Edgar Filing: PACIFIC GAS & ELECTRIC Co

form10q.htm


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, 2013 OR

[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to __________

Commission File Number _______________		Exact Name of Registrant as Specified in its Charter _______________		State or Other Jurisdiction of Incorporation ______________		IRS Employer Identification Number ___________

1-12609		PG&E Corporation		California		94-3234914
1-2348		Pacific Gas and Electric Company		California		94-0742640

Pacific Gas and Electric Company 77 Beale Street P.O. Box 770000 San Francisco, California 94177 ________________________________________				PG&E Corporation 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) 973-1000 ______________________________________
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 23, 2013:
PG&E Corporation:				442,173,394
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, 2013

TABLE OF CONTENTS

			PAGE
GLOSSARY			ii

PART I.	FINANCIAL INFORMATION
ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
	Condensed Consolidated Statements of Income		1
	Condensed Consolidated Statements of Comprehensive Income		2
	Condensed Consolidated Balance Sheets		3
	Condensed Consolidated Statements of Cash Flows		5
	Pacific Gas and Electric Company
	Condensed Consolidated Statements of Income		6
	Condensed Consolidated Statements of Comprehensive Income		7
	Condensed Consolidated Balance Sheets		8
	Condensed Consolidated Statements of Cash Flows		10
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:	Organization and Basis of Presentation	11
	NOTE 2:	Significant Accounting Policies	11
	NOTE 3:	Regulatory Assets, Liabilities, and Balancing Accounts	13
	NOTE 4:	Debt	14
	NOTE 5:	Equity	15
	NOTE 6:	Earnings Per Share	15
	NOTE 7:	Derivatives	16
	NOTE 8:	Fair Value Measurements	18
	NOTE 9:	Resolution of Remaining Chapter 11 Disputed Claims	24
	NOTE 10:	Commitments and Contingencies	25

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview		32
	Cautionary Language Regarding Forward-Looking Statements		34
	Results of Operations		37
	Liquidity and Financial Resources		41
	Contractual Commitments		46
	Natural Gas Matters		46
	Regulatory Matters		49
	Environmental Matters		51
	Off-Balance Sheet Arrangements		51
	Risk Management Activities		52
	Critical Accounting Policies		52
	Accounting Standards Issued But Not Yet Adopted		52

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		53
ITEM 4.	CONTROLS AND PROCEDURES		53

PART II.	OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS		54
ITEM 1A.	RISK FACTORS		55
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		55
ITEM 5.	OTHER INFORMATION		55
ITEM 6.	EXHIBITS		56

SIGNATURES			57

GLOSSARY

The following terms and abbreviations appearing in the text of this report have the meanings indicated below.

2012 Annual Report	PG&E Corporation's and Pacific Gas and Electric Company's combined 2012 Annual Report on Form 10-K
ALJ	administrative law judge
ARO(s)	asset retirement obligation(s)
ASU	Accounting Standards Update
CAISO	California Independent System Operator
CARB	California Air Resources Board
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
DTSC	California Department of Toxic Substances Control
ERBs	Energy Recovery Bonds
EPS	earnings per common share
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	generally accepted accounting principles
GHG	greenhouse gas
GRC	General Rate Case
GT&S	Gas Transmission and Storage
IRS	Internal Revenue Service
kWh(s)	kilowatt-hour(s)
NEIL	Nuclear Electric Insurance Limited
NRC	Nuclear Regulatory Commission
NTSB	National Transportation Safety Board
ROE	return on equity
San Bruno accident	On September 9, 2010, an underground 30-inch natural gas transmission pipeline owned and operated by the Utility, ruptured in a residential area located in the City of San Bruno, California. The ensuing explosion and fire resulted in the deaths of eight people, numerous personal injuries, and extensive property damage.
SED	Safety and Enforcement Division of the CPUC, formerly known as the Consumer Protection and Safety Division or CPSD
TO	Transmission Owner
Utility	Pacific Gas and Electric Company
VIE(s)	variable interest entity(ies)

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)	2013			2012
Operating Revenues
Electric	$	2,799		$	2,772
Natural gas		873			869
Total operating revenues		3,672			3,641
Operating Expenses
Cost of electricity		983			859
Cost of natural gas		346			343
Operating and maintenance		1,338			1,368
Depreciation, amortization, and decommissioning		503			584
Total operating expenses		3,170			3,154
Operating Income		502			487
Interest income		2			1
Interest expense		(176	)		(174	)
Other income, net		28			26
Income Before Income Taxes		356			340
Income tax provision		114			104
Net Income		242			236
Preferred stock dividend requirement of subsidiary		3			3
Income Available for Common Shareholders	$	239		$	233
Weighted Average Common Shares Outstanding, Basic		434			414
Weighted Average Common Shares Outstanding, Diluted		435			416
Net Earnings Per Common Share, Basic	$	0.55		$	0.56
Net Earnings Per Common Share, Diluted	$	0.55		$	0.56
Dividends Declared Per Common Share	$	0.46		$	0.46

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2013			2012
Net Income	$	242		$	236
Other Comprehensive Income
Pension and other postretirement benefit plans
Unrecognized prior service credit (net of income tax of $5 during respective periods)		6			6
Unrecognized net gain (net of income tax of $11 during respective periods)		17			21
Unrecognized net transition obligation (net of income tax of $2 in 2012)		-			4
Transfer to regulatory account (net of income tax of $13 and $15 during respective periods)		(19	)		(21	)
Other (net of income tax of $4 in 2013)		6			-
Total other comprehensive income		10			10
Comprehensive Income		252			246
Preferred stock dividend requirement of subsidiary		3			3
Comprehensive Income Attributable to Common Shareholders	$	249		$	243

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	March 31,			December 31,
(in millions)	2013			2012
ASSETS
Current Assets
Cash and cash equivalents	$	278		$	401
Restricted cash		304			330
Accounts receivable
Customers (net of allowance for doubtful accounts of $84 and $87at respective dates)		943			937
Accrued unbilled revenue		600			761
Regulatory balancing accounts		1,241			936
Other		298			365
Regulatory assets		486			564
Inventories
Gas stored underground and fuel oil		73			135
Materials and supplies		316			309
Income taxes receivable		166			211
Other		187			172
Total current assets		4,892			5,121
Property, Plant, and Equipment
Electric		40,356			39,701
Gas		12,786			12,571
Construction work in progress		2,100			1,894
Other		1			1
Total property, plant, and equipment		55,243			54,167
Accumulated depreciation		(16,961	)		(16,644	)
Net property, plant, and equipment		38,282			37,523
Other Noncurrent Assets
Regulatory assets		6,778			6,809
Nuclear decommissioning trusts		2,233			2,161
Income taxes receivable		202			176
Other		675			659
Total other noncurrent assets		9,888			9,805
TOTAL ASSETS	$	53,062		$	52,449

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	March 31,			December 31,
(in millions, except share amounts)	2013			2012
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	489		$	492
Long-term debt, classified as current		1,399			400
Accounts payable
Trade creditors		1,043			1,241
Disputed claims and customer refunds		156			157
Regulatory balancing accounts		1,102			634
Other		488			444
Interest payable		831			870
Income taxes payable		10			6
Deferred income taxes		44			-
Other		1,486			2,012
Total current liabilities		7,048			6,256
Noncurrent Liabilities
Long-term debt		11,518			12,517
Regulatory liabilities		5,187			5,088
Pension and other postretirement benefits		3,626			3,575
Asset retirement obligations		2,924			2,919
Deferred income taxes		6,870			6,748
Other		2,065			2,020
Total noncurrent liabilities		32,190			32,867
Commitments and Contingencies (Note 10)
Equity
Shareholders' Equity
Preferred stock		-			-
Common stock, no par value, authorized 800,000,000 shares, 441,509,054 and 430,718,293 shares outstanding at respective dates		8,879			8,428
Reinvested earnings		4,784			4,747
Accumulated other comprehensive loss		(91	)		(101	)
Total shareholders' equity		13,572			13,074
Noncontrolling Interest - Preferred Stock of Subsidiary		252			252
Total equity		13,824			13,326
TOTAL LIABILITIES AND EQUITY	$	53,062		$	52,449

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2013			2012
Cash Flows from Operating Activities
Net income	$	242		$	236
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		503			584
Allowance for equity funds used during construction		(26	)		(27	)
Deferred income taxes and tax credits, net		166			146
Other		57			73
Effect of changes in operating assets and liabilities:
Accounts receivable		209			221
Inventories		55			50
Accounts payable		(56	)		(213	)
Income taxes receivable/payable		49			29
Other current assets and liabilities		(242	)		(70	)
Regulatory assets, liabilities, and balancing accounts, net		(133	)		(171	)
Other noncurrent assets and liabilities		45			73
Net cash provided by operating activities		869			931
Cash Flows from Investing Activities
Capital expenditures		(1,249	)		(1,094	)
Decrease (increase) in restricted cash		26			(5	)
Proceeds from sales and maturities of nuclear decommissioning trust investments		363			351
Purchases of nuclear decommissioning trust investments		(364	)		(370	)
Other		17			25
Net cash used in investing activities		(1,207	)		(1,093	)
Cash Flows from Financing Activities
Net repayments of commercial paper, net of discount of $1 in 2012		(2	)		(245	)
Energy recovery bonds matured		-			(102	)
Common stock issued		426			387
Common stock dividends paid		(191	)		(182	)
Other		(18	)		48
Net cash provided by (used in) financing activities		215			(94	)
Net change in cash and cash equivalents		(123	)		(256	)
Cash and cash equivalents at January 1		401			513
Cash and cash equivalents at March 31	$	278		$	257
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(197	)	$	(204	)
Income taxes, net		36			-
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	201		$	193
Capital expenditures financed through accounts payable		257			276
Noncash common stock issuances		6			6
Terminated capital leases		-			136

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	(Unaudited)
	Three Months Ended
	March 31,
(in millions)	2013			2012
Operating Revenues
Electric	$	2,798		$	2,771
Natural gas		873			869
Total operating revenues		3,671			3,640
Operating Expenses
Cost of electricity		983			859
Cost of natural gas		346			343
Operating and maintenance		1,336			1,366
Depreciation, amortization, and decommissioning		503			584
Total operating expenses		3,168			3,152
Operating Income		503			488
Interest income		1			1
Interest expense		(170	)		(168	)
Other income, net		24			23
Income Before Income Taxes		358			344
Income tax provision		121			113
Net Income		237			231
Preferred stock dividend requirement		3			3
Income Available for Common Stock	$	234		$	228

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2013			2012
Net Income	$	237		$	231
Other Comprehensive Income
Pension and other postretirement benefit plans
Unrecognized prior service credit (net of income tax of $5 during respective periods)		6			6
Unrecognized net gain (net of income tax of $10 and $11 during respective periods)		18			21
Unrecognized net transition obligation (net of income tax of $2 in 2012)		-			4
Transfer to regulatory account (net of income tax of $13 and $15 during respective periods)		(19	)		(21	)
Total other comprehensive income		5			10
Comprehensive Income	$	242		$	241

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	March 31,			December 31,
(in millions)	2013			2012
ASSETS
Current Assets
Cash and cash equivalents	$	53		$	194
Restricted cash		304			330
Accounts receivable
Customers (net of allowance for doubtful accounts of $84 and $87 at respective dates)		943			937
Accrued unbilled revenue		600			761
Regulatory balancing accounts		1,241			936
Other		305			366
Regulatory assets		486			564
Inventories
Gas stored underground and fuel oil		73			135
Materials and supplies		316			309
Income taxes receivable		140			186
Other		161			160
Total current assets		4,622			4,878
Property, Plant, and Equipment
Electric		40,356			39,701
Gas		12,786			12,571
Construction work in progress		2,100			1,894
Total property, plant, and equipment		55,242			54,166
Accumulated depreciation		(16,960	)		(16,643	)
Net property, plant, and equipment		38,282			37,523
Other Noncurrent Assets
Regulatory assets		6,778			6,809
Nuclear decommissioning trusts		2,233			2,161
Income taxes receivable		197			171
Other		403			381
Total other noncurrent assets		9,611			9,522
TOTAL ASSETS	$	52,515		$	51,923

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	March 31,			December 31,
(in millions, except share amounts)	2013			2012
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	369		$	372
Long-term debt, classified as current		1,399			400
Accounts payable
Trade creditors		1,044			1,241
Disputed claims and customer refunds		156			157
Regulatory balancing accounts		1,102			634
Other		520			419
Interest payable		820			865
Income taxes payable		17			12
Deferred income taxes		36			-
Other		1,267			1,794
Total current liabilities		6,730			5,894
Noncurrent Liabilities
Long-term debt		11,168			12,167
Regulatory liabilities		5,187			5,088
Pension and other postretirement benefits		3,546			3,497
Asset retirement obligations		2,924			2,919
Deferred income taxes		7,066			6,939
Other		2,005			1,959
Total noncurrent liabilities		31,896			32,569
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 respective dates		1,322			1,322
Additional paid-in capital		5,051			4,682
Reinvested earnings		7,346			7,291
Accumulated other comprehensive loss		(88	)		(93	)
Total shareholders' equity		13,889			13,460
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	52,515		$	51,923

