
Regulatory assets ($227 and $336 related to energy recovery bonds at March 31, 2012 and December 31, 2011)	1,024	1,090
Inventories
Gas stored underground and fuel oil	97	159
Materials and supplies	273	261
Income taxes receivable	212	242
Other	188	213
Total current assets	6,010	6,326
Property, Plant, and Equipment
Electric	36,329	35,851
Gas	12,015	11,931
Construction work in progress	2,011	1,770
Total property, plant, and equipment	50,355	49,552
Accumulated depreciation	(16,106)	(15,898)
Net property, plant, and equipment	34,249	33,654
Other Noncurrent Assets
Regulatory assets	6,565	6,506
Nuclear decommissioning trusts	2,134	2,041
Income taxes receivable	413	384
Other	330	331
Total other noncurrent assets	9,442	9,262
TOTAL ASSETS	49,701	49,242
Current Liabilities
Short-term borrowings	1,401	1,647
Long-term debt, classified as current	50	50
Energy recovery bonds, classified as current	321	423
Accounts payable
Trade creditors	873	1,177
Disputed claims and customer refunds	658	673
Regulatory balancing accounts	641	374
Other	522	417
Interest payable	788	838
Income taxes payable	118	118
Deferred income taxes	165	199
Other	1,562	1,628
Total current liabilities	7,099	7,544
Noncurrent Liabilities
Long-term debt	11,418	11,417
Regulatory liabilities	4,927	4,733
Pension and other postretirement benefits	3,391	3,325
Asset retirement obligations	1,620	1,609
Deferred income taxes	6,347	6,160
Other	2,071	2,070
Total noncurrent liabilities	29,774	29,314
Commitments and Contingencies (Note 10)
Shareholders' Equity
Preferred stock	258	258
Common stock	1,322	1,322
Additional paid-in capital	4,181	3,796
Reinvested earnings	7,259	7,210
Accumulated other comprehensive loss	(192)	(202)
Total shareholders' equity	12,828	12,384
Total equity	12,828	12,384
TOTAL LIABILITIES AND EQUITY	$ 49,701	$ 49,242

XML

New And Significant Accounting Policies

3 Months Ended

Mar. 31, 2012

New And Significant Accounting Policies

NOTE 2: NEW AND SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies used by PG&E Corporation and the Utility are discussed in Note 2 of the Notes to the Consolidated Financial Statements in the 2011 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") and 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 have elected that certain of the trusts underlying these plans be treated under the Internal Revenue Code ("Code") as qualified trusts. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain Code limitations. PG&E Corporation and the Utility use a December 31 measurement date for all plans.

Net periodic benefit cost as reflected in PG&E Corporation's Condensed Consolidated Statements of Income for the three months ended March 31, 2012 and 2011 is as follows:

	Pension Benefits						Other Benefits
	Three Months Ended March 31,						Three Months Ended March 31,
(in millions)	2012			2011			2012			2011
Service cost for benefits earned	$	99		$	82		$	12		$	11
Interest cost		164			164			21			23
Expected return on plan assets		(149	)		(167	)		(19	)		(20	)
Amortization of transition obligation		-			-			6			6
Amortization of prior service cost		5			9			6			6
Amortization of unrecognized loss		31			12			1			1
Net periodic benefit cost		150			100			27			27
Less: transfer to regulatory account (1)		(75	)		(36	)		-			-
Total	$	75		$	64		$	27		$	27

⁽¹⁾  The Utility recorded $75 million and $36 million for the three months ended March 31, 2012 and 2011, 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 and the Utility for the information disclosed above.

.

Variable Interest Entities

PG&E Corporation and the Utility evaluate whether any entity is a variable interest entity ("VIE") that could require consolidation. PG&E Corporation and the Utility use a qualitative approach to determine who has a controlling financial interest in a VIE and perform ongoing assessments of whether an entity is the primary beneficiary of a VIE.

