PACIFIC GAS & ELECTRIC Co - FORM 10-Q

Attached files

file	filename
EX-3.1 - BYLAWS OF PG&E CORPORATION AMENDED AS OF MAY 1, 2011 - PACIFIC GAS & ELECTRIC Co	dex31.htm
EX-3.2 - BYLAWS OF PACIFIC GAS AND ELECTRIC COMPANY AMENDED AS OF MAY 1, 2011 - PACIFIC GAS & ELECTRIC Co	dex32.htm
EX-31.2 - CERTIFICATIONS OF CEO AND CFO OF PACIFIC GAS & ELEC CO REQUIRED BY SECTION 302 - PACIFIC GAS & ELECTRIC Co	dex312.htm
EX-31.1 - CERTIFICATIONS OF CEO AND CFO OF PG&E CORPORATION REQUIRED BY SECTION 302 - PACIFIC GAS & ELECTRIC Co	dex311.htm
EX-12.2 - COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES-PREF STOCK DIVIDENDS - PACIFIC GAS & ELECTRIC Co	dex122.htm
EX-10.1 - FORM OF RESTRICTED STOCK UNIT AGREEMENT FOR 2011 GRANTS - PACIFIC GAS & ELECTRIC Co	dex101.htm
EX-12.3 - COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES FOR PG&E COMPANY - PACIFIC GAS & ELECTRIC Co	dex123.htm
EX-32.2 - CERTIFICATIONS OF CEO AND CFO OF PACIFIC GAS & ELEC CO REQUIRED BY SECTION 906 - PACIFIC GAS & ELECTRIC Co	dex322.htm
EX-10.2 - FORM OF PERFORMANCE SHARE AGREEMENT FOR 2011 GRANTS - PACIFIC GAS & ELECTRIC Co	dex102.htm
EX-32.1 - CERTIFICATIONS OF CEO AND CFO OF PG&E CORPORATION REQUIRED BY SECTION 906 - PACIFIC GAS & ELECTRIC Co	dex321.htm
EX-12.1 - COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES - PACIFIC GAS & ELECTRIC Co	dex121.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, 2011 OR
[ ]		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to


Commission File Number	Exact Name of Registrant as specified in its charter	State or other Jurisdiction of Incorporation	IRS Employer Identification Number

1-12609	PG&E Corporation	California	94-3234914
1-2348	Pacific Gas and Electric Company	California	94-0742640
Pacific Gas and Electric Company 77 Beale Street P.O. Box 770000 San Francisco, California 94177		PG&E Corporation One Market, Spear Tower Suite 2400 San Francisco, California 94105
Address of principal executive offices, including zip code
Pacific Gas and Electric Company (415) 973-7000		PG&E Corporation (415) 267-7000

Registrant’s telephone number, including area code

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

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


PG&E Corporation		[X] Yes [ ] No

Pacific Gas and Electric Company:		[ ] 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 25, 2011:


PG&E Corporation		397,949,716
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, 2011

TABLE OF CONTENTS


PART I.	FINANCIAL INFORMATION		PAGE
ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
	Condensed Consolidated Statements of Income		2
	Condensed Consolidated Balance Sheets		3
	Condensed Consolidated Statements of Cash Flows		5
	Pacific Gas and Electric Company
	Condensed Consolidated Statements of Income		6
	Condensed Consolidated Balance Sheets		7
	Condensed Consolidated Statements of Cash Flows		9
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:	Organization and Basis of Presentation	10
	NOTE 2:	Significant Accounting Policies	10
	NOTE 3:	Regulatory Assets, Liabilities, and Balancing Accounts	12
	NOTE 4:	Debt	15
	NOTE 5:	Equity	16
	NOTE 6:	Earnings Per Share	16
	NOTE 7:	Derivatives and Hedging Activities	18
	NOTE 8:	Fair Value Measurements	22
	NOTE 9:	Resolution of Remaining Chapter 11 Disputed Claims	27
	NOTE 10:	Commitments and Contingencies	27

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview		35
	Cautionary Language Regarding Forward-Looking Statements		37
	Results of Operations		40
	Liquidity and Financial Resources		45
	Contractual Commitments		49
	Capital Expenditures		49
	Off-Balance Sheet Arrangements		49
	Contingencies		49
	Natural Gas Pipeline Matters		49
	Regulatory Matters		53
	Environmental Matters		57
	Legal Matters		58
	Risk Management Activities		58
	Critical Accounting Policies		60

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		61
ITEM 4.	CONTROLS AND PROCEDURES		61

PART II.	OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS		62
ITEM 1A.	RISK FACTORS		63
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		64
ITEM 5.	OTHER INFORMATION		64
ITEM 6.	EXHIBITS		65

SIGNATURES			66

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)	2011		2010
Operating Revenues
Electric		$ 2,617		$ 2,510
Natural gas		980		965

Total operating revenues		3,597		3,475

Operating Expenses
Cost of electricity		888		920
Cost of natural gas		508		495
Operating and maintenance		1,226		991
Depreciation, amortization, and decommissioning		491		451

Total operating expenses		3,113		2,857

Operating Income		484		618
Interest income		2		2
Interest expense		(177)		(168)
Other income (expense), net		17		(6)

Income Before Income Taxes		326		446
Income tax provision		124		185

Net Income		202		261
Preferred stock dividend requirement of subsidiary		3		3

Income Available for Common Shareholders		$ 199		$ 258

Weighted Average Common Shares Outstanding, Basic		396		371

Weighted Average Common Shares Outstanding, Diluted		397		389

Net Earnings Per Common Share, Basic		$ 0.50		$ 0.69

Net Earnings Per Common Share, Diluted		$ 0.50		$ 0.67

Dividends Declared Per Common Share		$ 0.46		$ 0.46

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


	(Unaudited)
	Balance At
(in millions)	March 31, 2011		December 31, 2010
ASSETS
Current Assets
Cash and cash equivalents		$ 240		$ 291
Restricted cash ($35 and $38 related to energy recovery bonds at March 31, 2011 and December 31, 2010, respectively)		431		563
Accounts receivable
Customers (net of allowance for doubtful accounts of $85 and $81 at March 31, 2011 and December 31, 2010, respectively)		922		944
Accrued unbilled revenue		616		649
Regulatory balancing accounts		1,293		1,105
Other		814		794
Regulatory assets		580		599
Inventories
Gas stored underground and fuel oil		78		152
Materials and supplies		214		205
Income taxes receivable		35		47
Other		248		193

Total current assets		5,471		5,542

Property, Plant, and Equipment
Electric		34,068		33,508
Gas		11,482		11,382
Construction work in progress		1,369		1,384
Other		14		15

Total property, plant, and equipment		46,933		46,289
Accumulated depreciation		(15,061)		(14,840)

Net property, plant, and equipment		31,872		31,449

Other Noncurrent Assets
Regulatory assets ($645 and $735 related to energy recovery bonds at March 31, 2011 and December 31, 2010, respectively)		5,655		5,846
Nuclear decommissioning trusts		2,054		2,009
Income taxes receivable		566		565
Other		641		614

Total other noncurrent assets		8,916		9,034

TOTAL ASSETS		$ 46,259		$ 46,025

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)	2011		2010
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings		$ 1,288		$ 853
Long-term debt, classified as current		922		809
Energy recovery bonds, classified as current		409		404
Accounts payable
Trade creditors		974		1,129
Disputed claims and customer refunds		691		745
Regulatory balancing accounts		531		256
Other		520		379
Interest payable		784		862
Income taxes payable		128		77
Deferred income taxes		79		113
Other		1,446		1,558

Total current liabilities		7,772		7,185

Noncurrent Liabilities
Long-term debt		10,294		10,906
Energy recovery bonds		321		423
Regulatory liabilities		4,584		4,525
Pension and other postretirement benefits		2,288		2,234
Asset retirement obligations		1,583		1,586
Deferred income taxes		5,721		5,547
Other		2,030		2,085

Total noncurrent liabilities		26,821		27,306

Commitments and Contingencies (Note 10)
Equity
Shareholders’ Equity
Preferred stock		-		-
Common stock, no par value, authorized 800,000,000 shares, 397,453,525 shares outstanding at March 31, 2011 and 395,227,205 shares outstanding at December 31, 2010		6,983		6,878
Reinvested earnings		4,624		4,606
Accumulated other comprehensive loss		(193)		(202)

Total shareholders’ equity		11,414		11,282
Noncontrolling Interest – Preferred Stock of Subsidiary		252		252

Total equity		11,666		11,534

TOTAL LIABILITIES AND EQUITY		$ 46,259		$ 46,025

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)	2011		2010
Cash Flows from Operating Activities
Net income		$ 202		$ 261
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		550		506
Allowance for equity funds used during construction		(20)		(28)
Deferred income taxes and tax credits, net		99		137
Other		(15)		26
Effect of changes in operating assets and liabilities:
Accounts receivable		35		114
Inventories		65		59
Accounts payable		182		87
Income taxes receivable/payable		34		69
Other current assets and liabilities		(205)		(319)
Regulatory assets, liabilities, and balancing accounts, net		(10)		(376)
Other noncurrent assets and liabilities		171		(141)

Net cash provided by operating activities		1,088		395

Cash Flows from Investing Activities
Capital expenditures		(945)		(855)
Decrease in restricted cash		132		4
Proceeds from sales and maturities of nuclear decommissioning trust investments		726		337
Purchases of nuclear decommissioning trust investments		(735)		(343)
Other		(61)		9

Net cash used in investing activities		(883)		(848)

Cash Flows from Financing Activities
Net issuances of commercial paper, net of discount of $1 in 2011		415		418
Long-term debt matured		(500)		-
Energy recovery bonds matured		(97)		(93)
Common stock issued		82		10
Common stock dividends paid		(174)		(157)
Other		18		6

Net cash provided by (used in) financing activities		(256)		184

Net change in cash and cash equivalents		(51)		(269)
Cash and cash equivalents at January 1		291		527