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2013			2012
Cash Flows from Operating Activities
Net income	$	237		$	231
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		503			584
Allowance for equity funds used during construction		(26	)		(27	)
Deferred income taxes and tax credits, net		163			153
Other		37			57
Effect of changes in operating assets and liabilities:
Accounts receivable		203			218
Inventories		55			50
Accounts payable		2			(182	)
Income taxes receivable/payable		51			30
Other current assets and liabilities		(230	)		(69	)
Regulatory assets, liabilities, and balancing accounts, net		(133	)		(171	)
Other noncurrent assets and liabilities		45			75
Net cash provided by operating activities		907			949
Cash Flows from Investing Activities
Capital expenditures		(1,249	)		(1,094	)
Decrease (increase) in restricted cash		26			(5	)
Proceeds from sales and maturities of nuclear decommissioning trust investments		363			351
Purchases of nuclear decommissioning trust investments		(364	)		(370	)
Other		5			3
Net cash used in investing activities		(1,219	)		(1,115	)
Cash Flows from Financing Activities
Net repayments of commercial paper, net of discount of $1 in 2012		(2	)		(245	)
Energy recovery bonds matured		-			(102	)
Preferred stock dividends paid		(3	)		(3	)
Common stock dividends paid		(179	)		(179	)
Equity contribution		370			385
Other		(15	)		51
Net cash provided by (used in) financing activities		171			(93	)
Net change in cash and cash equivalents		(141	)		(259	)
Cash and cash equivalents at January 1		194			304
Cash and cash equivalents at March 31	$	53		$	45
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(197	)	$	(204	)
Income taxes, net		36			-
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	257		$	276
Terminated capital leases		-			136

See accompanying Notes to the Condensed Consolidated Financial Statements.

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, 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 primarily regulated by the CPUC and the FERC. In addition, the 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. PG&E Corporation and the Utility operate in one segment.

The accompanying Condensed Consolidated Financial Statements have been prepared in accordance with 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 U.S. Securities and Exchange Commission and therefore do not contain all of the information and footnotes required by GAAP and the U.S. Securities and Exchange Commission 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, 2012 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 2012 Annual Report on Form 10-K filed with the U.S. Securities and Exchange Commission on February 21, 2013. This quarterly report should be read in conjunction with the 2012 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, 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: 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 2012 Annual Report.

Pension and Other Postretirement Benefits

PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees, as well as contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees. The trusts underlying certain of these plans are qualified trusts under the Internal Revenue Code of 1986, as amended (“Code”). 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.

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three months ended March 31, 2013 and 2012 were as follows:

	Pension Benefits						Other Benefits
	Three Months Ended						Three Months Ended
	March 31,						March 31,
(in millions)	2013			2012			2013			2012
Service cost for benefits earned	$	115		$	99		$	13		$	12
Interest cost		156			164			19			21
Expected return on plan assets		(162	)		(149	)		(20	)		(19	)
Amortization of transition obligation		-			-			-			6
Amortization of prior service cost		5			5			6			6
Amortization of unrecognized loss		27			31			1			1
Net periodic benefit cost		141			150			19			27
Less: transfer to regulatory account (1)		(57	)		(75	)		-			-
Total	$	84		$	75		$	19		$	27

(1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from customers in futures rates.

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Variable Interest Entities

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at March 31, 2013, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial exposure is limited to the amount the Utility pays for delivered electricity and capacity. (See Note 10 below.) The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at March 31, 2013, it did not consolidate any of them.

At March 31, 2013, PG&E Corporation affiliates had entered into four tax equity agreements to fund residential and commercial retail solar energy installations with two privately held companies that are considered VIEs. Under these agreements, PG&E Corporation has made lease payments and investment contributions of $363 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. PG&E Corporation determined that it does not have control over the companies’ significant economic activities, such as the design of the companies, vendor selection, and construction. PG&E Corporation’s remaining financial exposure is not material. Since PG&E Corporation was not the primary beneficiary of any of these VIEs at March 31, 2013, it did not consolidate any of them.

Adoption of New Accounting Pronouncements

Disclosures about Offsetting Assets and Liabilities

In January 2013, the FASB issued an ASU that clarifies the scope of disclosures about offsetting assets and liabilities. The guidance requires an entity to disclose gross and net information about derivatives that are offset in the balance sheet or subject to an enforceable master-netting arrangement or similar agreement The ASU became effective for PG&E Corporation and the Utility on January 1, 2013. (See Note 7 below).

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

In February 2013, the FASB issued an ASU that requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income. The ASU became effective for PG&E Corporation and the Utility on January 1, 2013.

The changes, net of income tax, in PG&E Corporation’s other comprehensive income for the three months ended March 31, 2013 consist of the following:

	Pension and
	Other
	Postretirement
(in millions)	Benefit Plans			Other		Total
Beginning balance (net of total income tax of $101)	$	(105	)	$	4	$	(101	)
Other comprehensive income before reclassifications (net of total income tax of $9)		(19	)		6		(13	)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of total income tax of $5) (1)		6			-		6
Amortization of actuarial gains (net of total income tax of $11) (1)		17			-		17
Net current period other comprehensive income		4			6		10
Ending balance (net of total income tax of $94)	$	(101	)	$	10	$	(91	)

(1) These other comprehensive income components are included in the computation of net periodic pension and other postretirement costs. (See the “Pension and Other Postretirement Benefits” table above for additional details.)

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Accounting Standards Issued But Not Yet Adopted

Joint and Several Liability

In February 2013, the FASB issued an ASU that will require certain obligations resulting from joint and several liability arrangements to be recognized as the sum of (1) the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and (2) any additional amount the reporting entity expects to pay on behalf of its co-obligors. The ASU also requires entities to disclose the nature and amount of the obligation as well as other information about those obligations. This ASU will be effective retrospectively beginning on January 1, 2014. PG&E Corporation and the Utility are currently evaluating the impact of the ASU.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

	Balance at
	March 31,		December 31,
(in millions)	2013		2012
Pension benefits	$	3,299	$	3,275
Deferred income taxes		1,668		1,627
Utility retained generation		539		552
Environmental compliance costs		596		604
Price risk management		185		210
Electromechanical meters		179		194
Unamortized loss, net of gain, on reacquired debt		136		141
Other		176		206
Total long-term regulatory assets	$	6,778	$	6,809

Regulatory Liabilities

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

	Balance at
	March 31,			December 31,
(in millions)	2013			2012
Cost of removal obligations		$	3,709		$	3,625
Recoveries in excess of AROs			673			620
Public purpose programs			539			590
Other			266			253
Total long-term regulatory liabilities		$	5,187		$	5,088

Regulatory Balancing Accounts

The Utility’s recovery of a significant portion of revenue requirements and costs is decoupled from the volume of sales. The Utility records differences between actual customer billings and the Utility’s authorized revenue requirement as well as differences between incurred costs and customer billings or authorized revenue. To the extent these differences are probable of recovery or refund, the Utility records a regulatory balancing account receivable or payable. Regulatory balancing accounts receivable and payable will fluctuate during the year based on seasonal electric and gas usage and timing of cost and collections.

Current Regulatory Balancing Accounts, Net

	Receivable (Payable)
	Balance at
	March 31,			December 31,
(in millions)	2013			2012
Distribution revenue adjustment mechanism	$	359		$	219
Utility generation		321			117
Hazardous substance		76			56
Public purpose programs		(69	)		(83	)
Gas fixed cost		(81	)		44
Energy recovery bonds		(192	)		(43	)
Energy procurement		(31	)		77
U.S. Department of Energy Settlement		(250	)		(250	)
Greenhouse gas allowance auction proceeds (1)		(141	)		-
Other		147			165
Total regulatory balancing accounts, net	$	139		$	302

(1) The CARB has adopted regulations that established a state-wide, “cap-and-trade” program (effective January 1, 2013) that sets a gradually declining limit on the amount of GHGs that may be emitted each year. This balancing

account is used to record proceeds collected by the Utility for GHG emission allowances associated with the cap-and-trade program. These amounts will be refunded to customers in future periods.

NOTE 4: DEBT

Revolving Credit Facilities – PG&E Corporation and the Utility

At March 31, 2013, PG&E Corporation had $120 million of cash borrowings and no letters of credit outstanding under its $300 million revolving credit facility.

At March 31, 2013, the Utility had no cash borrowings and $243 million of letters of credit outstanding under its $3.0 billion revolving credit facility.

On April 1, 2013, PG&E Corporation and the Utility entered into an amendment and restatement of their respective $300 million and $3.0 billion five-year revolving credit facilities that were entered into on May 31, 2011. PG&E Corporation’s and the Utility’s amended and restated credit agreements contain substantially similar terms as their 2011 credit agreements, except that the termination dates have been extended to April 1, 2018.

Utility

Pollution Control Bonds

At March 31, 2013, 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 0.10% to 0.17%. At March 31, 2013, the interest rates on the $309 million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements ranged from 0.10% to 0.11%.

Commercial Paper Program

At March 31, 2013, the Utility had $368 million of commercial paper outstanding.

NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the three months ended March 31, 2013 were as follows:


	PG&E Corporation			Utility
	Total			Total
(in millions)	Equity			Shareholders' Equity
Balance at December 31, 2012	$	13,326		$	13,460
Comprehensive income		252			242
Common stock issued		432			-
Share-based compensation expense		19			(1	)
Common stock dividends declared		(202	)		(179	)
Preferred stock dividend requirement		-			(3	)
Preferred stock dividend requirement of subsidiary		(3	)		-
Equity contributions		-			370
Balance at March 31, 2013	$	13,824		$	13,889

In March 2013, PG&E Corporation sold 7,200,000 shares of its common stock in an underwritten public offering for cash proceeds of $300 million, net of fees and commissions. During the three months ended March 31, 2013, PG&E Corporation issued 2,109,980 shares of its common stock under its 401(k) plan, its Dividend Reinvestment and Stock Purchase Plan, and its share-based compensation plans for total cash proceeds of $63 million. PG&E Corporation also sold 1,480,900 shares of its common stock under the Equity Distribution Agreement executed in November 2011 for cash proceeds of $63 million, net of fees, exhausting the remaining capacity under this agreement.

During the three months ended March 31, 2013, PG&E Corporation contributed equity of $370 million to the Utility to maintain the Utility’s CPUC-authorized capital structure, which consists of 52% common equity and 48% debt and preferred stock.

NOTE 6: EARNINGS PER SHARE

PG&E Corporation’s basic 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)	2013		2012
Income available for common shareholders	$	239	$	233
Weighted average common shares outstanding, basic		434		414
Add incremental shares from assumed conversions:
Employee share-based compensation		1		2
Weighted average common share outstanding, diluted		435		416
Total earnings per common share, diluted	$	0.55	$	0.56

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

NOTE 7: DERIVATIVES

The Utility uses both derivative and non-derivative contracts in managing its customers’ exposure to commodity-related price risk, including forward contracts, swap agreements and futures contracts, and option contracts.

These instruments are not held for speculative purposes and are subject to certain regulatory requirements. Customer rates are designed to recover the Utility’s reasonable costs of providing services, including the costs related to price risk management activities.

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 mechanism discussed above remains in place and the Utility’s price risk management activities are carried out in accordance with CPUC directives, the Utility expects to recover fully, in rates, all costs related to derivatives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. (See Note 3 above.) Net realized gains or losses on commodity derivatives 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 eligible 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.

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 and the intention to offset exists under a master netting agreement. All derivatives that are subject to a master netting arrangement have been netted. The net balances include outstanding cash collateral associated with derivative positions.

At March 31, 2013, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
	Gross Derivative											Total Derivative
(in millions)	Balance				Netting				Cash Collateral			Balance
Current assets – other		$	47			$	(27	)		$	33		$	53
Other noncurrent assets – other			92				(4	)			-			88
Current liabilities – other			(182	)			27				55			(100	)
Noncurrent liabilities – other			(188	)			4				11			(173	)
Total commodity risk		$	(231	)		$	-			$	99		$	(132	)

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

	Commodity Risk
	Gross Derivative											Total Derivative
(in millions)	Balance				Netting				Cash Collateral			Balance
Current assets – other		$	48			$	(25	)		$	36		$	59
Other noncurrent assets – other			99				(11	)			-			88
Current liabilities – other			(255	)			25				115			(115	)
Noncurrent liabilities – other			(221	)			11				14			(196	)
Total commodity risk		$	(329	)		$	-			$	165		$	(164	)

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

	Commodity Risk
	Three Months Ended
	March 31,
(in millions)	2013				2012
Unrealized gain/(loss) - regulatory assets and liabilities (1)		$	98			$	(54	)
Realized loss - cost of electricity (2)			(48	)			(151	)
Realized loss - cost of natural gas (2)			(8	)			(22	)
Total commodity risk		$	42			$	(227	)

(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings.