PG&E Corporation and the Utility are required to consolidate any entities that they control. In most cases, control can be determined based on majority ownership or voting interests. However, for certain entities, control is difficult to discern based on ownership or voting interests alone. These entities are referred to as VIEs. A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise has a controlling financial interest if it has the obligation to absorb expected losses or receive expected gains that could potentially be significant to a VIE and the power to direct the activities that are most significant to a VIE's economic performance. An enterprise that has a controlling financial interest is known as the VIE's primary beneficiary and is required to consolidate the VIE.

Some of the counterparties to the Utility's power purchase agreements are considered VIEs. In determining whether the Utility has a controlling financial interest in a VIE, the Utility assesses whether it absorbs any of the VIE's expected losses or receives any portion of the VIE's expected residual returns, as a result of the power purchase agreement. This assessment includes an evaluation of how the risks and rewards associated with the power plant's activities are absorbed by variable interest holders, as well as an analysis of the variability in the VIE's gross margin and the impact of the power purchase agreement on the gross margin. For each variable interest, the Utility assesses whether it has the power to direct the activities of the power plant that most directly impact the VIE's economic performance.

The Utility can hold a variable interest in entities that own power plants that generate electricity for sale to the Utility under power purchase agreements. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility utilizing various technologies such as natural gas, wind, solar photovoltaic, solar thermal, and hydroelectric. Under each of these power purchase agreements, the Utility is obligated to purchase electricity or capacity, or both, from the VIE. The Utility does not provide any other support to these VIEs, and the Utility's financial exposure is limited to the amount it pays for delivered electricity and capacity. (See Note 10 below.) The Utility does not have the power to direct the activities that are most significant to these VIE's economic performance. This assessment considers 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. As a result, the Utility does not have a controlling financial interest in any of these VIEs. Therefore, at March 31, 2012, the Utility was not the primary beneficiary of, and did not consolidate, any of these VIEs.

The Utility continued to consolidate PG&E Energy Recovery Funding LLC ("PERF") at March 31, 2012, as the Utility is the primary beneficiary of PERF. In 2005, PERF was formed as a wholly owned subsidiary of the Utility to issue energy recovery bonds ("ERB"s) in connection with the settlement agreement entered into between PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the remaining disputed claims made by electricity suppliers in the Utility's proceeding under Chapter 11 of the U.S. Bankruptcy Code ("Chapter 11 Settlement Agreement"). The Utility has a controlling financial interest in PERF since 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, which was an activity that was significant to PERF's economic performance. The assets of PERF were $382 million at March 31, 2012 and primarily consisted of assets related to ERBs, which are included in other current assets – regulatory assets in the Condensed Consolidated Balance Sheets. The liabilities of PERF were $321 million at March 31, 2012 and consisted of ERBs, which are included in current liabilities in the Condensed Consolidated Balance Sheets. (See Note 4 below.)

As of March 31, 2012, PG&E Corporation 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 $396 million to these companies in exchange for the right to receive benefits from local rebates, federal 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 March 31, 2012, PG&E Corporation had made total payments of $360 million under these agreements and received $160 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 March 31, 2012. 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 agreements is generally limited to its lease payments and investment contributions to these companies.

Adoption of New Accounting Standards

Amendments to Fair Value Measurement Requirements

On January 1, 2012, PG&E Corporation and the Utility adopted an accounting standards update ("ASU") that requires additional fair value measurement disclosures. For fair value measurements that use significant unobservable inputs, quantitative disclosures of the inputs and qualitative disclosures of the valuation processes are required. For items not measured at fair value in the balance sheet but whose fair value is disclosed, disclosures of the fair value hierarchy level, the fair value measurement techniques used, and the inputs used in the fair value measurements are required. In addition, the ASU permits 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 ASU refines when an entity should, and should not, apply certain premiums and discounts to a fair value measurement. The adoption of the ASU is reflected in Note 8 below and did not have a material impact on PG&E Corporation's or the Utility's Condensed Consolidated Financial Statements.