Cash and cash equivalents at March 31		$ 240		$ 258

Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized		$ (215)		$ (193)
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid		$ 181		$ 169
Capital expenditures financed through accounts payable		174		215
Noncash common stock issuances		6		-

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)	2011		2010
Operating Revenues
Electric		$ 2,616		$ 2,510
Natural gas		980		965

Total operating revenues		3,596		3,475

Operating Expenses
Cost of electricity		888		920
Cost of natural gas		508		495
Operating and maintenance		1,226		990
Depreciation, amortization, and decommissioning		490		451

Total operating expenses		3,112		2,856

Operating Income		484		619
Interest income		2		2
Interest expense		(171)		(156)
Other income (expense), net		17		(6)

Income Before Income Taxes		332		459
Income tax provision		131		195

Net Income		201		264
Preferred stock dividend requirement		3		3

Income Available for Common Stock		$ 198		$ 261

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)	2011		2010
ASSETS
Current Assets
Cash and cash equivalents		$ 52		$ 51
Restricted cash ($35 and $38 related to energy recovery bonds at March 31, 2011 and December 31, 2010, respectively)		431		563
Accounts receivable
Customers (net of allowance for doubtful accounts of $85 and $81 at March 31, 2011 and December 31, 2010, respectively)		922		944
Accrued unbilled revenue		616		649
Regulatory balancing accounts		1,293		1,105
Other		842		856
Regulatory assets		580		599
Inventories
Gas stored underground and fuel oil		78		152
Materials and supplies		214		205
Income taxes receivable		43		48
Other		243		190

Total current assets		5,314		5,362

Property, Plant, and Equipment
Electric		34,068		33,508
Gas		11,482		11,382
Construction work in progress		1,369		1,384

Total property, plant, and equipment		46,919		46,274
Accumulated depreciation		(15,047)		(14,826)

Net property, plant, and equipment		31,872		31,448

Other Noncurrent Assets
Regulatory assets ($645 and $735 related to energy recovery bonds at March 31, 2011 and December 31, 2010, respectively)		5,655		5,846
Nuclear decommissioning trusts		2,054		2,009
Income taxes receivable		614		614
Other		364		400

Total other noncurrent assets		8,687		8,869

TOTAL ASSETS		$ 45,873		$ 45,679

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)	2011		2010
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings		$ 1,288		$ 853
Long-term debt, classified as current		922		809
Energy recovery bonds, classified as current		409		404
Accounts payable
Trade creditors		974		1,129
Disputed claims and customer refunds		691		745
Regulatory balancing accounts		531		256
Other		539		390
Interest payable		774		857
Income taxes payable		137		116
Deferred income taxes		87		118
Other		1,249		1,349

Total current liabilities		7,601		7,026

Noncurrent Liabilities
Long-term debt		9,945		10,557
Energy recovery bonds		321		423
Regulatory liabilities		4,584		4,525
Pension and other postretirement benefits		2,227		2,174
Asset retirement obligations		1,583		1,586
Deferred income taxes		5,833		5,659
Other		1,965		2,008

Total noncurrent liabilities		26,458		26,932

Commitments and Contingencies (Note 10)
Shareholders’ Equity
Preferred stock		258		258
Common stock, $5 par value, authorized 800,000,000 shares, 264,374,809 shares outstanding at March 31, 2011 and December 31, 2010		1,322		1,322
Additional paid-in capital		3,306		3,241
Reinvested earnings		7,114		7,095
Accumulated other comprehensive loss		(186)		(195)

Total shareholders’ equity		11,814		11,721

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$ 45,873		$ 45,679

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)	2011		2010
Cash Flows from Operating Activities
Net income		$ 201		$ 264
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		534		491
Allowance for equity funds used during construction		(20)		(28)
Deferred income taxes and tax credits, net		99		138
Other		(15)		26
Effect of changes in operating assets and liabilities:
Accounts receivable		69		114
Inventories		65		59
Accounts payable		190		94
Income taxes receivable/payable		34		77
Other current assets and liabilities		(196)		(325)
Regulatory assets, liabilities, and balancing accounts, net		(10)		(376)
Other noncurrent assets and liabilities		144		(126)

Net cash provided by operating activities		1,095		408

Cash Flows from Investing Activities
Capital expenditures		(945)		(855)
Decrease in restricted cash		132		4
Proceeds from sales and maturities of nuclear decommissioning trust investments		726		337
Purchases of nuclear decommissioning trust investments		(735)		(343)
Other		7		5

Net cash used in investing activities		(815)		(852)

Cash Flows from Financing Activities
Net issuances of commercial paper, net of discount of $1 in 2011		415		418
Long-term debt matured		(500)		-
Energy recovery bonds matured		(97)		(93)
Preferred stock dividends paid		(4)		(4)
Common stock dividends paid		(179)		(179)
Equity contribution		65		20
Other		21		8

Net cash provided by (used in) financing activities		(279)		170

Net change in cash and cash equivalents		1		(274)
Cash and cash equivalents at January 1		51		334

Cash and cash equivalents at March 31		$52		$60

Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized		$ (215)		$ (193)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable		$ 174		$ 215

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

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

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

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

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

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

Pension and Other Postretirement Benefits

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

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Statements of Income for the three months ended March 31, 2011 and 2010 were as follows:


	Pension Benefits				Other Benefits
	Three Months Ended March 31,				Three Months Ended March 31,
(in millions)	2011		2010		2011		2010
Service cost for benefits earned		$ 82		$ 69		$ 11		$ 10
Interest cost		164		161		23		23
Expected return on plan assets		(167)		(156)		(20)		(18)
Amortization of transition obligation		-		-		6		6
Amortization of prior service cost		9		13		6		6
Amortization of unrecognized loss		12		11		1		1

Net periodic benefit cost		100		98		27		28
Less: transfer to regulatory account ⁽¹⁾		(36)		(58)		-		-

Total		$ 64		$ 40		$ 27		$ 28

⁽¹⁾ The Utility recorded $36 million and $58 million for the three month periods ended March 31, 2011 and 2010, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates.

There was no material difference between PG&E Corporation’s and the Utility’s consolidated net periodic benefit costs for the three months ended March 31, 2011 and 2010.

Variable Interest Entities

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

The Utility was the primary beneficiary of PG&E Energy Recovery Funding LLC (“PERF”) at March 31, 2011, and consolidated PERF. The Utility is exposed to PERF’s losses and returns through the Utility’s 100% equity investment in PERF and the Utility was involved in the design of PERF, which was an activity that was significant to PERF’s economic performance. The assets of PERF were $799 million at March 31, 2011 and primarily consisted of assets related to energy recovery bonds (“ERBs”), which are included in other noncurrent assets – regulatory assets in the Condensed Consolidated Balance Sheets. The liabilities of PERF were $730 million at March 31, 2011 and consisted of energy recovery bonds, which are included in current and noncurrent liabilities in the Condensed Consolidated Balance Sheets. (See Note 4 below.) The assets of PERF are only available to settle the liabilities of PERF and PERF’s creditors have no recourse to the Utility.

As of March 31, 2011, PG&E Corporation’s affiliates had entered into four tax equity agreements with two privately held companies to fund residential and commercial retail solar energy installations. Under these agreements, PG&E Corporation agreed to provide lease payments and investment contributions of up to $300 million to these companies in exchange for the right to receive the benefits from local rebates, federal investment tax credits or grants, and a share of the customer payments made to these companies. As of March 31, 2011, PG&E Corporation had made total payments of $216 million under these tax equity agreements. These amounts are recorded in other noncurrent assets – other in PG&E Corporation’s Condensed Consolidated Balance Sheets. PG&E Corporation holds a variable interest in these companies as a result of these agreements. PG&E Corporation was not the primary beneficiary of, and did not consolidate any of these companies at March 31, 2011. In making this determination, PG&E Corporation evaluated which party has control over these companies’ significant economic activities such as designing the companies, vendor selection, construction, customer selection, and re-marketing activities at the end of customer leases, and determined that these activities are under the control of these companies.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

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

The Utility uses regulatory balancing accounts to accumulate differences between actual billed and unbilled revenues and the Utility’s authorized revenue requirements for the period. The Utility also uses regulatory balancing accounts to accumulate differences between incurred costs and actual billed and unbilled revenues, as well as differences between incurred costs and authorized revenue meant to recover those costs. Under-collections that are probable of recovery through regulated rates are recorded as regulatory balancing account assets. Over-collections that are probable of being refunded to customers are recorded as regulatory balancing account liabilities.

Regulatory Assets

Current Regulatory Assets

At March 31, 2011 and December 31, 2010, the Utility had current regulatory assets of $580 million and $599 million, respectively, consisting primarily of price risk management regulatory assets and the Utility’s retained generation regulatory assets. The current portion of price risk management regulatory assets represents the deferral of unrealized losses related to price risk management derivative instruments with terms of one year or less. (See Note 7 below.) The current portion of the Utility’s retained generation regulatory assets represents one year of amortization of these regulatory assets over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized.

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:


	Balance at
(in millions)	March 31, 2011		December 31, 2010
Pension benefits		$ 1,775		$ 1,759
Deferred income taxes		1,285		1,250
Utility retained generation		649		666
Energy recovery bonds		645		735
Environmental compliance costs		412		450
Price risk management		331		424
Unamortized loss, net of gain, on reacquired debt		175		181
Other		383		381

Total long-term regulatory assets		$ 5,655		$ 5,846

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

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

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

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

The regulatory assets for environmental compliance costs represent estimated environmental compliance costs that the Utility expects to recover in future rates as actual environmental compliance costs are incurred. The Utility expects to recover these costs over the next 32 years. (See Note 10 below.)

Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative instruments with terms in excess of one year. (See Note 7 below.)

The regulatory assets for unamortized loss, net of gain, on reacquired debt represent costs related to debt reacquired or redeemed prior to maturity with associated discount and debt issuance costs. These costs are expected to be recovered over the next 16 years, which is the remaining amortization period of the reacquired debt. The Utility expects to fully recover these costs by 2026.