(2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.

Volume of Derivative Activity

At March 31, 2013, the volumes of PG&E Corporation’s and the Utility’s outstanding derivatives were as follows:

		Contract Volume (1)
				1 Year or		3 Years or
				Greater but		Greater but
		Less Than 1		Less Than 3		Less Than 5		5 Years or
Underlying Product	Instruments	Year		Years		Years		Greater (2)
Natural Gas (3)	Forwards and
(MMBtus (4))	Swaps		311,804,316		85,857,500		4,812,500		-
	Options		209,274,282		166,356,071		7,050,000		-
Electricity	Forwards and
(Megawatt-hours)	Swaps		2,537,023		3,164,680		2,008,046		2,402,346
	Options		21,002		239,233		239,015		98,505
	Congestion
	Revenue Rights		63,826,023		74,481,760		74,358,484		17,972,340

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

(2) Derivatives in this category expire between 2018 and 2023.

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

(4) Million British Thermal Units.

At December 31, 2012, the volumes of PG&E Corporation’s and the Utility’s outstanding derivatives were as follows:

		Contract Volume (1)
				1 Year or		3 Years or
				Greater but		Greater but
		Less Than 1		Less Than 3		Less Than 5		5 Years or
Underlying Product	Instruments	Year		Years		Years		Greater (2)
Natural Gas (3)	Forwards and
(MMBtus (4))	Swaps		329,466,510		98,628,398		5,490,000		-
	Options		221,587,431		216,279,767		10,050,000		-
Electricity	Forwards and
(Megawatt-hours)	Swaps		2,537,023		3,541,046		2,009,505		2,538,718
	Options		-		239,015		239,233		119,508
	Congestion
	Revenue Rights		74,198,690		74,187,803		74,240,147		25,699,804

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

(2) Derivatives in this category expire between 2018 and 2023.

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

(4) Million British Thermal Units.

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. At March 31, 2013, 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 additional cash immediately to fully collateralize some of its net liability derivative positions.

The additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows:

	Balance at
	March 31,			December 31,
(in millions)	2013			2012
Derivatives in a liability position with credit risk-relatedcontingencies that are not fully collateralized	$	(191	)	$	(266	)
Related derivatives in an asset position		59			59
Collateral posting in the normal course of business related to these derivatives		63			103
Net position of derivative contracts/additional collateral posting requirements (1)	$	(69	)	$	(104	)

(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.

Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below (assets held in rabbi trusts are held by PG&E Corporation and not the Utility):

	Fair Value Measurements
	At March 31, 2013
(in millions)	Level 1		Level 2		Level 3		Netting (1)			Total
Assets:
Money market investments	$	205	$	-	$	-	$	-		$	205
Nuclear decommissioning trusts
Money market investments		25		-		-		-			25
U.S. equity securities		984		10		-		-			994
Non-U.S. equity securities		394		-		-		-			394
U.S. government and agency securities		692		159		-		-			851
Municipal securities		-		65		-		-			65
Other fixed-income securities		-		177		-		-			177
Total nuclear decommissioning trusts (2)		2,095		411		-		-			2,506
Price risk management instruments
(Note 7)
Electricity		4		53		76		7			140
Gas		-		4		2		(5	)		1
Total price risk management instruments		4		57		78		2			141
Rabbi trusts
Fixed-income securities		-		30		-		-			30
Life insurance contracts		-		72		-		-			72
Total rabbi trusts		-		102		-		-			102
Long-term disability trust
Money market investments		4		-		-		-			4
U.S. equity securities		-		12		-		-			12
Non-U.S. equity securities		-		12		-		-			12
Fixed-income securities		-		136		-		-			136
Total long-term disability trust		4		160		-		-			164
Total assets	$	2,308	$	730	$	78	$	2		$	3,118
Liabilities:
Price risk management instruments
(Note 7)
Electricity	$	89	$	119	$	153	$	(92	)	$	269
Gas		5		4		-		(5	)		4
Total liabilities	$	94	$	123	$	153	$	(97	)	$	273

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

(2) Excludes $273 million at March 31, 2013 primarily related to deferred taxes on appreciation of investment value.

	Fair Value Measurements
	At December 31, 2012
(in millions)	Level 1		Level 2		Level 3		Netting (1)			Total
Assets:
Money market investments	$	209	$	-	$	-	$	-		$	209
Nuclear decommissioning trusts
Money market investments		21		-		-		-			21
U.S. equity securities		940		9		-		-			949
Non-U.S. equity securities		379		-		-		-			379
U.S. government and agency securities		681		139		-		-			820
Municipal securities		-		59		-		-			59
Other fixed-income securities		-		173		-		-			173
Total nuclear decommissioning trusts (2)		2,021		380		-		-			2,401
Price risk management instruments
(Note 7)
Electricity		1		60		80		6			147
Gas		-		5		1		(6	)		-
Total price risk management instruments		1		65		81		-			147
Rabbi trusts
Fixed-income securities		-		30		-		-			30
Life insurance contracts		-		72		-		-			72
Total rabbi trusts		-		102		-		-			102
Long-term disability trust
Money market investments		10		-		-		-			10
U.S. equity securities		-		14		-		-			14
Non-U.S. equity securities		-		11		-		-			11
Fixed-income securities		-		136		-		-			136
Total long-term disability trust		10		161		-		-			171
Total assets	$	2,241	$	708	$	81	$	-		$	3,030
Liabilities:
Price risk management instruments
(Note 7)
Electricity	$	155	$	144	$	160	$	(156	)	$	303
Gas		8		9		-		(9	)		8
Total liabilities	$	163	$	153	$	160	$	(165	)	$	311

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

(2) Excludes $240 million at December 31, 2012 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 tables above. All investments that are valued using a net asset value per share can be redeemed quarterly with notice not to exceed 90 days.

Money Market Investments

PG&E Corporation and the Utility invest 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 and the Utility’s investments in these money market funds are valued using unadjusted prices for identical assets in an active market and are thus classified as Level 1. Money market funds are recorded as cash and cash equivalents in PG&E Corporation’s and the Utility’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 for identical securities in active markets and are classified as Level 1. Equity securities also include commingled funds that are valued using a net asset value per share and are 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 traded either on an exchange or over-the-counter.

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. Over-the-counter forwards and swaps 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 the 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 transfers between levels in the fair value hierarchy as of the end of the reporting period. There were no transfers between levels at March 31, 2013.

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. Historical prices include CRR auction prices. Unobservable inputs include forward electricity 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.)

	Fair Value at
(in millions)	March 31, 2013
Fair Value Measurement	Assets			Liabilities			Valuation Technique	Unobservable Input	Range (1)
Congestion revenue rights		$	76		$	15	Market approach	CRR auction prices		$	(11.30) - 7.93
Power purchase agreements		$	-		$	139	Discounted cash flow	Forward prices		$	10.54 - 58.08

(1) Represents price per megawatt-hour

	Fair Value at
(in millions)	December 31, 2012
Fair Value Measurement	Assets			Liabilities			Valuation Technique	Unobservable Input	Range (1)
Congestion revenue rights		$	80		$	16	Market approach	CRR auction prices		$	(9.04) - 55.15
Power purchase agreements		$	-		$	145	Discounted cash flow	Forward prices		$	8.59 - 62.90

(1) Represents price per megawatt-hour

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the three months ended March 31, 2013 and 2012:

	Price Risk Management Instruments
(in millions)	2013			2012
Liability balance as of January 1	$	(79	)	$	(74	)
Realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)		4			(25	)
Transfers out of Level 3		-			-
Liability balance as of March 31	$	(75	)	$	(99	)

(1) Price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. 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, 2013 and December 31, 2012, 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 and PG&E Corporation’s fixed-rate senior notes were based on quoted market prices at March 31, 2013 and December 31, 2012.

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, 2013						December 31, 2012
(in millions)	Carrying Amount			Level 2 Fair Value			Carrying Amount			Level 2 Fair Value
Debt (Note 4)
PG&E Corporation		$	350		$	367		$	349		$	371
Utility			11,645			13,757			11,645			13,946

Nuclear Decommissioning Trust Investments

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

			Total		Total
	Amortized		Unrealized		Unrealized			Total Fair
(in millions)	Cost		Gains		Losses			Value (1)
As of March 31, 2013
Money market investments	$	25	$	-	$	-		$	25
Equity securities
U.S.		289		705		-			994
Non-U.S.		199		196		(1	)		394
Debt securities
U.S. government and agency securities		762		89		-			851
Municipal securities		61		4		-			65
Other fixed-income securities		173		4		-			177
Total	$	1,509	$	998	$	(1	)	$	2,506
As of December 31, 2012
Money market investments	$	21	$	-	$	-		$	21
Equity securities
U.S.		331		618		-			949
Non-U.S.		199		181		(1	)		379
Debt securities
U.S. government and agency securities		723		97		-			820
Municipal securities		56		4		(1	)		59
Other fixed-income securities		168		5		-			173
Total	$	1,498	$	905	$	(2	)	$	2,401

(1) Excludes $273 million and $240 million at March 31, 2013 and December 31, 2012, respectively, primarily related to deferred taxes on appreciation of investment value.

The fair value of debt securities by contractual maturity is as follows:

	As of
(in millions)	March 31, 2013
Less than 1 year	$	28
1–5 years		448
5–10 years		237
More than 10 years		380
Total maturities of debt securities	$	1,093

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

	Three Months Ended
	March 31, 2013			March 31, 2012
(in millions)
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	363		$	351
Gross realized gains on sales of securities held as available-for-sale		12			7
Gross realized losses on sales of securities held as available-for-sale		(1	)		(3	)

NOTE 9: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

Various electricity suppliers filed claims in the Utility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers 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 governmental entities, for overcharges incurred in the CAISO and the California Power Exchange wholesale electricity markets during this period.

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 Utility is uncertain when and how the remaining disputed claims will be resolved.

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 through the conclusion of the various FERC and judicial proceedings, are refunded to customers through rates in future periods.

At March 31, 2013, and December 31, 2012, the remaining net disputed claims liability consisted of $156 million and $157 million, respectively, of remaining net disputed claims (classified on the Condensed Consolidated Balance Sheets within accounts payable – disputed claims and customer refunds) and $691 million and $685 million, respectively, of accrued interest (classified on the Condensed Consolidated Balance Sheets within interest payable).

At March 31, 2013 and December 31, 2012, the Utility held $291 million, respectively, in escrow, including earned interest, for payment of the remaining net disputed claims liability. These amounts are included within restricted cash on the Condensed Consolidated Balance Sheets.

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 regulatory proceedings, nuclear operations, legal matters and environmental remediation.

Commitments

In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments. The Utility disclosed its commitments at December 31, 2012 in Note 15 of the Notes to the Consolidated Financial Statements in the 2012 Annual Report. The Utility has not entered into any new material commitments during the three months ended March 31, 2013.

Contingencies

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 reasonably possible losses are reviewed quarterly and are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. In assessing the amounts related to such contingencies, PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs.

The accrued liability associated with legal and regulatory contingencies (other than the amounts related to natural gas matters that are discussed below) totaled $38 million at March 31, 2013 and $34 million at December 31, 2012 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

Following the San Bruno accident in September 2010, various regulatory proceedings, investigations, and lawsuits were commenced. The NTSB, an independent review panel appointed by the CPUC, and the SED completed investigations with respect to the San Bruno accident, placing the blame primarily on the Utility.

Pending CPUC Investigations and Enforcement Matters

The CPUC is conducting three investigative enforcement proceedings of the Utility’s natural gas operations that relate to (1) the Utility’s safety recordkeeping for its natural gas transmission system, (2) the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density, and (3) the Utility’s pipeline installation, integrity management, recordkeeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the San Bruno accident. Evidentiary hearings and briefing on the issue of alleged violations have been completed in each of these investigations. See Note 15 of the Notes to the Consolidated Financial Statements of the 2012 Annual Report for additional information regarding each investigative proceeding.

The CPUC has stated that it is prepared to impose significant penalties on the Utility if the CPUC determines that the Utility violated applicable laws, rules, and orders. Many factors can be considered in determining the amount of penalties to impose on the Utility, including the financial resources of the Utility. The SED’s financial consultant prepared a report concluding that PG&E Corporation could raise approximately $2.25 billion through additional equity issuances to fund CPUC-imposed penalties on the Utility. The Utility’s financial consultant disagreed with this financial analysis and asserted that a fine in excess of financial analysts’ expectations, which the consultant’s report cited as a mean of $477 million, would make financing more difficult and expensive.