Presentation of Comprehensive Income

On January 1, 2012, PG&E Corporation and the Utility adopted ASUs that require an entity to present either (1) a single statement of comprehensive income or loss or (2) a separate statement of comprehensive income or loss that follows a statement of income or loss. A single statement of comprehensive income or loss is 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 separate statement of comprehensive income or loss immediately follows a statement of income or loss and is comprised of net income or loss, other comprehensive income and losses, total other comprehensive income or loss, and total comprehensive income or loss. Furthermore, the ASUs prohibit an entity from presenting other comprehensive income and losses in a statement of equity only. The adoption of the ASUs resulted in the addition of the Condensed Consolidated Statements of Comprehensive Income to PG&E Corporation's and the Utility's Condensed Consolidated Financial Statements.

Pacific Gas And Electric Company [Member]

New And Significant Accounting Policies

NOTE 2: NEW AND SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies used by PG&E Corporation and the Utility are discussed in Note 2 of the Notes to the Consolidated Financial Statements in the 2011 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") and 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 have elected that certain of the trusts underlying these plans be treated under the Internal Revenue Code ("Code") as qualified trusts. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain Code limitations. PG&E Corporation and the Utility use a December 31 measurement date for all plans.

Net periodic benefit cost as reflected in PG&E Corporation's Condensed Consolidated Statements of Income for the three months ended March 31, 2012 and 2011 is as follows:

	Pension Benefits						Other Benefits
	Three Months Ended March 31,						Three Months Ended March 31,
(in millions)	2012			2011			2012			2011
Service cost for benefits earned	$	99		$	82		$	12		$	11
Interest cost		164			164			21			23
Expected return on plan assets		(149	)		(167	)		(19	)		(20	)
Amortization of transition obligation		-			-			6			6
Amortization of prior service cost		5			9			6			6
Amortization of unrecognized loss		31			12			1			1
Net periodic benefit cost		150			100			27			27
Less: transfer to regulatory account (1)		(75	)		(36	)		-			-
Total	$	75		$	64		$	27		$	27

⁽¹⁾  The Utility recorded $75 million and $36 million for the three months ended March 31, 2012 and 2011, 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 and the Utility for the information disclosed above.

.

Variable Interest Entities

PG&E Corporation and the Utility evaluate whether any entity is a variable interest entity ("VIE") that could require consolidation. PG&E Corporation and the Utility use a qualitative approach to determine who has a controlling financial interest in a VIE and perform ongoing assessments of whether an entity is the primary beneficiary of a VIE.

PG&E Corporation and the Utility are required to consolidate any entities that they control. In most cases, control can be determined based on majority ownership or voting interests. However, for certain entities, control is difficult to discern based on ownership or voting interests alone. These entities are referred to as VIEs. A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise has a controlling financial interest if it has the obligation to absorb expected losses or receive expected gains that could potentially be significant to a VIE and the power to direct the activities that are most significant to a VIE's economic performance. An enterprise that has a controlling financial interest is known as the VIE's primary beneficiary and is required to consolidate the VIE.

Some of the counterparties to the Utility's power purchase agreements are considered VIEs. In determining whether the Utility has a controlling financial interest in a VIE, the Utility assesses whether it absorbs any of the VIE's expected losses or receives any portion of the VIE's expected residual returns, as a result of the power purchase agreement. This assessment includes an evaluation of how the risks and rewards associated with the power plant's activities are absorbed by variable interest holders, as well as an analysis of the variability in the VIE's gross margin and the impact of the power purchase agreement on the gross margin. For each variable interest, the Utility assesses whether it has the power to direct the activities of the power plant that most directly impact the VIE's economic performance.

The Utility can hold a variable interest in entities that own power plants that generate electricity for sale to the Utility under power purchase agreements. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility utilizing various technologies such as natural gas, wind, solar photovoltaic, solar thermal, and hydroelectric. Under each of these power purchase agreements, the Utility is obligated to purchase electricity or capacity, or both, from the VIE. The Utility does not provide any other support to these VIEs, and the Utility's financial exposure is limited to the amount it pays for delivered electricity and capacity. (See Note 10 below.) The Utility does not have the power to direct the activities that are most significant to these VIE's economic performance. This assessment considers 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. As a result, the Utility does not have a controlling financial interest in any of these VIEs. Therefore, at March 31, 2012, the Utility was not the primary beneficiary of, and did not consolidate, any of these VIEs.