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

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

Regulatory Liabilities

Current Regulatory Liabilities

At March 31, 2011 and December 31, 2010, the Utility had current regulatory liabilities of $79 million and $81 million, respectively, primarily consisting of amounts that the Utility expects to refund to customers for over-collected electric transmission rates and amounts that the Utility expects to refund to electric transmission customers for their portion of settlements the Utility entered into with various electricity suppliers to resolve certain remaining Chapter 11 disputed claims. Current regulatory liabilities are included in current liabilities – other in the Condensed Consolidated Balance Sheets.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:


	Balance at
(in millions)	March 31, 2011		December 31, 2010
Cost of removal obligation		$ 3,296		$ 3,229
Recoveries in excess of ARO		643		600
Public purpose programs		503		573
Other		142		123

Total long-term regulatory liabilities		$ 4,584		$ 4,525

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

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

The regulatory liability for public purpose programs represents amounts received from customers designated for public purpose program costs that are expected to be incurred in the future. The public purpose programs regulatory liabilities primarily consist of revenues collected from customers to pay for costs that the Utility expects to incur in the future under energy efficiency programs designed to encourage the manufacture, design, distribution, and customer use of energy efficient appliances and other energy-using products; under the California Solar Initiative program to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties; and under the Self-Generation Incentive program to promote distributed generation technologies installed on the customer’s side of the Utility meter that provide electricity and gas for all or a portion of that customer’s load.

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

Regulatory Balancing Accounts

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

Current Regulatory Balancing Accounts, net


	Receivable (Payable)
	Balance at
(in millions)	March 31, 2011		December 31, 2010
Utility generation		$ 439		$ 303
Distribution revenue adjustment mechanism		241		145
Public purpose programs		188		164
Hazardous substance		57		38
Gas fixed cost		(89)		56
Energy procurement		(91)		(25)
Energy recovery bonds		(110)		(34)
Other		127		202

Total regulatory balancing accounts, net		$ 762		$ 849

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

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

The hazardous substance balancing accounts are used to track recoverable hazardous substance clean up costs through the CPUC-approved ratemaking mechanism that authorizes the Utility to recover 90% of hazardous waste remediation costs. The current balance represents eligible remediation costs incurred by the Utility during 2010 that will be recovered through an annual true-up filing with the CPUC in January 2012. (See Note 10 below.)

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

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

The ERB balancing account records the benefits and costs associated with ERBs that are provided to, or received from, customers. This account ensures that customers receive the benefits of the net amount of energy supplier refunds, claim offsets, and other credits received by the Utility after the second series of ERBs was issued.

At March 31, 2011 and December 31, 2010, “other” primarily consisted of balancing accounts that track recovery of the authorized revenue requirements and costs related to the SmartMeter^TM advanced metering project.

NOTE 4: DEBT

PG&E Corporation

Credit Facility

At March 31, 2011, PG&E Corporation had no cash borrowings outstanding under its $187 million revolving credit facility.

Utility

Credit Facilities

At March 31, 2011, the Utility had no cash borrowings outstanding under its $1.9 billion and $750 million revolving credit facilities.

At March 31, 2011, the Utility had $315 million of letters of credit outstanding under its $1.9 billion revolving credit facility.

The Utility’s revolving credit facilities also provide liquidity support for commercial paper offerings. At March 31, 2011, the Utility had $1.0 billion of commercial paper outstanding at an average yield of 0.39%.

Other Short-term Borrowings

At March 31, 2011, the interest rate on the Utility’s $250 million principal amount of Floating Rate Senior Notes, due October 11, 2011, was 0.88%. The interest rate for the Floating Rate Senior Notes is equal to the three-month LIBOR plus 0.58% and resets quarterly. On April 11, 2011, the interest rate was reset to 0.87%.

Energy Recovery Bonds

In 2005, PERF issued two separate series of ERBs in the aggregate amount of $2.7 billion. The proceeds of the ERBs were used by PERF to purchase from the Utility the right, known as “recovery property,” to be paid a specified amount from a dedicated rate component to be collected from the Utility’s electricity customers. The total amount of ERB principal outstanding was $730 million at March 31, 2011.

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

NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the three months ended March 31, 2011 were as follows:


	PG&E Corporation		Utility
(in millions)	Total Equity		Total Shareholders’ Equity
Balance at December 31, 2010		$ 11,534		$ 11,721
Net income		202		201
Common stock issued		88		-
Share-based compensation expense		15		-
Common stock dividends declared		(181)		(179)
Preferred stock dividend requirement		-		(3)
Preferred stock dividend requirement of subsidiary		(3)		-
Other comprehensive income		9		9
Equity contribution		-		65
Other		2		-

Balance at March 31, 2011		$ 11,666		$ 11,814

For the three months ended March 31, 2011, PG&E Corporation issued 2,032,223 shares of common stock upon the exercise of employee stock options and under its 401(k) plan and Dividend Reinvestment and Stock Purchase Plan.

For the three months ended March 31, 2011, PG&E Corporation contributed equity of $65 million to the Utility in order to maintain the 52% common equity ratio authorized by the CPUC and to ensure that the Utility has adequate capital to fund its capital expenditures.

Comprehensive Income

Comprehensive income consists of net income and other comprehensive income, which includes certain changes in equity that are excluded from net income. Specifically, adjustments for employee benefit plans, net of tax, are recorded in other comprehensive income.

PG&E Corporation

Utility

Three Months Ended
March 31,

(in millions)

2011

2010

2011

2010

Net income

$ 202

$ 261

$ 201

$ 264

Employee benefit plan adjustment, net of tax ⁽¹⁾

(80)

Comprehensive Income

$ 211

$ 181

$ 210

$ 184

⁽¹⁾These balances are net of income tax expense of $6 million and net of income tax benefit of $55 million for the three months ended March 31, 2011 and 2010, respectively.

NOTE 6: EARNINGS PER SHARE

For the three months ended March 31, 2011, PG&E Corporation’s basic earnings per common share (“EPS”) was calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. For the three months ended March 31, 2010, PG&E Corporation calculated EPS using the “two-class” method because PG&E Corporation’s convertible subordinated notes that were then outstanding were considered to be participating securities under applicable accounting standards. Under the two-class method, the sum of distributed earnings to common shareholders and undistributed earnings allocated to common shareholders is divided by the weighted average number of common shares outstanding during the period. In applying the two-class method, undistributed earnings were allocated to both common shares and participating securities. Since all of PG&E Corporation’s convertible subordinated notes have been converted into common stock there were no participating securities outstanding as of March 31, 2011.

The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating basic EPS:


	Three Months Ended March 31,
(in millions, except per share amounts)	2011		2010
*Basic*
Income Available for Common Shareholders		$ 199		$ 258
Less: distributed earnings to common shareholders		181		169

Undistributed earnings		$ 18		$ 89

Allocation of undistributed earnings to common shareholders
Distributed earnings to common shareholders		$ 181		$ 169
Undistributed earnings allocated to common shareholders		18		85

Total common shareholders earnings		$ 199		$ 254

Weighted average common shares outstanding, basic		396		371
Convertible subordinated notes		-		16

Weighted average common shares outstanding and participating securities		396		387

Net earnings per common share, basic
Distributed earnings, basic ⁽¹⁾		$ 0.46		$ 0.46
Undistributed earnings, basic		0.04		0.23

Total		$ 0.50		$ 0.69


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

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

The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average shares of common stock outstanding for calculating diluted EPS:


	Three months ended
	March 31,
(in millions, except per share amounts)	2011		2010
*Diluted*
Income available for common shareholders		$ 199		$ 258
Add earnings impact of assumed conversion of participating securities:
Interest expense on convertible subordinated notes, net of tax		-		4

Income available for common shareholders and assumed conversion		$ 199		$ 262


Weighted average common shares outstanding, basic		396		371
Add incremental shares from assumed conversions:
Convertible subordinated notes		-		16
Employee share-based compensation		1		2

Weighted average common shares outstanding, diluted		397		389

Total earnings per common share, diluted		$ 0.50		$ 0.67

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

NOTE 7: DERIVATIVES AND HEDGING ACTIVITIES

Use of Derivative Instruments

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

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

•

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

•

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

•

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

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

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

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

Electricity Procurement

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

•

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

•

the execution of new electricity purchase contracts;

•

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

•

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

•

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

•

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

•

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

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

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

Electric Transmission Congestion Revenue Rights

The California Independent System Operator (“CAISO”) controlled electricity transmission grid used by the Utility to transmit power is subject to transmission constraints. As a result, the Utility is subject to financial risk associated with the cost of transmission congestion. The congestion revenue rights (“CRRs”) allow market participants, including load-serving entities, to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. The CAISO releases CRRs through an annual and monthly process, each of which includes an allocation phase (in which load-serving entities are allocated CRRs at no cost based on the customer demand or “load” they serve) and an auction phase (in which CRRs are priced at market and available to all market participants). The Utility participates in the allocation and auction phases of the annual and monthly CRR processes. The CRRs held by the Utility are considered derivative instruments.

Natural Gas Procurement (Electric Fuels Portfolio)

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

Natural Gas Procurement (Core Gas Supply Portfolio)

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

Volume of Derivative Activity

At March 31, 2011, the volumes of PG&E Corporation’s and the Utility’s outstanding derivative contracts were as follows:


		Contract Volume ⁽¹⁾
Underlying Product	Instruments	Less Than 1 Year		Greater Than 1 Year but Less Than 3 Years		Greater Than 3 Years but Less Than 5 Years		Greater Than 5 Years ⁽²⁾
Natural Gas ⁽³⁾ (MMBtus ⁽⁴⁾)	Forwards and Swaps		483,012,276		299,055,015		13,642,500		-
	Options		215,050,000		203,350,000		21,000,000		-
Electricity (Megawatt-hours)	Forwards and Swaps		4,738,243		6,526,712		3,297,199		4,674,168
	Options		415,450		24,540		264,348		371,604
	Congestion Revenue Rights		68,367,041		72,547,614		72,642,249		90,055,284

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

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

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

⁽⁴⁾Million British Thermal Units.