The SED and each other intervening party has been previously ordered to file single briefs, rather than separate briefs in each proceeding, to recommend the amount of penalties and other remedies (which could include remedial operational or policy measures) to be imposed on the Utility based on the violations the SED alleges the Utility committed. Under the revised procedural schedule, these briefs are due May 6, 2013, the Utility’s reply brief is due May 24, 2013, and rebuttal briefs are due on June 5, 2013. After briefing has been completed, it is anticipated that the ALJs will issue one or more presiding officer’s decisions containing the violations determined to have been committed, the amount of penalties, and any required remedial actions. Based on the CPUC’s rules, the presiding officer’s decisions are currently due August 5, 2013. The decisions would become the final decisions of the CPUC thirty days after issuance unless the Utility or another party filed an appeal, or a CPUC commissioner requested review of the decision, within such time.

As of March 31, 2013, the Utility has also submitted 48 self-reports with the SED, plus additional follow-up reports, to provide notice about self-identified and self-corrected violations of certain state and federal regulations related to the safety of natural gas facilities and natural gas operating practices. The SED is authorized to issue citations and impose penalties on the Utility associated with these or future reports that the Utility may file. The SED may consider the same factors as the CPUC in exercising its discretion to impose penalties, as described above, except that the SED is required to impose the maximum daily statutory penalty per violation. PG&E Corporation and the Utility are uncertain whether the SED will issue citations and impose penalties on the Utility based on the self-reports the Utility has already submitted.

In addition, the Utility has notified the CPUC and the SED that the Utility is undertaking a system-wide effort to survey its transmission pipelines and identify and remove encroachments from pipeline rights-of-way over a multi-year period. PG&E Corporation and the Utility are uncertain whether this matter will result in the imposition of penalties on the Utility.

PG&E Corporation and the Utility continue to believe it is probable that the Utility will incur penalties of at least $200 million in connection with these pending investigations and potential enforcement matters and have accrued this amount in their Condensed Consolidated Financial Statements. PG&E Corporation and the Utility are unable to make a better estimate of probable losses or estimate the amount of reasonably possible losses in excess of $200 million due to the many variables that could affect the final outcome of these matters. These variables include how the total number and duration of violations will be determined; whether penalties will be determined separately in each investigative proceeding or in the aggregate; how the testimony of the financial consultants will be considered; whether the Utility’s costs to perform any required remedial actions will be considered; how the CPUC responds to increasing public pressure; and whether and how the financial impact of non-recoverable costs the Utility has already incurred, and will continue to incur, to improve the safety and reliability of its pipeline system, will be considered. (See “CPUC Gas Safety Rulemaking Proceeding” below.) Future changes in these estimates or the assumptions on which they are based could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. The ultimate amount of penalties imposed on the Utility could be materially higher than the amount accrued.

CPUC Gas Safety Rulemaking Proceeding

The CPUC is conducting a rulemaking proceeding to adopt new safety and reliability regulations for natural gas transmission and distribution pipelines in California and the related ratemaking mechanisms. On December 20, 2012, the CPUC approved the Utility’s proposed pipeline safety enhancement plan (filed in August 2011) to modernize and upgrade its natural gas transmission system but disallowed the Utility’s request for rate recovery of a significant portion of plan-related costs the Utility forecasted it would incur over the first phase of the plan (2011 through 2014). The CPUC decision limited the Utility’s recovery of capital expenditures to $1.0 billion of the total $1.4 billion requested. Various parties have requested the CPUC to reconsider or modify its decision, arguing that the Utility’s cost recovery should be more limited. It is uncertain whether or when the CPUC will act on these requests. In 2012, the Utility recorded a $353 million charge to net income for plan-related capital expenditures incurred that are forecasted to exceed the CPUC’s authorized levels or that were specifically disallowed. The Utility will update its forecasts as the project continues and may incur additional charges to net income.

Criminal Investigation

In June 2011, the Utility was notified that representatives from the U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo County District Attorney’s Office are conducting an investigation of the San Bruno accident. Federal and state authorities have indicated that the Utility is a target of the investigation. The Utility is cooperating with the investigation. PG&E Corporation and the Utility are uncertain whether any criminal charges will be brought against either company or any of their current or former employees. A criminal charge or finding would further harm the Utility’s reputation. 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 and such penalties could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. In addition, the Utility’s business or operations could be negatively affected by any remedial measures imposed on the Utility.

Third-Party Claims

As of March 31, 2013, approximately 160 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, had been filed against PG&E Corporation and the Utility in connection with the San Bruno accident on behalf of approximately 480 plaintiffs. The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages. The Utility has entered into settlement agreements to resolve the claims of approximately 140 plaintiffs and other claimants. The Utility and most of the remaining plaintiffs are engaged in settlement discussions. Since the San Bruno accident, the Utility has recorded cumulative charges of $455 million through March 31, 2013 for estimated third-party claims, including personal injury and property damage, damage to infrastructure, and other damage claims. The Utility has made cumulative payments of $382 million for settlements of these claims. The Utility estimates it is reasonably possible that it may incur as much as an additional $145 million for third-party claims, for a total possible loss of $600 million since the San Bruno accident. This estimate is subject to change as more information becomes known about the unresolved claims. 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.

The following table presents changes in the third-party claims liability since December 31, 2012; the balance 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	$	-
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
Additional loss accrued		80
Less: Payments		(211	)
Balance at December 31, 2012		146
Additional loss accrued		-
Less: Payments		(73	)
Balance at March 31, 2013	$	73

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 insurance coverage for third-party liability attributable to the San Bruno accident is approximately $992 million in excess of a $10 million deductible. Through March 31, 2013, the Utility has recognized cumulative insurance recoveries for third-party claims of $284 million. 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 additional insurance recoveries.

Class Action Complaint

On August 23, 2012, a complaint was filed in the San Francisco Superior Court against PG&E Corporation and the Utility (and other unnamed defendants) by individuals who seek certification of a class consisting of all California residents who were customers of the Utility between 1997 and 2010, with certain exceptions. The plaintiffs allege that the Utility collected more than $100 million in customer rates from 1997 through 2010 for the purpose of various safety measures and operations projects but instead used the funds for general corporate purposes such as executive compensation and bonuses. The plaintiffs allege that PG&E Corporation and the Utility engaged in unfair business practices in violation of California state law. The plaintiffs seek restitution and disgorgement, as well as compensatory and punitive damages.

PG&E Corporation and the Utility contest the plaintiffs’ allegations. In January 2013, PG&E Corporation and the Utility requested that the court dismiss the complaint on the grounds that the CPUC has exclusive jurisdiction to adjudicate the issues raised by the plaintiffs’ allegations. In the alternative, PG&E Corporation and the Utility requested that the court stay the proceeding until the CPUC investigations described above are concluded. The court has set a hearing on the motion for May 23, 2013. Due to the early stage of this proceeding, PG&E Corporation and the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses that may be incurred in connection with this matter.

Nuclear Insurance

The Utility is a member of NEIL, which is a mutual insurer owned by utilities with nuclear facilities. NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility due to a nuclear event (meaning that nuclear material is released) that occurs at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident ($2.7 billion for property damage and $490 million for business interruption) for Diablo Canyon. In addition, NEIL provides $131 million of coverage for nuclear and non-nuclear property damages at Humboldt Bay Unit 3. (NEIL also provides insurance coverage to the Utility for non-nuclear property damages and business interruption losses at Diablo Canyon. NEIL significantly lowered the limits for this coverage in April 2013.) 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 $46 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 insurance policies. The Utility has a separate supplier’s and transporter’s 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.

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 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:

(in millions)
Balance at December 31, 2012	$	910
Additional remediation costs accrued:
Transfer to regulatory account for recovery		72
Amounts not recoverable from customers		16
Less: Payments		(44	)
Balance at March 31, 2013	$	954

The environmental remediation liability is composed of the following:

	Balance at
(in millions)	March 31, 2013		December 31, 2012
Utility-owned natural gas compressor site near Topock, Arizona (1)	$	271	$	239
Utility-owned natural gas compressor site near Hinkley, California (1)		217		226
Former manufactured gas plant sites owned by the Utility or third parties		187		181
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites		172		158
Fossil fuel-fired generation facilities formerly owned by the Utility		88		87
Decommissioning fossil fuel-fired generation facilities and sites		19		19
Total environmental remediation liability	$	954	$	910

(1) See “Natural Gas Compressor Sites” below.

The CPUC has authorized the Utility to recover most of its environmental remediation costs through various ratemaking mechanisms, subject to exclusions for certain sites, such as the Hinkley natural gas compressor site, and subject to limitations for certain liabilities such as amounts associated with fossil fuel-fired generation facilities formerly owned by the Utility. At March 31, 2013, the Utility expected to recover $596 million through these ratemaking mechanisms.

Natural Gas Compressor Sites

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor sites near Hinkley, California and Topock, Arizona. The Utility is also required to take measures to abate the effects of the contamination on the environment.

Hinkley Site

The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. 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. As of March 31, 2013, approximately 350 residential households located near the chromium plume boundary were covered by the Utility’s whole house water replacement program and the majority have opted to accept the Utility’s offer to purchase their properties. The Utility expects that the Regional Board will consider certification of the final environmental impact report in the third quarter of 2013. Following certification of the final report, the Regional Board is expected to issue the final cleanup standards.

At March 31, 2013 and December 31, 2012, $217 million and $226 million, respectively, were accrued in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Hinkley site. Remediation costs for the Hinkley site are not recovered from customers through rates. Future costs will depend on many factors, including the Regional Board’s certification of the final environmental impact report, the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the Utility’s required time frame for remediation, and adoption of a final drinking water standard currently under development by the State of California. As more information becomes known regarding these factors, these estimates and the assumptions on which they are based regarding the amount of liability incurred may be subject to further changes. Future changes in estimates or assumptions may have a material impact on PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows.

Topock Site

The Utility’s remediation and abatement efforts are subject to the regulatory authority of the California DTSC and the U.S. Department of the Interior. The Utility has implemented interim remediation measures, including a system of extraction wells and a treatment plant designed to prevent movement of a hexavalent chromium plume toward the Colorado River. The DTSC has certified the final environmental impact report and approved the Utility’s final remediation plan for the groundwater plume, under which the Utility will implement an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. On April 5, 2013, the Utility submitted its intermediate design plan for implementing the final groundwater remedyto the DTSC and the U.S. Department of the Interior. The Utility’s intermediate plan reflects its evaluation of input received from regulatory agencies and other stakeholders, potential sources of fresh water to be used as part of the remedy, and performing other engineering activities necessary to complete the remedial design. The Utility expects to submit its final plan for approval in 2014.

At March 31, 2013 and December 31, 2012, $271 million and $239 million, respectively, were accrued in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Topock site. The increase reflects the Utility’s best estimate of costs associated with the final groundwater remedy based on its intermediate design plan. The CPUC has authorized the Utility to recover 90% of its remediation costs for the Topock site from customers through rates without a reasonableness review. As more information becomes known regarding the extent of work to be performed to implement the final groundwater remedy, these estimates and the assumptions on which they are based regarding the amount of liability incurred may be subject to change. Future changes in estimates or assumptions could have a material impact on PG&E Corporation’s and the Utility’s future financial condition 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 $1.7 billion (including amounts related to the Hinkley and Topock sites described above) 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.

Tax Matters

In 2008, PG&E Corporation began participating in the compliance assurance process, a real-time IRS audit intended to expedite resolution of tax matters. Since 2008, the IRS has withheld several matters pertaining to the 2008, 2010, and 2011 tax returns for further review. The most significant of the matters withheld for review relates to a 2008 tax accounting method change filed by PG&E Corporation related to repairs. The IRS is expected to complete its review of the 2008 repair method changes in 2013. PG&E Corporation and the Utility expect the unrecognized tax benefits may change significantly within the next 12 months. However, PG&E Corporation and the Utility cannot estimate the change in unrecognized tax benefits related to the items discussed above.

There were no other significant developments to tax matters during the three months ended March 31, 2013. (Refer to Note 9 of the Notes to the Consolidated Financial Statements in the 2012 Annual Report.)

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

RESULTS OF OPERATIONS

OVERVIEW

PG&E Corporation, incorporated in California in 1995, is a holding company that conducts its business through Pacific Gas and Electric Company, 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 4.4 million natural gas distribution customers at March 31, 2013.

The Utility is regulated primarily by the CPUC and the FERC. In addition, the 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.

Most of the Utility’s revenue requirements that the Utility is authorized to collect through rates are set by the CPUC in the GRC, which occurs generally every three years. The Utility’s revenue requirements for other portions of its operations, such as electric transmission, natural gas transportation and storage services, electricity and natural gas purchases, are authorized in other regulatory proceedings overseen by the CPUC or the FERC. The Utility’s revenue requirements are generally set 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 with an opportunity to earn its authorized ROE. 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. From time to time, the Utility also files separate applications with the CPUC requesting authority to recover costs for other projects. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows are affected by the extent to which the Utility is able to timely recover its actual costs through rates and earn its authorized ROE.

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 the 2012 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 materially affected by costs the Utility has incurred to improve the safety and reliability of its natural gas operations, as well as by costs related to the ongoing regulatory proceedings, investigations, and civil lawsuits that commenced following the San Bruno accident in September 2010. Through March 31, 2013, PG&E Corporation and the Utility have incurred cumulative charges of approximately $1.9 billion related to the San Bruno accident and natural gas matters that will not be recoverable through rates. These matters and a number of other factors will continue to have a material negative 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 pipeline-related costs ranging from $400 million to $500 million in 2013 that will not be recoverable through rates, including $62 million incurred during the three months ended March 31, 2013. (See “Operating and Maintenance” below.) Additionally, the CPUC could impose penalties that are materially higher than the $200 million accrued in connection with three pending CPUC investigations and other matters that were self-reported by the Utility related to the safety of its natural gas operations. The Utility may also incur costs to implement any remedial actions the CPUC may order the Utility to perform. On May 6, 2013, the SED and other parties are expected to file briefs to recommend the amount of penalties and other remedial actions to be imposed on the Utility based on the violations the SED alleges that the Utility committed. Based on the current procedural schedule, the Utility expects that the pending investigations will be resolved by the third quarter of 2013. (See “Pending CPUC Investigations and Enforcement Matters” below.) In addition, an ongoing investigation of the San Bruno accident by federal, state, and local authorities may result in the imposition of penalties and remedial measures on the Utility. (See “Criminal Investigation” below.) Finally, PG&E Corporation and the Utility believe it is reasonably possible that they may incur additional charges of up to $145 million for estimated third-party claims related to the San Bruno accident. (See “Third-Party Claims” below.)

The Amount and Timing of the Utility’s Equity Financing Needs. PG&E Corporation contributes equity to the Utility as needed by the Utility to maintain its CPUC-authorized capital structure. The Utility has incurred significant expenses that are not recoverable through rates, which has increased the Utility’s equity needs. For the three months ended March 31, 2013, PG&E Corporation made equity contributions to the Utility of $370 million, which were funded primarily through common stock issuances. The Utility’s future financing needs will be affected by the ultimate amount of unrecoverable costs and penalties incurred in connection with natural gas matters above. The Utility’s financing needs also will be affected by other factors, including the timing and amount of the Utility’s capital expenditures, operating expenses, and collateral requirements associated with price risk management activities. Additional equity issued by PG&E Corporation in the future to fund the Utility’s equity needs attributable to unrecoverable costs, including the ultimate amount of penalties associated with the pending investigations, is expected to have a material dilutive effect on its EPS. 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 Proceedings. The Utility’s financial results are affected by the timing and outcome of ratemaking proceedings. During 2013, the CPUC is scheduled to determine the amount of revenue requirements the Utility is authorized to recover beginning in 2014 for its electric and natural gas distribution operations and its electric generation operations in the 2014 GRC. The Utility has requested that the CPUC increase the Utility’s base revenues for 2014 by $1.28 billion over the comparable revenues for 2013 that were previously authorized. (See “2014 General Rate Case” below.) The FERC is also considering proposed changes in the Utility’s electric transmission rates in the pending TO rate case. Although the proposed rate changes became effective on May 1, 2013, the Utility’s collection of the increased rates is subject to refund following the issuance of a final decision by the FERC. (See “FERC Transmission Owner Rate Case” below.) The Utility expects to file an application with the CPUC in late 2013 to initiate the Utility’s 2015 GT&S rate case in which the CPUC will determine the rates, and terms and conditions of the Utility’s gas transmission and storage services beginning January 1, 2015. The Utility expects to address the scope, timing, and cost recovery of continuing work to enhance the safety and reliability of its gas pipeline system in the 2015 GT&S rate case. The outcome of these ratemaking proceedings can be affected by many factors, including general economic conditions, the level of customer rates, regulatory policies, and political considerations.

The Ability of the Utility to Control Operating Costs and Capital Expenditures. Rates are primarily set based on forecasts and assumptions about the amount of operating costs and capital expenditures the Utility will incur in future periods. PG&E Corporation’s and the Utility’s net income is negatively affected when the revenues provided by rates are not sufficient for the Utility to recover the costs it actually incurs. In 2013, in addition to the non-recoverable costs related to the Utility’s natural gas system described above, the Utility forecasts that it will incur approximately $250 million to improve the safety and reliability of its electric and natural gas operations that it will not recover through rates. (See “Operating and Maintenance” below.) Any future increase in the Utility’s environmental-related liabilities that are not recoverable through rates, such as costs associated with its natural gas compressor station located in Hinkley, California, also will negatively affect PG&E Corporation’s and the Utility’s net income. (See “Environmental Matters” below.) Other differences between the amount or timing of the Utility’s actual costs and forecasted or authorized amounts may also affect the Utility’s ability to earn its authorized ROE.

Summary of Changes in Earnings per Common Share and Income Available for Common Shareholders for 2013

The following table is a summary reconciliation of the key changes, after-tax, in PG&E Corporation’s income available for common shareholders and earnings per common share for the three months ended March 31, 2013 compared to the three months ended March 31, 2012 (see “Results of Operations” below):

				Earnings Per
				Common Share
(in millions, except per share amounts)	Earnings			(Diluted)
Income Available for Common Shareholders - March 31, 2012	$	233		$	0.56
Natural gas matters (1)		60			0.15
Environmental-related costs		42			0.10
Growth in rate base earnings		21			0.05
Reduction in authorized cost of capital		(44	)		(0.10	)
Nuclear refueling outage		(27	)		(0.06	)
Timing of incremental work		(13	)		(0.03	)
Gas transmission revenues		(3	)		(0.01	)
Increase in shares outstanding (2)		-			(0.04	)
Other		(30	)		(0.07	)
Income Available for Common Shareholders - March 31, 2013	$	239		$	0.55

(1) The Utility incurred charges related to natural gas matters of $62 million and $163 million, pre-tax, for the three months ended March 31, 2013 and 2012, respectively. The amount shown above represents the favorable impact attributable to the lower amount of expenses recorded in 2013. See “Operating and Maintenance” below for additional information.

(2) Represents the impact of a higher number of shares outstanding at March 31, 2013, compared to the number of shares outstanding at March 31, 2012. PG&E Corporation issues shares to fund its equity contributions to the Utility to maintain the Utility’s 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 quarterly 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 losses associated with various investigations; estimated losses and insurance recoveries associated with the civil litigation arising from the San Bruno accident; forecasts of costs the Utility will incur to make safety and reliability improvements, including costs to perform work under the pipeline safety enhancement plan, that the Utility will not recover through rates; forecasts of capital expenditures; estimates and assumptions used in critical accounting policies, including those relating to environmental remediation, tax, litigation, third-party claims, and other liabilities; 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,” “predict,” “anticipate,” “may,” “should,” “would,” “could,” “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 timing and terms of the resolution of pending investigations and enforcement matters related to the Utility’s natural gas system operating practices and the San Bruno accident, including the ultimate amount of penalties the Utility will be required to pay, the cost of any remedial actions the Utility may be ordered to perform, and whether the resolution is reached through settlement negotiations, or a fully litigated proceeding; the ultimate amount of third-party claims associated with the San Bruno accident and the timing and amount of related insurance recoveries; the ultimate amount of punitive damages, if any, the Utility may incur related to third-party claims; and the ultimate amount of civil or criminal penalties, if any, the Utility may incur related to the criminal investigation;

·	the outcomes of current ratemaking proceedings, such as the 2014 GRC and the pending TO rate case; the outcome of future ratemaking and regulatory proceedings, such as the 2015 GT&S rate case; and the outcomes of other ratemaking and regulatory proceedings;

the ultimate amount of costs the Utility incurs in the future that are not recovered through rates, including pipeline-related expenses to validate safe operating pressure, conduct strength tests, and to identify and remove encroachments from transmission pipeline easements, and costs to perform incremental work to improve the safety and reliability of electric and natural gas operations;

·	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;

whether PG&E Corporation and the Utility are able to repair the reputational harm that they have suffered, and may suffer in the future, due to the negative publicity surrounding the San Bruno accident, the related civil litigation, and the pending investigations, including any charge or finding of criminal liability;

the level of equity contributions that PG&E Corporation must make to the Utility to enable the Utility to maintain its authorized capital structure as the Utility incurs charges and costs, including costs associated with natural gas matters and penalties imposed in connection with the pending investigations, that are not recoverable through rates or insurance;

the impact of environmental remediation laws, regulations, and orders; the ultimate amount of costs incurred to discharge the Utility’s known and unknown remediation obligations; 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 environmental remediation liabilities that are not recoverable through rates or insurance, such as the remediation costs associated with the Utility’s natural gas compressor station site located near Hinkley, California;

the impact of new legislation or NRC regulations, recommendations, policies, decisions, or orders relating to the operations, seismic design, security, safety, or decommissioning of nuclear facilities, including the Utility’s Diablo Canyon nuclear power plant, or relating to the storage of spent nuclear fuel, cooling water intake, or other issues; and the ability of the Utility to relicense the Diablo Canyon units;

the impact of weather-related conditions or events (such as storms, tornadoes, floods, drought, solar or electromagnetic events, and wildland and other fires), natural disasters (such as earthquakes, tsunamis, and pandemics), and other events (such as explosions, fires, accidents, mechanical breakdowns, equipment failures, human errors, and labor disruptions), 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 environmental laws and regulations aimed at the reduction of carbon dioxide and GHGs, 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 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 extent of municipalization of the Utility’s electric distribution facilities, changing levels of “direct access” customers who procure electricity from alternative energy providers, changing levels of customers who purchase electricity from governmental bodies that act as “community choice aggregators,” and the development of alternative energy technologies including self-generation and distributed generation technologies;

the adequacy and price of electricity, natural gas, and nuclear fuel supplies; the extent to which the Utility can manage and respond to the volatility of energy commodity prices; the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and whether the Utility is able to recover timely its energy commodity costs through rates;

whether the Utility’s information technology, operating systems and networks, including the advanced metering system infrastructure, customer billing, financial, and other systems, can continue to function accurately while meeting regulatory requirements; whether the Utility is able to protect its operating systems and networks from damage, disruption, or failure caused by cyber-attacks, computer viruses, or other hazards; whether the Utility’s security measures are sufficient to protect confidential customer, vendor, and financial data contained in such systems and networks; and whether the Utility can continue to rely on third-party vendors and contractors that maintain and support some of the Utility’s operating systems;

·	the extent to which costs incurred in connection with third-party claims or litigation are not recoverable through insurance, rates, or from other third parties;

·	the ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing in a timely manner on acceptable terms;

·	the impact on the availability and costs of borrowing if the Utility were to lose its investment grade credit ratings;

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; and, in turn, PG&E Corporation’s ability to pay dividends;

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

·	the impact of changes in GAAP, standards, rules, or policies, including those related to regulatory accounting, and the impact of changes in their interpretation or application.

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 “Risk Factors” in the 2012 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.

RESULTS OF OPERATIONS

The table below details certain items from the accompanying Condensed Consolidated Statements of Income:

	Three Months Ended March 31,
(in millions)	2013			2012
Utility
Electric operating revenues	$	2,798		$	2,771
Natural gas operating revenues		873			869
Total operating revenues		3,671			3,640
Cost of electricity		983			859
Cost of natural gas		346			343
Operating and maintenance		1,336			1,366
Depreciation, amortization, and decommissioning		503			584
Total operating expenses		3,168			3,152
Operating income		503			488
Interest income		1			1
Interest expense		(170	)		(168	)
Other income, net		24			23
Income before income taxes		358			344
Income tax provision		121			113
Net income		237			231
Preferred stock dividend requirement		3			3
Income Available for Common Stock	$	234		$	228
PG&E Corporation, Eliminations, and Other (1)
Operating revenues	$	1		$	1
Operating expenses		2			2
Operating loss		(1	)		(1	)
Interest income		1			-
Interest expense		(6	)		(6	)
Other income, net		4			3
Loss before income taxes		(2	)		(4	)
Income tax benefit		(7	)		(9	)
Net income	$	5		$	5
Consolidated Total
Operating revenues	$	3,672		$	3,641
Operating expenses		3,170			3,154
Operating income		502			487
Interest income		2			1
Interest expense		(176	)		(174	)
Other income, net		28			26
Income before income taxes		356			340
Income tax provision		114			104
Net income		242			236
Preferred stock dividend requirement of subsidiary		3			3
Income Available for Common Shareholders	$	239		$	233

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

The following presents the Utility’s operating results for the three months ended March 31, 2013 and 2012.

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 the cost of electricity procurement and the cost 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)	2013			2012
Revenues excluding passed-through costs		$	1,597		$	1,575
Revenues for recovery of passed-through costs			1,201			1,196
Total electric operating revenues		$	2,798		$	2,771

The Utility’s total electric operating revenues increased by $27 million, or 1%, in the three months ended March 31, 2013, as compared to the same period in 2012. Electric operating revenues, excluding revenues intended to recover costs that are passed through to customers, increased by $22 million, primarily due to an increase in base revenues as authorized in the 2011 GRC, partially offset by a decrease in revenues authorized in the 2013 Cost of Capital proceeding. Revenues intended to recover costs that are passed through to customers and do not impact net income increased, primarily due to a $124 million increase in the cost of electricity (see “Cost of Electricity” below), offset by a $115 million decrease resulting from the absence of revenue related to ERBs that matured in late 2012.

The Utility’s future electric operating revenues are expected to be impacted by revenues authorized by the FERC in the pending TO rate case (these increased revenues became effective on May 1, 2013, subject to refund) and by the CPUC in the 2014 GRC. (See “Regulatory Matters” below.) Future electric operating revenues will also be impacted by the cost of electricity and other revenues intended to recover 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. (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 and distribution 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 amount and average cost of purchased power:

	Three Months Ended March 31,
(in millions)	2013		2012
Cost of purchased power	$	910	$	776
Fuel used in own generation facilities		73		83
Total cost of electricity	$	983	$	859
Average cost of purchased power per kWh	$	0.084	$	0.075
Total purchased power (in millions of kWh)		10,886		10,290

The Utility’s total cost of electricity increased by $124 million, or 14%, in the three months ended March 31, 2013, as compared to the same period in 2012, primarily due to the higher costs to purchase renewable energy and higher transmission costs. The volume of power the Utility purchases is driven by customer demand, the availability of the Utility’s own generation facilities, and the cost effectiveness of each source of electricity.

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

Natural Gas Operating Revenues

The Utility’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 programs.

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

	Three Months Ended March 31,
(in millions)	2013			2012
Revenues excluding passed-through costs		$	442		$	439
Revenues for recovery of passed-through costs			431			430
Total natural gas operating revenues		$	873		$	869

The Utility’s natural gas operating revenues remained flat in the three months ended March 31, 2013, as compared to the same period in 2012, primarily due to an increase in base revenues as authorized in the 2011 GT&S rate case and 2011 GRC that was offset by a decrease in revenues authorized in the 2013 Cost of Capital proceeding.

The Utility’s natural gas operating revenues are expected to increase as authorized by the CPUC in the 2011 GT&S rate case. The Utility’s future operating revenues will also depend on the amount of revenue requirements authorized by the CPUC in the Utility’s 2014 GRC and the 2015 GT&S rate case. (See “Regulatory Matters” below.) Additionally, the Utility’s future operating revenues will reflect revenues authorized by the CPUC under the Utility’s pipeline safety enhancement plan. (See “Natural Gas Matters” below.) Future gas operating revenues will also be impacted by 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, transportation of natural gas and 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. The Utility’s cost of natural gas excludes the cost of operating the Utility’s gas transmission and distribution system, which is 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 natural gas:

	Three Months Ended March 31,
(in millions)	2013		2012
Cost of natural gas sold	$	300	$	294
Transportation cost of natural gas sold		46		49
Total cost of natural gas	$	346	$	343
Average cost per Mcf (1) of natural gas sold	$	2.94	$	2.97
Total natural gas sold (in millions of Mcf) (1)		102		99

(1) One thousand cubic feet

The Utility’s total cost of natural gas slightly increased in the three months ended March 31, 2013, as compared to the same period in 2012, primarily due to an increase in the volume of natural gas sold.

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 part on its ability to manage its expenses and to achieve operational and cost efficiencies.

The Utility’s operating and maintenance expenses decreased by $30 million, or 2%, from $1,366 million in the three months ended March 31, 2012 to $1,336 million in the three months ended March 31, 2013. The total decrease in operating and maintenance expense was primarily due to $101 million of lower net costs associated with natural gas matters that are not recoverable through rates (see table below) and a $69 million decrease in environmental remediation costs associated with a charge to net income in 2012 for the Hinkley natural gas compressor site. These costs were partially offset by a $46 million increase for a scheduled refueling outage at Diablo Canyon and $21 million related to continuing work to improve the safety and reliability of the Utility’s electric and natural gas operations. The change in costs passed through to customers was immaterial.

The Utility incurred net costs of $62 million and $163 million during the three months ended March 31, 2013 and 2012, respectively, in connection with natural gas matters that are not recoverable through rates, as shown in the following table:

	Three Months Ended March 31,
(in millions)	2013		2012
Pipeline-related expenses	$	62	$	104
Insurance recoveries		-		(11	)
Contribution to City of San Bruno		-		70
Total natural gas matters	$	62	$	163

The Utility forecasts that the total unrecoverable pipeline-related expenses in 2013 will range from $400 million to $500 million. These amounts include costs to validate safe operating pressures, conduct strength testing, and perform other work associated with safety improvements to the Utility’s natural gas pipeline system. They also include costs related to the Utility’s multi-year effort to identify and remove encroachments (e.g. building structures and vegetation overgrowth) from transmission pipeline rights-of-way, to improve the integrity of transmission pipelines and to perform other gas-related work, and legal and other expenses. For the three months ended March 31, 2013, the Utility did not record any charges related to penalties or third-party claims. Since the San Bruno accident, PG&E Corporation and the Utility have incurred total cumulative charges to net income of approximately $1.9 billion related to natural gas matters that are not recoverable through rates. (See “Natural Gas Matters” below.)

Future operating and maintenance expense will continue to be affected by pipeline-related expenses and other costs associated with natural gas matters that are not recoverable through rates, including any additional charges for third-party claims arising from the San Bruno accident that are not recoverable through insurance, additional charges for civil or criminal penalties, or punitive damages, if any, that may be imposed on the Utility. The Utility may incur costs to implement any remedial actions the CPUC may order the Utility to perform. (See “Natural Gas Matters – Pending CPUC Investigations and Enforcement Matters” below.)

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation and amortization expense consists of depreciation and amortization on plant and regulatory assets, and decommissioning expenses associated with fossil fuel-fired generation facilities and nuclear power facilities. The Utility’s depreciation, amortization, and decommissioning expenses decreased by $81 million, or 14%, in the three months ended March 31, 2013, as compared to the same period in 2012. The decrease is primarily due to the absence of amortization expense of $109 million for the ERB regulatory asset, which fully amortized in 2012. This was partially offset by the impact of capital additions.

The Utility’s depreciation expense for future periods is expected to be affected as a result of changes in capital expenditures and the implementation of new depreciation rates as authorized by the CPUC in future GRCs and GT&S rate cases. Future TO rate cases authorized by the FERC will also have an impact on depreciation rates.

Interest Income, Interest Expense and Other Income, Net

There were no material changes to interest income, interest expense and other income, net for the three months ended March 31, 2013, as compared to the same period in 2012.

Income Tax Provision

There were no material changes to the Utility’s income tax provision, or the effective tax rate, in the three months ended March 31, 2013, as compared to the same period in 2012.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

The Utility’s ability to fund operations and make distributions to PG&E Corporation 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 long-term 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. 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, 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.

PG&E Corporation’s and the Utility’s credit ratings may affect their access to the credit and capital markets and their respective financing costs in those markets. Credit rating downgrades may increase the cost of short-term borrowing, including the Utility’s commercial paper, as well as the costs associated with their respective credit facilities, and long-term debt.

Revolving Credit Facilities and Commercial Paper Program

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, 2013:

					Letters of
	Termination	Facility			Credit				Commercial			Facility
	Date	Limit			Outstanding		Borrowings		Paper			Availability
(in millions)
PG&E Corporation	May 2016	$	300	(1)	$	-	$	120	$	-		$	180
Utility	May 2016		3,000	(2)		243		-		368	(3)		2,389	(3)
Total revolving credit facilities		$	3,300		$	243	$	120	$	368		$	2,569

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

(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, 2013, the average and maximum outstanding borrowings under PG&E Corporation’s revolving credit facility were $120 million. On April 30, 2013, PG&E Corporation borrowed an additional $140 million under its revolving credit facility for total borrowings of $260 million. For the three months ended March 31, 2013, the Utility’s average outstanding commercial paper balance was $257 million and the maximum outstanding balance during the quarter was $450 million. The Utility did not borrow under its credit facility for the three months ended March 31, 2013.

The revolving credit facilities include usual and customary provisions for revolving credit facilities of this type, including those regarding events of default and 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. PG&E Corporation’s 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, 2013, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

On April 1, 2013, PG&E Corporation and the Utility entered into an amendment and restatement of their respective $300 million and $3.0 billion five-year revolving credit facilities that were entered into on May 30, 2011. PG&E Corporation’s and the Utility’s amended and restated credit agreements contain substantially similar terms as their 2011 credit agreements, except that the termination dates have been extended to April 1, 2018.

2013 Financings

During the three months ended March 31, 2013, PG&E Corporation issued a total of 10,790,880 shares of its common stock for aggregate net cash proceeds of $426 million comprised of the following:

·	7,200,000 shares were sold in an underwritten public offering for cash proceeds of $300 million, net of fees and commissions;

·	2,109,980 shares that were issued for cash proceeds of $63 million under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans; and

·	1,480,900 shares were sold for cash proceeds of $63 million, net of fees of $1 million, exhausting the remaining capacity under the equity distribution agreement executed in November 2011.

The proceeds from these sales were used for general corporate purposes, including the infusion of equity into the Utility. For the three months ended March 31, 2013, PG&E Corporation made equity contributions to the Utility of $370 million. In addition, on April 30, 2013, PG&E Corporation made equity contributions of $210 million to the Utility.

PG&E Corporation forecasts that it will need to continue to issue additional common stock to fund the Utility’s equity needs. PG&E Corporation intends to enter into a new equity distribution agreement with a maximum aggregate offering price of $400 million on May 2, 2013 to partially fund these needs. See “Future Financing Needs” below.

Future Financing Needs

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

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

·	the timing and amount of forecasted capital expenditures;

·	the timing and amount of payments made to third parties in connection with the San Bruno accident, and the timing and amount of related insurance recoveries (see “Natural Gas Matters” below);

·	the timing and amount of penalties imposed on the Utility in connection with the pending investigations and other potential enforcement matters related to the San Bruno accident and the Utility’s natural gas operations (see “Natural Gas Matters” below);

·	the timing and amount of pipeline-related expenses and other expenses to improve the safety and reliability of the Utility’s electric and natural gas operations that are not recoverable through rates (see “Operating and Maintenance” above);

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

·	the amount of future tax payments;

·	the conditions in the capital markets, and other factors; and

·	the maturity date of existing debt instruments, including the $1.0 billion of senior notes due in March 2014.

PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure. The CPUC has authorized the Utility’s capital structure through 2015 for the Utility’s electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base, consisting of 52% common equity, 47% long-term debt, and 1% preferred stock. The CPUC also authorized the Utility to earn a ROE of 10.40% effective January 1, 2013, compared to the 11.35% previously authorized. (See the “2013 Cost of Capital Proceeding” discussion in “Regulatory Matters” below.) The Utility’s future equity needs will continue to be affected by costs that are not recoverable through rates, including costs related to natural gas matters. Further, given the Utility’s significant ongoing capital expenditures, the Utility will continue to need equity contributions from PG&E Corporation to maintain its authorized capital structure.

PG&E Corporation’s equity contributions to the Utility are funded primarily through common stock issuances. PG&E Corporation also may use draws under its revolving credit facility to occasionally fund equity contributions on an interim basis. Additional common stock issued by PG&E Corporation in the future to fund further equity contributions to the Utility could have a material dilutive effect on PG&E Corporation’s earnings per common share, primarily depending upon the resolution of the pending investigations and the ultimate amount of unrecoverable operating and maintenance costs the Utility incurs.

Dividends

On February 20, 2013 , the Board of Directors of PG&E Corporation declared quarterly dividends of $0.455 per share, totaling $202 million, of which $196 million was paid on April 15, 2013 to shareholders of record on March 28, 2013. The remaining $6 million was reinvested under the Dividend Reinvestment and Stock Purchase Plan.

On February 20, 2013, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on May 15, 2013, to shareholders of record on April 30, 2013.

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, 2013 and 2012 were as follows:

(in millions)	2013			2012
Net income	$	237		$	231
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, amortization, and decommissioning		503			584
Allowance for equity funds used during construction		(26	)		(27	)
Deferred income taxes and tax credits, net		163			153
Other		37			57
Net effect of changes in operating assets and liabilities		(7	)		(49	)
Net cash provided by operating activities	$	907		$	949

During 2013, net cash provided by operating activities decreased by $42 million compared to 2012. The 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.

Future cash flow from operating activities will be affected by the timing and amount of payments to be made to third parties in connection with the San Bruno accident and related insurance recoveries; the timing and amount of penalties that may be assessed, as well as any remedial actions the CPUC may order the Utility to perform; and the anticipated 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 such as 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 generation facilities.

The Utility’s cash flows from investing activities for the three months ended March 31, 2013 and 2012 were as follows:

(in millions)	2013			2012
Capital expenditures	$	(1,249	)	$	(1,094	)
Decrease (increase) in restricted cash		26			(5	)
Proceeds from sales and maturities of nuclear decommissioning trust investments		363			351
Purchases of nuclear decommissioning trust investments		(364	)		(370	)
Other		5			3
Net cash used in investing activities	$	(1,219	)	$	(1,115	)

Net cash used in investing activities increased by $104 million in 2013 compared to 2012 primarily due to higher capital expenditures. The increase in capital expenditures was partially offset by a reduction of $31 million in restricted cash held in escrow for third-party agreements.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures.

Financing Activities

The Utility’s cash flows from financing activities for the three months ended March 31, 2013 and 2012 were as follows:

(in millions)	2013			2012
Net repayments of commercial paper, net of discount of $1 in 2012	$	(2	)	$	(245	)
Energy recovery bonds matured		-			(102	)
Preferred stock dividends paid		(3	)		(3	)
Common stock dividends paid		(179	)		(179	)
Equity contribution		370			385
Other		(15	)		51
Net cash provided by (used in) financing activities	$	171		$	(93	)

In 2013, net cash provided by financing activities increased by $264 million compared to the same period in 2012. 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 long-term senior unsecured debt issuances and equity contributions from PG&E Corporation to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.

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 purchases of fuel and transportation to support the Utility’s generation activities. (Refer to the 2012 Annual Report and “Liquidity and Financial Resources” above.)

NATURAL GAS MATTERS

PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows, have continued to be negatively affected by costs the Utility has incurred to improve the safety and reliability of the Utility’s natural gas operations, as well as by costs related to the on-going regulatory proceedings, investigations, and civil lawsuits related to the San Bruno accident and the Utility’s natural gas operations. During the three months ended March 31, 2013, the Utility continued to make progress on efforts to improve the safety of its gas transmission system and to satisfy recommendations made by the NTSB and the CPUC following their investigations into the San Bruno accident. As of March 31, 2013, the Utility had satisfied seven of the twelve NTSB recommendations. The NTSB has stated that the Utility’s progress on satisfying the remaining five recommendations was acceptable. The Utility expects to satisfy three more recommendations by the end of 2013. Since the San Bruno accident in September 2010, PG&E Corporation and the Utility have incurred total cumulative charges to net income of approximately $1.9 billion related to natural gas matters that are not recoverable through rates, as shown in the following table:

	Three Months Ended March 31,					Cumulative
(in millions)	2013		2012			Charges (5)
Pipeline-related expenses(1)	$	62	$	104		$	1,085
Disallowed capital expenditures(1)		-		-			353
Accrued penalties(2)		-		-			217
Third-party claims(3)		-		-			455
Insurance recoveries(3)		-		(11	)		(284	)
Contribution to City of San Bruno(4)		-		70			70
Total natural gas matters	$	62	$	163		$	1,896

(1) See “CPUC Gas Safety Rulemaking Proceeding” below.

(2) See “Pending CPUC Investigations and Enforcement Matters” below. Amount includes $17 million penalty that was paid in 2012.

(3) See “Third-Party Claims” below.

(4) 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.

(5) Total cumulative charges to net income since the San Bruno accident in September 2010.

Pending CPUC Investigations and Enforcement Matters

PG&E Corporation and the Utility continue to believe it is probable that the Utility will incur penalties of at least $200 million in connection with these pending investigations and potential enforcement matters and have accrued this amount in their condensed consolidated financial statements. PG&E Corporation and the Utility are unable to make a better estimate of probable losses or estimate the amount of reasonably possible losses in excess of $200 million due to the many variables that could affect the final outcome of these matters. These variables include how the total number and duration of violations will be determined; whether penalties will be determined separately in each investigative proceeding or in the aggregate; how the testimony of the financial consultants will be considered; whether the Utility’s costs to perform any required remedial actions will be considered; how the CPUC responds to increasing public pressure; and whether and how the financial impact of non-recoverable costs the Utility has already incurred, and will continue to incur, to improve the safety and reliability of its pipeline system, will be considered. (See “CPUC Gas Safety Rulemaking Proceeding” below.) Future changes in these estimates or the assumptions on which they are based could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. The ultimate amount of penalties imposed on the Utility could be materially higher than the amount accrued.

CPUC Gas Safety Rulemaking Proceeding

The CPUC is conducting a rulemaking proceeding to develop and adopt new safety and reliability regulations for natural gas transmission and distribution pipelines in California and the related ratemaking mechanisms. On December 28, 2012, the CPUC issued a decision that approved most of the Utility’s pipeline safety enhancement plan to modernize and upgrade its natural gas transmission system, but disallowed the Utility’s request for rate recovery of a significant portion of plan-related costs the Utility forecasted it would incur over the first phase of the plan (2011 through 2014). The CPUC stated that the Utility’s recovery of the amounts authorized in the decision will be subject to refund, noting the possibility that further ratemaking adjustments may be made in the pending CPUC investigations in which the CPUC will address potential penalties to be imposed on the Utility. (See “Pending CPUC Investigations and Enforcement Matters” above.) In addition, the CPUC may disallow additional costs or adjust the authorized revenue requirements based on the final results of the Utility’s pipeline records search and pipeline pressure validation work. The Utility is required to update its plan and file an expedited update application within 30 days after this work is completed, which the Utility expects to complete in the third quarter of 2013.

In 2012, the Utility recorded a $353 million charge to net income for plan-related capital expenditures incurred that are forecasted to exceed the CPUC’s authorized levels or that were specifically disallowed. The Utility will update its forecasts as the project continues and may incur additional charges to net income. For the three months ended March 31, 2013, the Utility incurred pipeline-related expenses of $62 million in operating and maintenance expense that will not be recoverable through rates, including plan-related expenses of $25 million. Unrecoverable plan-related expenses are expected to range from approximately $150 million to $200 million in 2013. The Utility expects to continue to incur unrecoverable expenses in 2014.

Several parties have filed applications for rehearing of the CPUC’s decision. The applications for rehearing state, among other arguments, that the CPUC should have disallowed more of the Utility’s costs and that the CPUC should have approved a reduced ROE for capital expenditures made under the plan. Several parties also have filed petitions for modification of the decision. It is uncertain whether or when the CPUC will grant these requests.

The second phase of the Utility’s pipeline safety enhancement plan beginning in 2015 will focus on pipeline segments in less populated areas, as well as certain pressure testing and pipeline replacement work that the CPUC deferred from the first phase. The Utility expects to file an application with the CPUC in late 2013 to initiate the Utility’s 2015 GT&S rate case, in which the CPUC will determine the rates, and terms and conditions of the Utility’s gas transmission and storage services beginning January 1, 2015. The Utility expects to address the scope, timing, and cost recovery of continuing work to enhance the safety and reliability of the gas pipeline system in the 2015 GT&S rate case.

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 and have indicated that the Utility is a target of the investigation. The Utility is cooperating with the investigation. PG&E Corporation and the Utility are uncertain whether any criminal charges will be brought against either company or any of their current or former employees. A criminal charge or finding would further harm the Utility’s reputation. 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 and such penalties could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. In addition, the Utility’s business or operations could be negatively affected by any remedial measures imposed on the Utility.

Third-Party Claims

In addition to the investigations and proceedings discussed above, as of March 31, 2013, approximately 160 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, had been filed against PG&E Corporation and the Utility in connection with the San Bruno accident on behalf of approximately 480 plaintiffs. The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages. The Utility has entered into settlement agreements to resolve the claims of approximately 140 plaintiffs and other claimants. The Utility and most of the remaining plaintiffs are engaged in settlement discussions. Since the San Bruno accident, the Utility has recorded cumulative charges of $455 million through March 31, 2013 for estimated third-party claims, including personal injury and property damage, damage to infrastructure, and other damage claims. The Utility has made cumulative payments of $382 million for settlements of these claims. The Utility estimates it is reasonably possible that it may incur as much as an additional $145 million for third-party claims, for a total possible loss of $600 million since the San Bruno accident. This estimate is subject to change as more information becomes known about the unresolved claims. 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.)

Through March 31, 2013, the Utility has recognized cumulative insurance recoveries of $284 million for third-party claims. 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 additional insurance recoveries. (See Note 10 to the Condensed Consolidated Financial Statements.)

Class Action Complaint

Other Pending Lawsuits and Claims

At March 31, 2013, there were two purported shareholder derivative lawsuits outstanding against PG&E Corporation and the Utility. In October 2010, a derivative lawsuit was filed in San Mateo Superior Court 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, relating to the Utility’s natural gas business. The proceedings have been stayed until further order of the court. On February 7, 2013, another derivative lawsuit was filed in U.S. District Court for the Northern District of California to seek recovery on behalf of PG&E Corporation for alleged breaches of fiduciary duty by officers and directors, among other claims. By agreement among the parties, this second derivative lawsuit is stayed in its entirety pending resolution of the first filed matter.

In February 2011, the Board of Directors of PG&E Corporation authorized PG&E Corporation to reject a demand made by another shareholder that the Board of Directors (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 of Directors members, officers, other employees, and third parties; and (3) adopt corporate governance initiatives and safety programs. The Board of Directors also reserved the right to commence further investigation or litigation regarding the San Bruno accident if the Board of Directors deems such investigation or litigation appropriate.

PG&E Corporation and the Utility are uncertain when and how the above matters will be resolved.

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 financial condition, results of operations, and cash flows. Significant regulatory developments that have occurred since the 2012 Annual Report was filed with the SEC are discussed below.

2014 General Rate Case

In November 2012, the Utility filed its 2014 GRC application to request that the CPUC 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 operations for 2014 through 2016. The Utility has requested that the CPUC increase the Utility’s base revenues for 2014 by $1.28 billion over the comparable revenues for 2013 that were previously authorized. The Utility also requested additional revenue increases of $492 million in 2015 and $504 million in 2016. (See the 2012 Annual Report for additional information.)

Independent consultants engaged by the SED are reviewing and evaluating certain operational plans underlying the Utility’s 2014 cost forecast to ensure that safety and security concerns have been addressed and that the plans properly incorporate risk assessments and mitigation measures. The SED has also engaged independent consultants to conduct a financial review of the Utility’s gas distribution system, which will examine the Utility’s authorized and budgeted capital investments and operation and maintenance expenditures for its recent GRC cycles. The SED reports on the results of the consultants’ evaluations and financial review are due May 17, 2013 and May 31, 2013, respectively. The Utility and other parties will be able to respond to the reports.

The DRA is scheduled to serve its report on the Utility’s application on May 3, 2013. Testimony from other parties is scheduled to be submitted by May 17, 2013. The CPUC’s current procedural schedule contemplates evidentiary hearings to be held this summer, followed by a proposed decision to be released in November 2013 and a final CPUC decision to be issued in December 2013. Consistent with practice in prior GRCs, the CPUC has authorized the revenue requirement changes to become effective as of January 1, 2014, even if the final decision is issued after that date.

FERC Transmission Owner Rate Case

As discussed in the 2012 Annual Report, in December 2012, the Utility revised its requested revenue requirements and rates being considered in its pending TO rate case to comply with an order issued by the FERC to reflect a 9.1% ROE on electric transmission assets, rather than the 11.5% the Utility originally requested. The Utility has filed a request for rehearing of the FERC’s order but it is uncertain when the request will be addressed. Based on the reduced ROE, the Utility estimates that TO revenues would increase by approximately $158 million, for total annual electric transmission revenues of $1.1 billion. The proposed rate changes, based on a 9.1% ROE, became effective on May 1, 2013, subject to refund following the issuance of a final decision by the FERC. The resolution of revenue requirements and rates will be addressed through settlement or hearing procedures. Hearings are currently held in abeyance while settlement discussions are held. It is uncertain when the rate case will be resolved.

2013 Cost of Capital Proceeding

The CPUC has authorized the Utility’s capital structure through 2015 for the Utility’s electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base, consisting of 52% common equity, 47% long-term debt, and 1% preferred stock. The CPUC also authorized the Utility to earn a ROE of 10.40% effective January 1, 2013, compared to the 11.35% previously authorized.

On March 21, 2013, the CPUC issued a final decision that retains the annual cost of capital adjustment mechanism. Under the mechanism, the Utility’s ROE of 10.40% would be adjusted if the 12-month October-through-September average of the Moody's Investors Service long-term Baa utility bond index increases or decreases by more than 1.00% as compared to the applicable benchmark. If the adjustment mechanism is triggered, the Utility’s authorized ROE, beginning January 1st of the following year, would be adjusted by one-half of the difference between the index and the benchmark. Additionally, the Utility’s authorized costs of long-term debt and preferred stock would be updated to reflect actual August month-end embedded costs and forecasted interest rates for variable long-term debt, as well as new long-term debt and preferred stock scheduled to be issued. In any year where the 12-month average yield triggers an automatic ROE adjustment, that average would become the new benchmark.

The Utility will file its next full cost of capital application in April 2015 for the 2016 test year.

Oakley Generation Facility

In December 2012, the CPUC approved an amended purchase and sale agreement between the Utility and a third-party developer that provides for the construction of a 586-megawatt natural gas-fired facility in Oakley, California. The CPUC authorized the Utility to recover the purchase price through rates. On April 18, 2013, the CPUC denied various applications for rehearing that had been filed with respect to the CPUC’s December 2012 decision. The parties have 30 days to file an appeal of the CPUC’s decision at either the California Supreme Court or the California Court of Appeal. The Utility is uncertain whether appeals will be filed at the courts.

Diablo Canyon Nuclear Power Plant

The Utility’s application to renew the operating licenses for the two operating units at Diablo Canyon (which expire in 2024 and 2025) is pending with the NRC. In May 2011, after the earthquake and tsunami that caused significant damage to the Fukushima-Dai-ichi nuclear facilities in Japan, the NRC granted the Utility’s request to delay processing the Utility’s application until certain advanced seismic studies were completed by the Utility. The Utility plans to complete its seismic studies and submit a final report to the NRC by June 2014. After the final report has been submitted, the Utility will determine whether and when it will request the NRC to resume the relicensing proceeding. In order for the NRC to issue renewed operating licenses, the California Coastal Commission must determine that license renewal is consistent with federal and state coastal laws. The disposition of the Utility’s relicensing application also will be affected by the terms and timing of the NRC’s “waste confidence” decision regarding the environmental impacts of the storage of spent nuclear fuel which is not expected to be issued before September 2014. The NRC has stated that it will not take action in licensing or re-licensing proceedings until it issues a new “waste confidence decision.”

The CPUC is also considering the Utility’s December 2012 application to recover estimated costs to decommission the Utility’s nuclear facilities at Diablo Canyon and the retired nuclear facility located at the Utility’s Humboldt Bay Generation Station. The Utility files an application with the CPUC every three years requesting approval of the Utility’s estimated decommissioning costs and authorization to recover the estimated costs through rates. As discussed in the 2012 Annual Report, the estimated discounted cost to decommission the Utility’s nuclear power plants increased by $1.4 billion due to higher spent nuclear fuel disposal costs and an increase in the scope of work. The Utility requested that the CPUC issue a final decision by the end of 2013.

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” below.) 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.

Hinkley Site

GHG Cap-and-Trade

California Assembly Bill 32 requires the gradual reduction of state-wide GHG emissions to the 1990 level by 2020. The CARB is the state agency charged with adopting regulations to implement and enforce AB 32. The CARB has established a state-wide, comprehensive “cap-and-trade” program that sets a gradually declining limit (or “cap”) on the amount of GHGs that may be emitted by the major sources of GHG emissions each year. The cap and trade program’s first two-year compliance period, which began on January 1, 2013, applies to the electricity generation and large industrial sectors. The next compliance period, from January 1, 2015 through December 31, 2017, will expand to include the natural gas supply and transportation sectors, effectively covering all the capped sectors until 2020.

Each year, the CARB will issue emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHG emissions allowed for that year. Emitters can obtain allowances from the CARB at quarterly auctions held by the CARB or from third parties or exchanges on the secondary market for trading GHG allowances. Also, during each year of the program, the CARB will allocate a fixed number of allowances (which will decrease each year) for free to regulated electric distribution utilities, including the Utility, for the benefit of their electricity customers. The utilities are required to consign their allowances for auction by the CARB. The CPUC has ordered the utilities to allocate their auction revenues, including accrued interest, among certain classes of their electricity distribution customers in accordance with existing state law. Although the CPUC had previously authorized the utilities to recover their GHG compliance costs through rates, the CPUC decided that the recovery of these costs should be deferred until the CPUC adopted a final revenue allocation methodology. Until a final methodology is adopted, the utilities have been ordered to track GHG costs and auction revenues for future rate recovery.

The Utility expects all costs and revenues associated with GHG cap-and-trade to be passed through to customers.

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.

RISK MANAGEMENT ACTIVITIES

PG&E Corporation and the Utility, 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; emissions allowances, other goods and services; and other aspects of their businesses. PG&E Corporation and the Utility categorize market risks as “price risk” and “interest rate risk.” The Utility is also exposed to “credit risk,” the risk that counterparties fail to perform their contractual obligations.

The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes. The Utility’s risk management activities include the use of energy and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases. These activities are discussed in detail in the 2012 Annual Report. There were no significant developments to the Utility and PG&E Corporation’s risk management activities during the three months ended March 31, 2013.

CRITICAL ACCOUNTING POLICIES

The preparation of the Condensed Consolidated Financial Statements in accordance with U.S. generally accepted accounting principles involved the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the Condensed Consolidated 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 benefits plans to be critical accounting policies due, in part, to these accounting policies’ complexity, relevance and materiality to the financial position and results of operations of PG&E Corporation and the Utility, and requirement to use material judgments and estimates. Actual results may differ substantially from these estimates. These accounting policies and their key characteristics are discussed in detail in the 2012 Annual Report.

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

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

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 commodity 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, 2013, 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 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 Securities Exchange Act of 1934 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 three months ended March 31, 2013 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information about the significant risks that could affect PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows, see the section of the 2012 Annual Report entitled “Risk Factors” and the section of this quarterly report entitled “Cautionary Language Regarding Forward-Looking 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 2012 Annual Report.

Litigation Related to the San Bruno Accident and Natural Gas Spending

Various lawsuits have been filed in San Mateo County Superior Court against PG&E Corporation and the Utility in connection with the San Bruno accident, including two class action lawsuits. The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages. At March 31, 2013, the Utility has entered into settlement agreements to resolve the claims of approximately 140 plaintiffs. The Utility and most of the remaining plaintiffs are engaged in settlement discussions. It is uncertain whether or when the Utility will be able to resolve the remaining claims through settlement. Additionally, at March 31, 2013, there were two purported shareholder derivative lawsuits outstanding against PG&E Corporation and the Utility seeking recovery on behalf of PG&E Corporation for alleged breaches of fiduciary duty by officers and directors, among other claims. One of these lawsuits has been coordinated with the other cases in the San Mateo County Superior Court. The judge has ordered that proceedings in the derivative lawsuit be delayed until further order of the court. The other purported shareholder derivative lawsuit, filed in U.S. District Court for the Northern District of California, has been stayed pending the resolution of the first-filed derivative matter. PG&E Corporation and the Utility are uncertain when and how these derivative lawsuits will be resolved.

In addition, on August 23, 2012, a complaint was filed in the San Francisco Superior Court against PG&E Corporation and the Utility (and other unnamed defendants) by individuals who seek certification of a class consisting of all California residents who were customers of the Utility between 1997 and 2010, with certain exceptions. The plaintiffs allege that the Utility collected more than $100 million in customer rates from 1997 through 2010 for the purpose of various safety measures and operations projects but instead used the funds for general corporate purposes such as executive compensation and bonuses. PG&E Corporation and the Utility contest the allegations.

For additional information, see “Part I, Item 3. Legal Proceedings” in the 2012 Annual Report and the discussion 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.

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. Evidentiary hearings and briefing on the issue of alleged violations have been completed in each of these investigations. On May 6, 2013, the SED and other parties are expected to file briefs to recommend the amount of penalties and other remedial actions to be imposed on the Utility based on the violations the SED alleges that the Utility committed. Based on the current procedural schedule, the Utility expects that the pending investigations will be resolved by the third quarter of 2013. The CPUC has stated that it is prepared to impose significant penalties on the Utility if the CPUC determines that the Utility violated applicable laws, rules, and orders. Many factors can be considered in determining the amount of penalties to impose on the Utility, including the financial resources of the Utility.

As of March 31, 2013, the Utility has also submitted 48 self-reports with the SED, plus additional follow-up reports, to provide notice about self-identified and self-corrected violations of certain state and federal regulations related to the safety of natural gas facilities and natural gas operating practices. The SED is authorized to issue citations and impose penalties on the Utility associated with these or future reports that the Utility may file. PG&E Corporation and the Utility are uncertain whether the SED will issue citations and impose penalties on the Utility based on the self-reports the Utility has already submitted.

In addition, the Utility has notified the CPUC and the SED that the Utility is undertaking a system-wide effort to survey its transmission pipelines and identify and remove encroachments from pipeline rights-of-way over a multi-year period. PG&E Corporation and the Utility are uncertain whether additional proceedings or investigations will be commenced that could result in regulatory orders or the imposition of penalties on the Utility.

For additional information, see “Part I, Item 3. Legal Proceedings” in the 2012 Annual Report and the discussion entitled “Natural Gas Matters – Pending CPUC Investigations and Enforcement 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.

Criminal Investigation

On June 9, 2011, the Utility was notified that representatives from the U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo County District Attorney’s Office are conducting an investigation of the San Bruno accident. These representatives have indicated that the Utility is a target of the investigation. The Utility is cooperating with the investigation. PG&E Corporation and the Utility are uncertain whether any criminal charges will be brought against either company or any of their current or former employees. A criminal charge or finding would further harm the Utility’s reputation. 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 and such penalties could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. In addition, the Utility’s business or operations could be negatively affected by any remedial measures imposed on the Utility.

ITEM 1A. RISK FACTORS

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

During the three months ended March 31, 2013, PG&E Corporation made equity contributions totaling $370 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 three months ended March 31, 2013.

Issuer Purchases of Equity Securities

During the three months ended March 31, 2013, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the three months ended March 31, 2013, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

ITEM 5. OTHER INFORMATION

Since January 1, 2013 PG&E Corporation has made equity contributions to the Utility totalling $580 million, including equity contributions of $210 million that were made on April 30, 2013.

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, 2013 was 2.58. The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the three months ended March 31, 2013 was 2.53. 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, 2013 was 2.49. 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.

ITEM 6. EXHIBITS

10.1	Amended and restated credit agreement dated April 1, 2013 among (1) PG&E Corporation as borrower, (2) Bank of America, N.A., as administrative agent and a lender, (3) J.P. Morgan Securities LLC, Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBS Securities Inc. and Wells Fargo Securities LLC as joint lead arrangers and joint bookrunners, (4) Citibank N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, (5) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, and Sumitomo Mitsui Banking Corporation

10.2	Amended and restated credit agreement dated April 1, 2013 among (1) Pacific Gas and Electric Company as borrower, (2) Citibank N.A., as administrative agent and a lender, (3) Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, RBS Securities Inc. and Wells Fargo Securities LLC as joint lead arrangers and joint bookrunners, (4) Bank of America, N.A. and JPMorgan Chase Bank, N.A. as co-syndication agents and lenders, (5) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, and Sumitomo Mitsui Banking Corporation

*10.3	Form of Restricted Stock Unit Agreement for 2013 grants under the PG&E Corporation 2006 Long-Term Incentive Plan

*10.4	Form of Performance Share Agreement for 2013 grants under the PG&E Corporation 2006 Long-Term Incentive Plan

*10.5	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2013 grant under the PG&E Corporation 2006 Long-Term Incentive Plan

*10.6	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2013 grant under the PG&E Corporation 2006 Long-Term Incentive Plan

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.

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, 2013

EXHIBIT INDEX

10.1	Amended and restated credit agreement dated April 1, 2013 among (1) PG&E Corporation as borrower, (2) Bank of America, N.A., as administrative agent and a lender, (3) J.P. Morgan Securities LLC, Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBS Securities Inc. and Wells Fargo Securities LLC as joint lead arrangers and joint bookrunners, (4) Citibank N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, (5) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, and Sumitomo Mitsui Banking Corporation

10.2	Amended and restated credit agreement dated April 1, 2013 among (1) Pacific Gas and Electric Company as borrower, (2) Citibank N.A., as administrative agent and a lender, (3) Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, RBS Securities Inc. and Wells Fargo Securities LLC as joint lead arrangers and joint bookrunners, (4) Bank of America, N.A. and JPMorgan Chase Bank, N.A. as co-syndication agents and lenders, (5) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, and Sumitomo Mitsui Banking Corporation

*10.3	Form of Restricted Stock Unit Agreement for 2013 grants under the PG&E Corporation 2006 Long-Term Incentive Plan

*10.4	Form of Performance Share Agreement for 2013 grants under the PG&E Corporation 2006 Long-Term Incentive Plan

*10.5	Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2013 grant under the PG&E Corporation 2006 Long-Term Incentive Plan

*10.6	Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2013 grant under the PG&E Corporation 2006 Long-Term Incentive Plan

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.