The Utility continued to consolidate PG&E Energy Recovery Funding LLC ("PERF") at March 31, 2012, as the Utility is the primary beneficiary of PERF. In 2005, PERF was formed as a wholly owned subsidiary of the Utility to issue energy recovery bonds ("ERB"s) in connection with the settlement agreement entered into between PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the remaining disputed claims made by electricity suppliers in the Utility's proceeding under Chapter 11 of the U.S. Bankruptcy Code ("Chapter 11 Settlement Agreement"). The Utility has a controlling financial interest in PERF since 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, which was an activity that was significant to PERF's economic performance. The assets of PERF were $382 million at March 31, 2012 and primarily consisted of assets related to ERBs, which are included in other current assets regulatory assets in the Condensed Consolidated Balance Sheets. The liabilities of PERF were $321 million at March 31, 2012 and consisted of ERBs, which are included in current liabilities in the Condensed Consolidated Balance Sheets. (See Note 4 below.)

As of March 31, 2012, PG&E Corporation 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 $396 million to these companies in exchange for the right to receive benefits from local rebates, federal 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 March 31, 2012, PG&E Corporation had made total payments of $360 million under these agreements and received $160 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 March 31, 2012. 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 agreements is generally limited to its lease payments and investment contributions to these companies.

Adoption of New Accounting Standards

Amendments to Fair Value Measurement Requirements

On January 1, 2012, PG&E Corporation and the Utility adopted an accounting standards update ("ASU") that requires additional fair value measurement disclosures. For fair value measurements that use significant unobservable inputs, quantitative disclosures of the inputs and qualitative disclosures of the valuation processes are required. For items not measured at fair value in the balance sheet but whose fair value is disclosed, disclosures of the fair value hierarchy level, the fair value measurement techniques used, and the inputs used in the fair value measurements are required. In addition, the ASU permits 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 ASU refines when an entity should, and should not, apply certain premiums and discounts to a fair value measurement. The adoption of the ASU is reflected in Note 8 below and did not have a material impact on PG&E Corporation's or the Utility's Condensed Consolidated Financial Statements.

Presentation of Comprehensive Income

On January 1, 2012, PG&E Corporation and the Utility adopted ASUs that require an entity to present either (1) a single statement of comprehensive income or loss or (2) a separate statement of comprehensive income or loss that follows a statement of income or loss. A single statement of comprehensive income or loss is 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 separate statement of comprehensive income or loss immediately follows a statement of income or loss and is comprised of net income or loss, other comprehensive income and losses, total other comprehensive income or loss, and total comprehensive income or loss. Furthermore, the ASUs prohibit an entity from presenting other comprehensive income and losses in a statement of equity only. The adoption of the ASUs resulted in the addition of the Condensed Consolidated Statements of Comprehensive Income to PG&E Corporation's and the Utility's Condensed Consolidated Financial Statements.

XML

Commitments And Contingencies (Environmental Remediation Liability Disclosure) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Pacific Gas And Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Balance at December 31, 2011	$ 785
Transfer to regulatory account for recovery	77
Amounts not recoverable in customer rates	81
Less: Payments	(22)
Balance at March 31, 2012	921
Remediation At Utility Natural Gas Compressor Site Near Hinkley, CA [Member] | Pacific Gas And Electric Company [Member]
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual for remediation	218
Remediation At Utility Natural Gas Compressor Site Near Topock, AZ [Member]
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual for remediation	240
Remediation At Divested Generation Facilities [Member]
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual for remediation	80
Remediation Costs For Generation And Other Facilities And For Third-Party Disposal Sites [Member]
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual for remediation	168
Investigation And/Or Remediation Costs At Former MGP Sites [Member]
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual for remediation	165
Remediation Of Decommissioning Fossil Fuel-Fired Sites [Member]
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual for remediation	$ 50

XML

Commitments And Contingencies (Tables)

3 Months Ended

Mar. 31, 2012

Commitments And Contingencies [Abstract]

Schedule Of Undiscounted Future Expected Power Purchase Agreement Payments

(in millions)
2012	$ 1,810
2013	2,860
2014	3,010
2015	3,007
2016	2,917
Thereafter	32,120
Total	$ 45,724