Presentation of Derivative Instruments in the Financial Statements

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

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


(in millions)	Gross Derivative Balance ⁽¹⁾		Netting ⁽²⁾		Cash Collateral ⁽²⁾		Total Derivative Balances
Commodity Risk (PG&E Corporation and the Utility)
Current assets –other		59		(47)		128		140
Other noncurrent assets – other		139		(100)		42		81
Current liabilities – other		(371)		47		135		(189)
Noncurrent liabilities – other		(431)		100		48		(283)

Total commodity risk		(604)		-		353		(251)

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

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

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


(in millions)	Gross Derivative Balance		Netting ⁽¹⁾		Cash Collateral ⁽¹⁾		Total Derivative Balances
Commodity Risk (PG&E Corporation and the Utility)
Current assets –other		$ 56		$ (45)		$ 79		$ 90
Other noncurrent assets – other		77		(62)		96		111
Current liabilities – other		(388)		45		119		(224)
Noncurrent liabilities – other		(486)		62		130		(294)

Total commodity risk		$ (741)		$ -		$ 424		$ (317)

⁽¹⁾Positions and cash collateral, by counterparty, are netted where the intent and legal right to offset exist in accordance with master netting agreements.

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


	Commodity Risk (PG&E Corporation and Utility)

	Three months ended March 31,
(in millions)	2011		2010
Unrealized gain/(loss) - Regulatory assets and liabilities ⁽¹⁾		$ 137		$ (289)
Realized loss - Cost of electricity ⁽²⁾		(136)		(106)
Realized loss - Cost of natural gas ⁽²⁾		(55)		(39)

Total commodity risk instruments		$ (54)		$ (434)

		Other Risk Instruments (PG&E Corporation Only)

Other expense (income), net		$ -		$ 1

Total other risk instruments		$ -		$ 1


⁽¹⁾ Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings.
⁽²⁾ These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.

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

The majority of the Utility’s commodity commodity-related derivative instruments contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. As of March 31, 2011, the Utility’s credit rating was investment grade. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to immediately post additional cash to fully collateralize its net liability derivative positions.

At March 31, 2011, the additional cash collateral that the Utility would be required to post if its credit risk-related contingency features were triggered was as follows:


(in millions)
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized			(487)
Related derivatives in an asset position			12
Collateral posting in the normal course of business related to these derivatives			16

Net position of derivative contracts/additional collateral posting requirements ⁽¹⁾			(459)


⁽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 (money market investments and assets held in rabbi trusts are held by PG&E Corporation and not the Utility):


	Fair Value Measurements
	At March 31, 2011								At December 31, 2010
(in millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets:
Money market investments		$ 187		$ -		$ -		$ 187		$ 138		$ -		$ -		$ 138

Nuclear decommissioning trusts
U.S. equity securities ⁽¹⁾		861		8		-		869		1,029		7		-		1,036
Non-U.S. equity securities		360		-		-		360		349		-		-		349
U.S. government and agency securities		647		159		-		806		584		40		-		624
Municipal securities		-		109		-		109		-		119		-		119
Other fixed income securities		-		113		-		113		-		66		-		66

Total nuclear decommissioning trusts ⁽²⁾		1,868		389		-		2,257		1,962		232		-		2,194

Price risk management instruments (Note 7)
Electric ⁽³⁾		119		11		-		130		130		-		-		130
Gas ⁽⁴⁾		8		-		-		8		3		-		-		3

Total price risk management instruments		127		11		-		138		133		-		-		133

Rabbi trusts
Fixed income securities		-		24		-		24		-		24		-		24
Life insurance contracts		-		65		-		65		-		65		-		65

Total rabbi trusts		-		89		-		89		-		89		-		89

Long-term disability trust
U.S. equity securities ⁽¹⁾		4		20		-		24		11		24		-		35
Non-U.S. equity securities		-		8		-		8		-		-		-		-
Corporate debt securities ⁽¹⁾		-		145		-		145		-		150		-		150

Total long-term disability trust		4		173		-		177		11		174		-		185

Total assets		$ 2,186		$ 662		$ -		$ 2,848		$ 2,244		$ 495		$ -		$ 2,739

Liabilities:
Price risk management instruments (Note 7)
Electric ⁽⁵⁾		$ -		$ -		$ 382		$ 382		$ -		$ 5		$ 403		$ 408
Gas ⁽⁶⁾		-		1		6		7		-		1		41		42

Total liabilities		$ -		$ 1		$ 388		$ 389		$ -		$ 6		$ 444		$ 450

⁽¹⁾

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

⁽²⁾

Excludes $203 million and $185 million at March 31, 2011 and December 31, 2010, respectively, primarily related to deferred taxes on appreciation of investment value.

⁽³⁾

Balances include the impact of netting adjustments of $321 million and $359 million to Level 1 at March 31, 2011 and December 31, 2010, respectively and $70 million to Level 2 at March 31, 2011. Includes natural gas for electric portfolio.

⁽⁴⁾

Balances include the impact of netting adjustments of $40 million and $44 million to Level 1 at March 31, 2011 and December 31, 2010, respectively. Includes natural gas for core customers.

⁽⁵⁾

Balances include the impact of netting adjustments of $66 million to Level 2 at December 31, 2010 and $(73) million and $(48) million to Level 3 at March 31, 2011 and December 31, 2010, respectively. Includes natural gas for electric portfolio.

⁽⁶⁾

Balances include the impact of netting adjustments of $(5) million and $3 million to Level 3 at March 31, 2011 and December 31, 2010, respectively. Includes natural gas for core customers.

Money Market Investments

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

Trust Assets

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

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

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

Price Risk Management Instruments

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

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

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

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

Transfers between Levels

PG&E Corporation and the Utility recognize any transfers between levels in the fair value hierarchy as of the end of the reporting period. There were no significant transfers between levels for the three months ended March 31, 2011.

Level 3 Reconciliation

The following table presents reconciliations for assets and liabilities measured and recorded at fair value on a recurring basis for PG&E Corporation and the Utility (money market investments and dividend participation rights are held by PG&E Corporation and not the Utility), using significant unobservable inputs (Level 3):


	For the three months ended March 31,
	2011		2010
(in millions)	Price Risk Management Instruments		Money Market		Dividend Participation Rights		Price Risk Management Instruments		Other Liabilities		Total

Asset (liability) balance as of December 31		$ (444)		$ 4		$ (12)		$ (217)		$ (3)		$ (228)

Realized and unrealized gains (losses):
Included in earnings		-		-		-		-		-		-
Included in regulatory assets and liabilities or balancing accounts		56		-		-		(119)		2		(117)

Purchases, issuances, sales and settlements		-		(4)		5		-		-		1
Transfers into Level 3		-		-		-		-		-		-
Transfers out of Level 3		-		-		-		-		-		-

Asset (liability) balance as of March 31		$ (388)		$ -		$ (7)		$ (336)		$ (1)		$ (344)

Financial Instruments

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

•

The fair values of cash, restricted cash and deposits, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at March 31, 2011 and December 31, 2010.

•

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

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


	At March 31, 2011				At December 31, 2010
(in millions)	Carrying Amount		Fair Value⁽¹⁾		Carrying Amount		Fair Value⁽¹⁾
Debt (Note 4):
PG&E Corporation		$ 349		$ 382		$ 349		$ 383
Utility		9,945		10,524		10,444		11,314
Energy recovery bonds (Note 4)		730		757		827		862
⁽¹⁾ Fair values are determined using readily available quoted market prices.

Nuclear Decommissioning Trust Investments

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

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


(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Estimated ⁽¹⁾ Fair Value
As of March 31, 2011
Equity securities
U.S.		$ 308		$ 562		$ (1)		$ 869
Non-U.S.		182		179		(1)		360
Debt securities
U.S. government and agency securities		759		50		(3)		806
Municipal securities		108		1		-		109
Other fixed income securities		113		1		(1)		113

Total		$ 1,470		$ 793		$ (6)		$ 2,257

As of December 31, 2010
Equity securities
U.S.		$ 509		$ 529		$ (2)		$ 1,036
Non-U.S.		180		170		(1)		349
Debt securities
U.S. government and agency securities		571		55		(2)		624
Municipal securities		119		1		(1)		119
Other fixed income securities		65		1		-		66

Total		$ 1,444		$ 756		$ (6)		$ 2,194


⁽¹⁾		Excludes $203 million and $185 million at March 31, 2011 and December 31, 2010, respectively, primarily related to deferred taxes on appreciation of investment value.

The debt securities mature on the following schedule:


(in millions)	As of March 31, 2011
Less than 1 year		$ 72
1–5 years		325
5–10 years		286
More than 10 years		345

Total maturities of debt securities		$ 1,028

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


	Three Months Ended
(in millions)	March 31, 2011		March 31, 2010
Proceeds from sales and maturities of nuclear decommissioning trust investments		$ 726		$ 337
Gross realized gains on sales of securities held as available-for-sale		20		15
Gross realized losses on sales of securities held as available-for-sale		(4)		(5)

NOTE 9: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

Various electricity suppliers filed claims in the Utility’s Chapter 11 Settlement Agreement seeking payment for energy supplied to the Utility’s customers through the wholesale electricity markets operated by the CAISO and the California Power Exchange (“PX”) between May 2000 and June 2001. These claims, which the Utility disputes, are being addressed in various FERC and judicial proceedings in which the State of California, the Utility, and other electricity purchasers are seeking refunds from electricity suppliers, including municipal and governmental entities, for overcharges incurred in the CAISO and the PX wholesale electricity markets between May 2000 and June 2001. At March 31, 2011 and December 31, 2010, the Utility held $384 million and $512 million in escrow, respectively, including interest earned, for payment of the remaining net disputed claims. These amounts are included within restricted cash on the Condensed Consolidated Balance Sheets.

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

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


(in millions)
Balance at December 31, 2010			$ 934
Interest accrued			7
Less: supplier settlements			(86)

Balance at March 31, 2011			$ 855

At March 31, 2011, the Utility’s net disputed claims liability was $855 million, consisting of $691 million of remaining disputed claims (classified on the Condensed Consolidated Balance Sheets within accounts payable – disputed claims and customer refunds) and interest accrued at the FERC-ordered rate of $658 million (classified on the Condensed Consolidated Balance Sheets within interest payable) partially offset by accounts receivable from the CAISO and the PX of $494 million (classified on the Condensed Consolidated Balance Sheets within accounts receivable – other).

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

PG&E Corporation and the Utility are unable to predict when the FERC or judicial proceedings that are still pending will be resolved, and the amount of any potential refunds that the Utility may receive or the amount of disputed claims, including interest that the Utility will be required to pay.

NOTE 10: COMMITMENTS AND CONTINGENCIES

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

Commitments

Utility

Third-Party Power Purchase Agreements

As part of the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either gas or electricity at the date of purchase.

At March 31, 2011, the undiscounted future expected power purchase agreement payments were as follows:


(in millions)
2011			$ 2,076
2012			2,553
2013			3,004
2014			3,276
2015			3,478
Thereafter			54,390

Total			$ 68,777

Costs incurred by the Utility under power purchase agreements amounted to $587 million and $201 million for the three months ended March 31, 2011 and 2010, respectively.

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


(in millions)
2011	$ 43
2012	50
2013	50
2014	42
2015	38
Thereafter	124

Total fixed capacity payments	347
Less: amount representing interest	(68	)

Present value of fixed capacity payments	$279

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

At March 31, 2011 and December 31, 2010, current liabilities – other included $34 million and $34 million, respectively, and noncurrent liabilities – other included $245 million and $248 million, respectively. The corresponding assets at March 31, 2011 and December 31, 2010 of $279 million and $282 million including accumulated amortization of $129 million and $126 million, respectively are included in property, plant, and equipment on PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets.

Natural Gas Supply, Transportation, and Storage Commitments

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities. The contract lengths and quantities of the Utility’s portfolio of natural gas procurement contracts can fluctuate based on market conditions. The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins. In addition, the Utility has contracted for gas storage services in northern California in order to better meet core customers’ winter peak loads. At March 31, 2011, the Utility’s undiscounted obligations for natural gas purchases, natural gas transportation services, and natural gas storage were as follows:


(in millions)
2011			$ 659
2012			514
2013			258
2014			209
2015			195
Thereafter			1,141

Total ⁽¹⁾			$ 2,976


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

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage amounted to $433 million and $553 million for the three months ended March 31, 2011 and March 31, 2010, respectively.

Nuclear Fuel Agreements

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

At March 31, 2011, the undiscounted obligations under nuclear fuel agreements were as follows:


(in millions)
2011			$ 65
2012			83
2013			125
2014			143
2015			200
Thereafter			1,065

Total			$1,681

Payments for nuclear fuel amounted to $29 million and $53 million for the three months ended March 31, 2011 and March 31, 2010, respectively.

Contingencies

PG&E Corporation

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

Utility

Energy Efficiency Programs and Incentive Ratemaking

On November 15, 2010, a proposed decision was issued that if, adopted by the CPUC, would modify the incentive mechanism that would apply to the 2010 through 2012 program cycle. Among other changes, the proposed modification would limit the total amount of the incentive award or penalty that could be awarded to, or imposed on, all the investor-owned utilities to $189 million. If the proposed decision is adopted, the Utility’s opportunity to earn incentive revenues would be limited compared to the mechanism that was in place for the 2006-2008 program cycle.

Spent Nuclear Fuel Storage Proceedings

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

Because the DOE failed to develop a permanent storage site, the Utility obtained a permit from the Nuclear Regulatory Commission (“NRC”) to build an on-site dry cask storage facility to store spent fuel at Diablo Canyon through at least 2024. The construction of the dry cask storage facility is complete. During 2009 and 2010, the Utility moved all the spent nuclear fuel that was scheduled to be moved into dry cask storage. An appeal of the NRC’s issuance of the permit, which claimed that the NRC failed to adequately consider environmental impacts of a potential terrorist attack at Diablo Canyon, was denied by the U.S. Court of Appeals for the Ninth Circuit on February 15, 2011.

As a result of the DOE’s failure to build a repository for nuclear waste, the Utility and other nuclear power plant owners sued the DOE to recover costs that they incurred to build on-site spent nuclear fuel storage facilities. The Utility sought to recover $92 million of costs that it incurred through 2004. After several years of litigation, on March 30, 2010, the U.S. Court of Federal Claims awarded the Utility $89 million. The DOE filed an appeal of this decision on May 28, 2010. The appeal was argued in the

Federal Circuit Court of Appeals on March 10, 2011. Additionally, on August 3, 2010, the Utility filed two complaints against the DOE in the U.S. Court of Federal Claims seeking to recover all costs incurred since 2005 to build on-site storage facilities. The Utility estimates that it has incurred costs of at least $205 million since 2005. Amounts recovered from the DOE will be credited to customers.

Nuclear Insurance

The Utility has several types of nuclear insurance for the two nuclear operating units at Diablo Canyon and for its retired nuclear generation facility at Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited (“NEIL”). NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.2 billion per incident for Diablo Canyon. In addition, NEIL provides $131 million of property damage insurance for Humboldt Bay Unit 3. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay an additional premium of up to $42 million per one-year policy term.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. If one or more acts of terrorism cause damages covered under any of the nuclear insurance policies issued by NEIL to any NEIL member, the maximum recovery under all those nuclear insurance policies may not exceed NEIL’s policy limit of $3.2 billion within a 12-month period plus any additional amounts recovered by NEIL for these losses from reinsurance. Certain acts of terrorism may be “certified” by the Secretary of the Treasury. For damages 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 caused by these certified acts of terrorism. The $3.2 billion amount would not be shared as is described above for damages caused by acts of terrorism that have not been certified.

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

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

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.

Legal Matters

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

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

The accrued liability associated with claims and litigation, regulatory proceedings, and other legal matters (other than third-party liability claims related to the San Bruno accident as discussed below) totaled $87 million at March 31, 2011 and $55 million at December 31, 2010 and is included in PG&E

Corporation’s and the Utility’s current liabilities – other in the Condensed Consolidated Balance Sheets. Except as discussed below, PG&E Corporation and the Utility do not believe that losses associated with legal matters would have a material adverse impact on their financial condition, results of operations, or cash flows after consideration of the accrued liability at March 31, 2011.

Explosion and Fires in San Bruno, California

On September 9, 2010, an underground 30-inch natural gas transmission pipeline (line 132) owned and operated by the Utility, ruptured in a residential area located in the City of San Bruno, California (“San Bruno accident”). The ensuing explosion and fire resulted in the deaths of eight people, injuries to numerous individuals, and extensive property damage. The NTSB has issued several public statements regarding its investigation of the San Bruno accident but has not yet determined the cause of the pipeline rupture. During the quarter ended March 31, 2011, the CPUC initiated an investigation pertaining to safety recordkeeping for the Utility’s gas transmission pipeline that ruptured in San Bruno, as well as for its entire gas transmission system, which is discussed below.

In addition to these investigations, as of March 31, 2011, 74 tort lawsuits on behalf of approximately 224 plaintiffs, including two class action lawsuits, have been filed against PG&E Corporation and the Utility. Five of the lawsuits on behalf of 11 plaintiffs were filed in the San Francisco County Superior Court; the rest were filed in San Mateo County Superior Court. These tort lawsuits seek compensation for personal injury and property damage and seek other relief. The class action lawsuits allege causes of action for strict liability, negligence, public nuisance, private nuisance, and declaratory relief. Several other residents of San Bruno also have submitted damage claims to the Utility. These lawsuits have been coordinated and assigned to one judge in the San Mateo County Superior Court.

The Utility recorded a provision of $220 million in 2010 for estimated third-party claims related to the San Bruno accident, including personal injury and property damage claims, damage to infrastructure, and other damage claims. The provision also included estimated liabilities to reimburse the City of San Bruno for costs it incurred related to the fires caused by the pipeline rupture. As of March 31, 2011 and December 31, 2010, $198 million and $214 million, respectively, was accrued as a liability in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. The change in the liability from December 31, 2010 was due to payments made to third parties.

The Utility currently estimates that it may incur as much as $400 million for third-party claims. As more information becomes known, including information resulting from the NTSB and CPUC investigations, management’s estimates and assumptions regarding the amount of third-party liability incurred in connection with the San Bruno accident may change. It is possible that a change in estimate could have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.

The Utility maintains liability insurance for damages in the approximate amount of $992 million in excess of a $10 million deductible. Although PG&E Corporation and the Utility currently consider it likely that a significant portion of the costs the Utility incurs for third-party claims relating to the San Bruno accident will ultimately be covered through this insurance, no amount for insurance recoveries has been recorded as of March 31, 2011. PG&E Corporation and the Utility are unable to predict the amount and timing of insurance recoveries.

CPUC Investigations

On February 24, 2011, the CPUC issued an order instituting a formal investigation (“OII”) pertaining to safety recordkeeping for the Utility’s gas transmission pipeline that ruptured in San Bruno on September 9, 2010, as well as for its entire gas transmission system. The CPUC stated that in deciding to issue the OII, it had relied on the NTSB’s public preliminary reports issued in connection with its investigation of the San Bruno accident, the NTSB’s January 3, 2011 urgent safety recommendations regarding the importance of accurate pipeline records in calculating maximum safe operating pressures, and other NTSB statements. After the NTSB has completed its investigation and issued a final report, the CPUC also will consider other possible violations of law, besides recordkeeping, associated with the Utility’s transmission lines and with Line 132 in particular.

If the CPUC determines that the Utility violated safety law standards with respect to its gas system recordkeeping, the CPUC will schedule a later phase or phases to determine whether penalties are warranted, and if so the amount of such penalties. It is anticipated that the administrative law judge will set the procedural schedule after a second pre-hearing conference is held during the week of May 9, 2011.

The CPUC also is investigating a natural gas explosion and fire that occurred on December 24, 2008 in a house located in Rancho Cordova, California (“Rancho Cordova accident”). On February 17, 2011, the Utility submitted its report to the CPUC to provide extensive information, from as far back as January 1, 2000, about the Utility’s natural gas operating and maintenance practices and procedures. The Utility’s report agrees with the NTSB’s conclusions about the probable cause of the accident and explains what process improvements the Utility has made to prevent a similar accident in the future. The CPUC has scheduled an evidentiary hearing in mid-July.

If the CPUC determines that the Utility violated applicable laws in connection with the San Bruno or Rancho Cordova accidents, the CPUC could impose penalties of up to $20,000 per day, per violation which, in the aggregate, could have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows. Estimated liabilities associated with the Rancho Cordova investigation are included in the accrual for legal matters discussed above. In addition, law enforcement authorities could begin proceedings that could result in the imposition of civil or criminal fines or penalties on the Utility. PG&E Corporation and the Utility are unable to predict the ultimate outcome of the investigations discussed above or whether additional investigations or proceedings will be instituted.

Environmental Matters

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

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. The Utility records an environmental remediation liability when site assessments indicate that remediation is probable and it can reasonably estimate the loss within a range of possible amounts.

The Utility records an environmental remediation liability based on the lower end of the range of estimated costs, unless an amount within the range is a better estimate than any other amount. Amounts recorded are not discounted to their present value.

The Utility had an undiscounted and gross environmental remediation liability of $627 million at March 31, 2011 and $612 million at December 31, 2010. The following table presents the changes in the environmental remediation liability from December 31, 2010:


(in millions)
Balance at December 31, 2010			$ 612
Additional remediation costs accrued:
Transfer to regulatory account for recovery			33
Amounts not recoverable from customers			9
Less: Payments			(27)

Balance at March 31, 2011			$ 627

The $627 million accrued at March 31, 2011 consists of the following:

•

$45 million for remediation at the Utility’s natural gas compressor site located near Hinkley, California;

•

$180 million for remediation at the Utility’s natural gas compressor site located on the California border, near Topock, Arizona;

•

$83 million related to remediation at divested generation facilities;

•

$117 million related to remediation costs for the Utility’s generation and other facilities and for third-party disposal sites;

•

$142 million related to investigation and/or remediation costs at former MGP sites owned by the Utility or third parties (including those sites that are the subject of remediation orders by environmental agencies or claims by the current owners of the former MGP sites); and

•

$60 million related to remediation costs for fossil decommissioning sites.

Of the $627 million environmental remediation liability, the Utility expects to recover $327 million through the CPUC-approved ratemaking mechanism that authorizes the Utility to recover 90% of hazardous waste remediation costs without a reasonableness review (excluding any remediation associated with the Hinkley natural gas compressor site) and $135 million through the ratemaking mechanism that authorizes the Utility to recover 100% of remediation costs for decommissioning fossil-fueled sites and certain of the Utility’s transmission stations (excluding any remediation associated with divested generation facilities). The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility’s ultimate obligations may be subject to refund to customers.

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized. The Utility’s undiscounted future costs could increase to as much as $1.2 billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements. Recovery of these amounts would be subject to CPUC approval.

Tax Matters

In tax year 2008, PG&E Corporation began participating in the Compliance Assurance Process (“CAP”), a real-time Internal Revenue Service (“IRS”) audit intended to expedite resolution of tax matters. The CAP audit culminates with a letter from the IRS indicating their acceptance of the return. The IRS partially accepted the 2008 return, withholding two issues for further review. The most significant of these relates to a tax accounting method change filed by PG&E Corporation to accelerate the amount of deductible repairs. While the IRS approved PG&E Corporation’s request for a change in method, the IRS will audit the methodology to determine the proper deduction. This audit has not progressed significantly because the IRS is working with the utility industry to resolve this matter in a consistent manner for all utilities before auditing individual companies. In December 2010, the IRS accepted PG&E Corporation’s 2009 tax return. PG&E Corporation is currently under audit for the 2010 CAP year.

PG&E Corporation and the Utility expect the IRS to release new guidance clarifying the treatment of deductible repairs within the next 12 months. This guidance may result in a change in unrecognized tax benefits. PG&E Corporation and the Utility are unable to determine the potential impact of this change to the unrecognized tax benefits at this time.

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

PG&E Corporation believes that the final resolution of the federal and California audits will not have a material adverse impact on its financial condition or results of operations. PG&E Corporation is neither under audit nor subject to any material risk in any other jurisdiction.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

OVERVIEW

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

The Utility served 5.2 million electricity distribution customers and 4.3 million natural gas distribution customers at March 31, 2011. The Utility had $45.9 billion in assets at March 31, 2011 and generated revenues of $3.6 billion in the three months ended March 31, 2011.

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

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

Key Factors Affecting Results of Operations and Financial Condition

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

•

The Outcome of Matters Related to the Utility’s Natural Gas Pipeline System. The National Transportation Safety Board (“NTSB”) is continuing its investigation of the rupture of a Utility-owned natural gas pipeline on September 9, 2010 in San Bruno, California (the “San Bruno accident”). The NTSB has issued several public statements regarding its investigation of the San Bruno accident but has not yet determined the cause of the pipeline rupture. The CPUC is also investigating a natural gas explosion and fire that occurred on December 24, 2008 in a house located in Rancho Cordova, California (the “Rancho Cordova accident”). If the CPUC finds that the Utility violated applicable law in connection with these accidents, the CPUC may impose substantial penalties on the Utility. (See “Natural Gas Pipeline Matters” below). During the quarter ended March 31, 2011, the CPUC opened a rule-making proceeding and initiated a formal investigation of the Utility’s gas transmission pipeline recordkeeping. The Utility currently estimates that in 2011 it will incur incremental costs associated with its natural gas transmission business, including costs to comply with CPUC orders and NTSB recommendations, ranging from $350 million to $550 million. (See “Operating and Maintenance” and “Natural Gas Pipeline Matters” below.) These cost estimates could change depending on a number of factors, including the outcome of regulatory proceedings and pending investigations, as well as future rulemaking, ratemaking, or other investigatory proceedings that may be commenced at the CPUC. If state or federal legislation is enacted to address natural gas transmission operations and maintenance, the Utility may incur additional costs to comply with such new statutory requirements. It is uncertain how much of the costs the Utility incurs to comply with orders, recommendations, new CPUC regulations, or new legislation, will be recoverable through rates. In addition, various civil lawsuits have been filed by residents of San Bruno in California state courts against PG&E Corporation and the Utility related to

the San Bruno accident. The Utility currently estimates that it may incur as much as $400 million for third-party claims, including the $220 million provision recorded for the year ended December 31, 2010. (See Note 10 to the Notes of the Condensed Consolidated Financial Statements.) The total amount of third-party liability claims will depend on the final determination of the causes for the pipeline rupture and responsibility for the personal injuries and property damages, and the number and nature of third-party claims. Although PG&E Corporation and the Utility currently consider it likely that a significant portion of the costs the Utility incurs for third-party claims will ultimately be covered by its liability insurance, no amounts for insurance recoveries have been recorded as of March 31, 2011. The resolutions of the various regulatory matters and the outcome of the pending investigations and third-party claims may have a material adverse impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.

•

The Timing and Outcome of Ratemaking and Other Regulatory Proceedings. The majority of the Utility’s base revenue requirements for 2011 and several years thereafter are determined in various rate cases at the CPUC and the FERC. On April 14, 2011, the CPUC issued a decision in the Utility’s 2011 Gas Transmission and Storage rate case (“GT&S”) authorizing the Utility to collect increased revenue requirements from January 1, 2011. In the Utility’s 2011 General Rate Case (“GRC”) the CPUC will authorize a change in revenue requirements beginning on January 1, 2011, but the CPUC has not yet issued a decision. These and other regulatory proceedings are discussed under “Regulatory Matters” below. From time to time, the Utility also requests that the CPUC authorize additional base revenue requirements for specific capital expenditure projects, such as new power plants. The outcome of these proceedings can be affected by many factors, including general economic conditions, the level of customer rates, and political and regulatory policies. (See “Risk Factors” in the 2010 Annual Report.)

•

The Ability of the Utility to Control Operating Costs and Capital Expenditures. The Utility’s revenue requirements are generally set by the CPUC and the FERC at a level to allow the Utility the opportunity to recover its forecasted operating expenses, to recover depreciation, tax, and interest expenses associated with forecasted capital expenditures, and to earn a return on equity (“ROE”). Actual costs may differ from forecasts, or the Utility may incur significant unanticipated costs, such as costs related to storms, outages, catastrophic events, or costs incurred to comply with regulatory orders or legislation. For example, during the three months ended March 31, 2011, the Utility incurred comparatively higher expenses to respond to winter storms, as shown in the table below. As noted above, the Utility expects to incur material costs during 2011 to comply with CPUC orders and NTSB recommendations that have been issued in connection with the investigations of the San Bruno accident. (See “Operating and Maintenance” and “Natural Gas Pipeline Matters” below.) Differences in the amount or timing of forecasted or authorized and actual costs can affect the Utility’s ability to earn its authorized rate of return and the amount of PG&E Corporation’s income available for common shareholders. To the extent the Utility is unable to conclude that costs are probable of recovery through rates, the Utility will incur a charge to income.

•

Authorized Capital Structure, Rate of Return, and Financing. The Utility’s CPUC-authorized capital structure for its electric and natural gas distribution and electric generation rate base consisting of 52% common equity and 48% debt and preferred stock is scheduled to remain in effect through 2012. The Utility’s CPUC-authorized ROE of 11.35% is scheduled to remain in effect through 2012 but is subject to change based on an annual adjustment mechanism as described in the 2010 Annual Report. The timing and amount of the Utility’s future debt financing will depend primarily on the timing and amount of its capital expenditures. PG&E Corporation contributes equity to the Utility as needed by the Utility to maintain its CPUC-authorized capital structure. As the Utility incurs costs to perform pipeline safety-related work as described above, the amount of equity needed by the Utility to maintain its capital structure is anticipated to increase. PG&E Corporation anticipates issuing equity in the future to meet the Utility’s additional equity needs. (See “Liquidity and Financial Resources” below.)

Summary of Changes in Earnings per Common Share and Income Available for Common Shareholders for the Three Months Ended March 31, 2011

PG&E Corporation’s income available for common shareholders decreased by $59 million, or 23%, from $258 million for the three months ended March 31, 2010 to $199 million for the three months ended March 31, 2011. The following table is a summary reconciliation of the key changes in income available for common shareholders and earnings per common share for the three months ended March 31, 2011:


(in millions)	Earnings		Earnings Per Common Share (Diluted)
Income Available for Common Shareholders – March 31, 2010		$ 258		$ 0.67
Natural gas pipeline matters ⁽¹⁾		(31)		(0.08)
Delay in rate case decisions ⁽²⁾		(27)		(0.07)
Storm and outage expenses ⁽³⁾		(18)		(0.05)
Statewide ballot initiative⁽⁴⁾		25		0.07
Federal healthcare law⁽⁵⁾		20		0.05
Other⁽⁶⁾		(28)		(0.06)
Increase in shares outstanding⁽⁷⁾		-		(0.03)

Income Available for Common Shareholders – March 31, 2011		$ 199		$ 0.50


⁽¹⁾ During the three months ended March 31, 2011, the Utility incurred costs of $31 million, after-tax, to comply with CPUC orders and NTSB recommendations that have been issued in connection with investigations related to the San Bruno accident. These costs are primarily associated with an extensive review of the Utility’s pipeline records, as well as other activities associated with the accident and pending investigations. ⁽²⁾ During the three months ended March 31, 2011, the Utility incurred an unfavorable variance of $27 million, after-tax, representing expenses that would have been offset by increased revenues if the CPUC had issued final decisions in the Utility’s Gas Transmission and Storage Case and 2011 General Rate Case before March 31, 2011. ⁽³⁾ During the three months ended March 31, 2011, the Utility incurred higher expenses of $18 million, after-tax, due to more severe winter storms as compared to the same period in 2010. ⁽⁴⁾ During the three month period ended March 31, 2010, PG&E Corporation contributed $25 million to support Proposition 16 - The Taxpayers Right to Vote Act. ⁽⁵⁾ During the three months ended March 31, 2010, the Utility recorded a charge of $20 million triggered by the elimination of the tax deductibility of Medicare Part D federal subsidies. ⁽⁶⁾ During the three months ended March 31, 2011, the Utility incurred higher legal expenses, environmental remediation expenses, and other operating and maintenance expenses, partially offset by an increase in rate base earnings for electric transmission and separately funded projects, as compared to the same period in 2010. ⁽⁷⁾ Represents the impact of a higher number of shares outstanding at March 31, 2011, compared to the number of shares outstanding at March 31, 2010; this has no dollar impact on earnings.

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

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

•

the Utility’s ability to efficiently manage capital expenditures and its operating and maintenance expenses within authorized levels and timely recover its costs through rates;

•

the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigations by the NTSB and CPUC into the cause of the San Bruno accident and the safety of the Utility’s natural gas transmission pipelines in its northern and central California service territory; the CPUC investigation of the Rancho Cordova accident; whether the Utility incurs civil or criminal penalties as a result of these proceedings; whether the Utility is required to incur additional costs for third-

party liability claims or to comply with regulatory or legislative mandates that the Utility is unable to recover through rates or insurance; and whether the Utility incurs third-party liabilities or other costs in connection with service disruptions that may occur as the Utility complies with regulatory orders to decrease pressure in its natural gas transmission system;

•

reputational harm that PG&E Corporation and the Utility may suffer depending on the outcome of the various investigations, including those by the NTSB and the CPUC, the outcome of civil litigation, and the extent to which civil or criminal proceedings may be pursued by regulatory or governmental agencies;

•

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

•

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

•

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

•

the potential impacts of climate change on the Utility’s electricity and natural gas businesses;

•

changes in customer demand for electricity (“load”) and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, changes in technology that include the development of alternative technologies that enable customers to increase their reliance on self-generation, or other reasons;

•

the occurrence of unplanned outages at the Utility’s two nuclear generating units at Diablo Canyon, the availability of nuclear fuel, the outcome of seismic studies the Utility is conducting in the area near Diablo Canyon that could affect the Utility’s ability to operate Diablo Canyon or renew the operating licenses for Diablo Canyon, and the ability of the Utility to procure replacement electricity if nuclear generation from Diablo Canyon were unavailable;

•

the impact that the recent earthquake and tsunami in Japan may have on the Utility’s ability to continue its nuclear operations at Diablo Canyon or to renew the operating licenses for Diablo Canyon as a result of new legislation that may be adopted, or new orders or regulations that may be issued by the NRC or environmental agencies with respect to the operations, decommissioning, storage of spent nuclear fuel, security, safety, cooling water intake, or other matters associated with the operations at Diablo Canyon;

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

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

RESULTS OF OPERATIONS

The table below details certain items from the accompanying Condensed Consolidated Statements of Income for the three months ended March 31, 2011 and 2010:


	Three Months ended March 31,
(in millions)	2011		2010
Utility
Electric operating revenues		$ 2,616		$ 2,510
Natural gas operating revenues		980		965

Total operating revenues		3,596		3,475

Cost of electricity		888		920
Cost of natural gas		508		495
Operating and maintenance		1,226		990
Depreciation, amortization, and decommissioning		490		451

Total operating expenses		3,112		2,856

Operating income		484		619
Interest income		2		2
Interest expense		(171)		(156)
Other income (expense), net		17		(6)

Income before income taxes		332		459
Income tax provision		131		195

Net Income		201		264
Preferred stock dividend requirement		3		3

Income available for common stock		$ 198		$ 261

PG&E Corporation, Eliminations, and Other ⁽¹⁾
Operating revenues		$ 1		$ -
Operating expenses		1		1

Operating loss		-		(1)
Interest income		-		-
Interest expense		(6)		(12)
Other expense, net		-		-

Loss before income taxes		(6)		(13)
Income tax benefit		(7)		(10)

Net (loss) gain		$ 1		$ (3)

Consolidated Total
Operating revenues		$ 3,597		$ 3,475
Operating expenses		3,113		2,857

Operating income		484		618
Interest income		2		2
Interest expense		(177)		(168)
Other income (expense), net		17		(6)

Income before income taxes		326		446
Income tax provision		124		185

Net Income		202		261
Preferred stock dividend requirement of subsidiary		3		3

Income available for common shareholders		$ 199		$ 258


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

Utility

The following presents the Utility’s operating results for the three months ended March 31, 2011 and 2010. These operating results do not reflect the increase in revenues that is expected to occur upon authorization of the 2011 GRC by the CPUC. Revenues will be adjusted retroactively once a final decision is approved for the 2011 GRC. Revenues will also be retroactively adjusted during the second quarter of 2011 as a result of the CPUC’s final decision in the 2011 GT&S rate case which authorizes an increase in the Utility’s natural gas transmission and storage revenues effective as of January 1, 2011. (See “Regulatory Matters” below.)

Electric Operating Revenues

The Utility’s electric operating revenues consist of amounts charged to customers for electricity generation and for electric transmission and distribution services, as well as amounts charged to customers to recover the cost of electric procurement, public purpose, energy efficiency, and demand response programs. The Utility provides electricity to residential, industrial, agricultural, and small and large commercial customers through its own generation facilities and through power purchase agreements with third parties. In addition, a portion of the Utility’s customers’ load is satisfied by electricity provided under long-term contracts between the California Department of Water Resources (“DWR”) and various power suppliers. The commodity costs and associated revenues to recover the costs allocated to the Utility by the DWR are not included in the Condensed Consolidated Statements of Income.

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


	Three months ended March 31,
(in millions)	2011		2010
Revenues excluding pass-through costs		$ 1,523		$ 1,443
Revenues for recovery of passed-through costs		1,093		1,067

Total electric operating revenues		$ 2,616		$ 2,510

The Utility’s total electric operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $106 million, or 4%, in the three months ended March 31, 2011, as compared to the same period in 2010. Costs that are passed through to customers and do not impact net income increased by $26 million, primarily due to increases in the cost of public purpose programs and pension contributions which were partially offset by decreases in the cost of electricity procurement. (See “Cost of Electricity” below.) Electric operating revenues, excluding costs passed through to customers, increased by $80 million. This was primarily due to increases in authorized rate base for separately funded projects and an increase in electric transmission revenues as authorized by the FERC in an electric transmission owner (“TO”) rate case.

The Utility’s future electric operating revenues are expected to be impacted by the CPUC’s authorized decision in the 2011 GRC and the FERC in other TO rate cases. (See “Regulatory Matters” below.) The Utility also expects to continue to collect revenue requirements outside of the GRC that are related to capital expenditures that have already been approved by the CPUC or that may be approved by the CPUC in the future. Finally, the Utility may earn incentive revenues under the existing energy efficiency ratemaking mechanism.

Cost of Electricity

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

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)	2011		2010
Cost of purchased power		$ 821		$ 842
Fuel used in own generation facilities		67		78

Total cost of electricity		$ 888		$ 920

Average cost of purchased power per kWh ⁽¹⁾		$ 0.094		$ 0.083

Total purchased power (in kWh)		8,779		10,117


⁽¹⁾Kilowatt-hour

The Utility’s total cost of electricity decreased by $32 million, or 3%, in the three months ended March 31, 2011 as compared to the same period in 2010. This was caused by decreases in the volume of purchased power and the cost of fuel used in the Utility’s own generation facilities. The volume of purchased power is driven by customer demand, the availability of the Utility’s own electricity generation, 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 expects that it will be able to continue passing through the costs of its renewable energy purchase commitments to customers. (See “Environmental Matters” below.)

The Utility’s future cost of electricity also will be affected by federal or state legislation or rules that may be adopted to regulate GHG emissions. (See “Environmental Matters” below.)

Natural Gas Operating Revenues

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

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


	Three months ended March 31,
(in millions)	2011		2010
Revenues excluding pass-through costs		$ 404		$ 414
Revenues for recovery of passed-through costs		576		551

Total natural gas operating revenues		$ 980		$ 965

The Utility’s natural gas operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $15 million, or 2%, in the three months ended March 31, 2011 as compared to the same period in 2010. This reflects a $25 million increase in the costs which are passed through to customers and do not impact net income, primarily due to an increase in the costs of natural gas procurement, public purpose programs, and pension contributions. Natural gas operating revenues, excluding costs passed through to customers, decreased by $10 million, primarily due to a decrease in natural gas storage revenues.

The CPUC’s final decision in the 2011 GT&S rate case provides for an overall increase in the revenue requirements and rates for the Utility’s gas transmission and storage services for 2011 through 2014. Natural gas operating revenues also will be impacted by the CPUC’s expected decision in the 2011 GRC. (See “Regulatory Matters” below.) Additionally, the Utility may earn incentive revenues under the existing energy efficiency ratemaking mechanism. (See “Regulatory Matters” below.)

Cost of Natural Gas

The Utility’s cost of natural gas includes the purchase costs of natural gas, transportation costs on interstate pipelines, and gas storage costs, but excludes the transportation costs on intrastate pipelines for core and non-core customers, which are included in operating and maintenance expense in the Condensed Consolidated Statements of Income. The Utility’s cost of natural gas also includes realized gains and losses on price risk management activities. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)

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


	Three months ended March 31,
(in millions)	2011		2010
Cost of natural gas sold		$ 461		$ 444
Transportation cost of natural gas sold		47		51

Total cost of natural gas		$ 508		$ 495

Average cost per Mcf ⁽¹⁾ of natural gas sold		$ 4.52		$ 4.67

Total natural gas sold (in millions of Mcf)		102		95


⁽¹⁾ One thousand cubic feet

The Utility’s total cost of natural gas increased by $13 million, or 3%, in the three months ended March 31, 2011 as compared to the same period in 2010. The increase was primarily due to the absence in 2011 of the $49 million the Utility received in the first quarter of 2010 to be refunded to customers as part of a litigation settlement arising from the manipulation of the natural gas market by third parties during 1999 through 2002. The increase resulting from the settlement was partially offset by a decrease in procurement costs due to decreases in the average market price of natural gas purchased.

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

Operating and Maintenance

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

The Utility’s operating and maintenance expenses (including costs passed through to customers) increased by $236 million, or 24%, in the three months ended March 31, 2011, as compared to the same period in 2010. Increases in pass-through costs include a $23 million increase in pension plan contributions and a $52 million increase in the cost of public purpose programs due to an increase in the level of program spending. Excluding costs passed through to customers, operating and maintenance expenses increased by $161 million, primarily due to costs of $51 million that the Utility incurred to comply with CPUC orders and NTSB recommendations that have been issued in connection with the investigation of the San Bruno accident (see “Natural Gas Pipeline Matters” below), $31 million in higher costs related to more severe winter storms in 2011, and increases in other expenses, including legal, regulatory, and environmental items.

The Utility currently estimates that it will incur incremental costs associated with its natural gas transmission business ranging from $350 million to $550 million in 2011, including costs to complete its review and validation of pipeline records, to perform pressure tests and other tests on portions of its natural gas transmission system, to respond to regulatory proceedings, and to perform other activities related to the safety of its gas pipeline system. These cost estimates could change depending on a number of factors, including the outcome of the regulatory proceedings and investigations discussed below under “Natural Gas Pipeline Matters” and new state and federal laws that may be adopted. PG&E Corporation and the Utility are uncertain what portion of the costs the Utility may incur to respond to orders, recommendations, or new legislative requirements, would be recoverable through rates and the timing of any such recovery.

Future operating and maintenance expenses also may be affected by the amount of third party liability the Utility incurs as a result of the San Bruno accident as well as by the amount of fines the CPUC may impose on the Utility in connection with the pending investigations discussed below. (See “Natural Gas Pipeline Matters” below and Note 10 of the Notes to the Condensed Consolidated Financial Statements.) If the CPUC determines in the investigations discussed below that the Utility violated laws, rules, regulations or orders, the CPUC may impose fines or penalties on the Utility, which may be material.

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 and nuclear decommissioning. The Utility’s depreciation, amortization, and decommissioning expenses increased by $39 million, or 9%, in the three months ended March 31, 2011, as compared to the same period in 2010, primarily due to an increase in authorized capital additions.

The Utility’s depreciation expense for future periods is expected to increase as a result of an overall increase in capital expenditures and implementation of depreciation rates authorized by the CPUC. Depreciation expense in subsequent years will be determined based on rates to be set by the CPUC in the 2011 GRC and by the FERC in future TO rate cases.

Interest Income

The Utility’s interest income increased by less than $1 million in the three months ended March 31, 2011, as compared to the same period in 2010, due to fluctuations in various regulatory balancing accounts.

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

Interest Expense

The Utility’s interest expense increased by $15 million, or 10%, in the three months ended March 31, 2011, as compared to the same period in 2010. The increase resulted from higher interest costs due to an increase in outstanding senior notes and was partially offset by a decrease in the outstanding balance of the energy recovery bonds (“ERBs”). (See Note 4 of the Notes to the Condensed Consolidated Financial Statements.)

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

Other Income, Net

The Utility’s other income, net increased by $23 million in the three months ended March 31, 2011, as compared to the same period in 2010. The increase was primarily due to a $25 million decrease in other expenses as a result of costs the Utility incurred in 2010 to support a California ballot initiative that appeared on the June 2010 ballot, with no similar activity in the current year. This expense was partially offset by an $8 million decrease in allowance for equity funds used during construction due to lower average balances of construction work in progress.

Income Tax Provision

The Utility’s income tax provision decreased by $64 million, or 33%, in the three months ended March 31, 2011, as compared to the same period in 2010. The effective tax rates were 38% and 42% for 2011 and 2010, respectively. The effective tax rate decreased in the three months ended March 31, 2011, as compared to the same period in 2010 when the Utility incurred non tax deductible lobbying expenses associated with a ballot initiative and reversed a deferred tax asset that had previously been recorded to reflect the future tax benefits attributable to the Medicare Part D subsidy after 2012, which was eliminated as part of the federal healthcare legislation passed during 2010.

PG&E Corporation, Eliminations, and Other

Operating Revenues and Expenses

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

There were no material changes to PG&E Corporation’s operating income in the three months ended March 31, 2011, as compared to the same period in 2010.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

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

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

Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s revolving credit facilities at March 31, 2011:


(in millions)	Termination Date		Facility Limit			Letters of Credit Outstanding		Cash Borrowings		Commercial Paper Backup		Availability
PG&E Corporation		February 2012		$ 187	⁽¹⁾		$ -		$-		$ -		$ 187
Utility		February 2012		1,940	⁽²⁾		315		-		1,019		606
Utility		February 2012		750	⁽³⁾		N/A		-		-		750

Total credit facilities				$ 2,877			$ 315		$-		$ 1,019		$ 1,543


⁽¹⁾ Includes an $87 million sublimit for letters of credit and a $100 million commitment for “swingline” loans, defined as loans that are made available on a same-day basis and are repayable in full within 30 days. ⁽²⁾ Includes a $921 million sublimit for letters of credit and a $200 million commitment for swingline loans. ⁽³⁾ Includes a $75 million commitment for swingline loans.

For the three months ended March 31, 2011, the average outstanding commercial paper balance was $735 million and the maximum outstanding balance during the quarter was $1.2 billion. There were no cash borrowings on the revolving credit facilities in the three months ended March 31, 2011.

PG&E Corporation’s and the Utility’s credit agreements contain covenants that are usual and customary for credit facilities of this type, including covenants limiting liens, mergers, substantial asset sales, and other fundamental changes. Both the $750 million and the $1.9 billion revolving credit facilities require that 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. In addition, the $187 million revolving credit facility agreement requires that PG&E Corporation must own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting capital stock of the Utility.

At March 31, 2011, PG&E Corporation and the Utility were in compliance with all covenants under each of the revolving credit facilities listed in the table above.

2011 Financings

During the three months ended March 31, 2011, PG&E Corporation issued 2,032,223 shares of common stock upon the exercise of employee stock options and under its 401(k) plan and Dividend Reinvestment and Stock Purchase Plan, generating $82 million of cash.

During the three months ended March 31, 2011, the Utility received cash contributions of $65 million from PG&E Corporation to ensure that the Utility had adequate capital to maintain the 52% common equity ratio authorized by the CPUC.

Future Financing Needs

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

•

the amount of cash internally generated through normal business operations;

•

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

•

the timing of the resolution of the Chapter 11 disputed claims and the amount of interest on these claims that the Utility will be required to pay;

•

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

•

the timing and amount of payments related to costs incurred to comply with CPUC orders and NTSB recommendations that have been issued in connection with the San Bruno accident (see “Operating and Maintenance” above and “Natural Gas Pipeline Matters” below);

•

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

•

the conditions in the capital markets, and other factors. (See Notes 9 and 10 of the Notes to the Condensed Consolidated Financial Statements.)

PG&E Corporation’s future financing needs depend primarily on the timing and amount of contributions made to the Utility to maintain the Utility’s 52% common equity ratio authorized by the CPU

PACIFIC GAS & ELECTRIC Co - FORM 10-Q - May 4, 2011

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