Undiscounted Obligations For Natural Gas Purchases, Gas Transportation Services, And Gas Storage

(in millions)
2012	$ 475
2013	331
2014	196
2015	187
2016	153
Thereafter	974
Total	$ 2,316

Undiscounted Obligations For Nuclear Fuel Agreements

(in millions)
2012	$ 67
2013	86
2014	127
2015	193
2016	147
Thereafter	1,011
Total	$ 1,631

Change In Accruals Related To Third-Party Claims

(in millions)
Balance at January 1, 2010	$ 0
Loss accrued	220
Less: Payments	(6)
Balance at December 31, 2010	214
Additional loss accrued	155
Less: Payments	(92)
Balance at December 31, 2011	277
Less: Payments	(34)
Balance at March 31, 2012	$ 243

Environmental Remediation Liability Disclosure

(in millions)
Balance at December 31, 2011	$ 785
Additional remediation costs accrued:
Transfer to regulatory account for recovery	77
Amounts not recoverable in customer rates	81
Less: Payments	(22)
Balance at March 31, 2012	$ 921

XML

Derivatives (Volumes Of Outstanding Derivative Contracts) (Details)	Mar. 31, 2012
Derivative [Line Items]
Derivatives expiration, lower (year)	2017
Derivatives expiration, higher (year)	2022
Forwards And Swaps [Member] | Natural Gas [Member]
Derivative [Line Items]
Less Than 1 Year	439,441,427	[1],[2],[3]
Greater Than 1 Year but Less Than 3 Years	166,878,481	[1],[2],[3]
Greater Than 3 Years but Less Than 5 Years	4,280,000	[1],[2],[3]
Forwards And Swaps [Member] | Electricity [Member]
Derivative [Line Items]
Less Than 1 Year	4,141,223	[1]
Greater Than 1 Year but Less Than 3 Years	4,696,221	[1]
Greater Than 3 Years but Less Than 5 Years	2,009,505	[1]
Greater Than 5 Years	3,421,832	[1],[4]
Options [Member] | Natural Gas [Member]
Derivative [Line Items]
Less Than 1 Year	231,380,020	[1]
Greater Than 1 Year but Less Than 3 Years	280,200,000	[1]
Options [Member] | Electricity [Member]
Derivative [Line Items]
Less Than 1 Year	1,248,000	[1]
Greater Than 1 Year but Less Than 3 Years	140,510	[1]
Greater Than 3 Years but Less Than 5 Years	239,233	[1]
Greater Than 5 Years	218,013	[1],[4]
Congestion Revenue Rights [Member] | Electricity [Member]
Derivative [Line Items]
Less Than 1 Year	75,532,338	[1]
Greater Than 1 Year but Less Than 3 Years	73,123,024	[1]
Greater Than 3 Years but Less Than 5 Years	73,190,271	[1]
Greater Than 5 Years	54,209,541	[1],[4]

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

[2] Amounts shown are for the combined positions of the electric fuels and core gas portfolios.

[3] Million British Thermal Units.

[4] Derivatives in this category expire between 2017 and 2022.

XML

New And Significant Accounting Policies (Tables)

3 Months Ended

Mar. 31, 2012

New And Significant Accounting Policies [Abstract]

Components Of Net Periodic Benefit Cost

	Pension Benefits						Other Benefits
	Three Months Ended March 31,						Three Months Ended March 31,
(in millions)	2012			2011			2012			2011
Service cost for benefits earned	$	99		$	82		$	12		$	11
Interest cost		164			164			21			23
Expected return on plan assets		(149	)		(167	)		(19	)		(20	)
Amortization of transition obligation		-			-			6			6
Amortization of prior service cost		5			9			6			6
Amortization of unrecognized loss		31			12			1			1
Net periodic benefit cost		150			100			27			27
Less: transfer to regulatory account (1)		(75	)		(36	)		-			-
Total	$	75		$	64		$	27		$	27

⁽¹⁾  The Utility recorded $75 million and $36 million for the three months ended March 31, 2012 and 2011, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates.