PACIFIC GAS & ELECTRIC Co - FORM 10-Q

Attached files

file	filename
EX-12.1 - COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES FOR PACIFIC GAS AND ELECTRIC - PACIFIC GAS & ELECTRIC Co	dex121.htm
EX-12.3 - COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARES FOR PG&E COPORATION - PACIFIC GAS & ELECTRIC Co	dex123.htm
EX-10.2 - CREDIT AGREEMENT - PACIFIC GAS & ELECTRIC Co	dex102.htm
EX-31.1 - CERTIFICATION OF CEO AND CFO OF PG&E CORPORATION REQUIRED BY SECTION 302 - PACIFIC GAS & ELECTRIC Co	dex311.htm
EX-31.2 - CERTIFICATION OF CEO AND CFO OF PACIFIC GAS AND ELEC CO REQUIRED BY SECTION 302 - PACIFIC GAS & ELECTRIC Co	dex312.htm
EX-10.1 - PG&E CORPORATION 2006 LONG-TERM INCENTIVE PLAN - PACIFIC GAS & ELECTRIC Co	dex101.htm
EX-12.2 - COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES-PREF STOCK DIVIDENDS - PACIFIC GAS & ELECTRIC Co	dex122.htm
EX-32.1 - CERTIFICATION OF CEO AND CFO OF PG&E CORPORATION REQUIRED BY SECTION 906 - PACIFIC GAS & ELECTRIC Co	dex321.htm
EX-32.2 - CERTIFICATION OF CEO AND CFO OF PACIFIC GAS AND ELEC CO REQUIRED BY SECTION 906 - PACIFIC GAS & ELECTRIC Co	dex322.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 June 30, 2010

[ ]

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission

File

Number

Exact Name of

Registrant

as specified

in its charter

State or other

Jurisdiction of

Incorporation

IRS Employer

Identification

Number

1-12609

1-2348

PG&E Corporation

Pacific Gas and Electric Company

California

94-3234914

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 July 29, 2010:


PG&E Corporation		390,752,206
Pacific Gas and Electric Company		264,374,809

PG&E CORPORATION AND

PACIFIC GAS AND ELECTRIC COMPANY,

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2010

TABLE OF CONTENTS


			PAGE
PART I.	FINANCIAL INFORMATION

ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS PG&E Corporation
	Condensed Consolidated Statements of Income		3
	Condensed Consolidated Balance Sheets		4
	Condensed Consolidated Statements of Cash Flows		6
	Pacific Gas and Electric Company
	Condensed Consolidated Statements of Income		7
	Condensed Consolidated Balance Sheets		8
	Condensed Consolidated Statements of Cash Flows		10
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:	Organization and Basis of Presentation	11
	NOTE 2:	Significant Accounting Policies	11
	NOTE 3:	Regulatory Assets, Liabilities, and Balancing Accounts	14
	NOTE 4:	Debt	17
	NOTE 5:	Equity	18
	NOTE 6:	Earnings Per Share	19
	NOTE 7:	Derivatives and Hedging Activities	21
	NOTE 8:	Fair Value Measurements	25
	NOTE 9:	Related Party Agreements and Transactions	31
	NOTE 10:	Resolution of Remaining Chapter 11 Disputed Claims	31
	NOTE 11:	Commitments and Contingencies	32

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview		39
	Cautionary Language Regarding Forward-Looking Statements		41
	Results of Operations		43
	Liquidity and Financial Resources		49
	Contractual Commitments		53
	Capital Expenditures		53
	Off-Balance Sheet Arrangements		55
	Contingencies		55
	Regulatory Matters		55
	Environmental Matters		57
	Other Matters		59
	Risk Management Activities		60
	Critical Accounting Policies		62

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		63
ITEM 4.	CONTROLS AND PROCEDURES		63

PART II.	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS		64
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		64
ITEM 5.	OTHER INFORMATION		65
ITEM 6.	EXHIBITS		66

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	(Unaudited)
	Three Months Ended June 30,						Six Months Ended June 30,
(in millions, except per share amounts)	2010			2009			2010			2009
Operating Revenues
Electric	$	2,515		$	2,554		$	5,025		$	4,980
Natural gas		717			640			1,682			1,645

Total operating revenues		3,232			3,194			6,707			6,625

Operating Expenses
Cost of electricity		863			883			1,783			1,766
Cost of natural gas		247			188			742			745
Operating and maintenance		959			1,038			1,950			2,097
Depreciation, amortization, and decommissioning		468			429			919			848

Total operating expenses		2,537			2,538			5,394			5,456

Operating Income		695			656			1,313			1,169
Interest income		2			17			4			26
Interest expense		(175	)		(178	)		(343	)		(359	)
Other income (expense), net		2			22			(4	)		40

Income Before Income Taxes		524			517			970			876
Income tax provision		187			125			372			240

Net Income		337			392			598			636
Preferred stock dividend requirement of subsidiary		4			4			7			7

Income Available for Common Shareholders	$	333		$	388		$	591		$	629

Weighted Average Common Shares Outstanding, Basic		373			368			372			366

Weighted Average Common Shares Outstanding, Diluted		390			369			389			367

Net Earnings Per Common Share, Basic	$	0.88		$	1.03		$	1.56		$	1.68

Net Earnings Per Common Share, Diluted	$	0.86		$	1.02		$	1.54		$	1.67

Dividends Declared Per Common Share	$	0.46		$	0.42		$	0.91		$	0.84

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


	(Unaudited)
	Balance At
(in millions)	June 30, 2010			December 31, 2009
ASSETS
Current Assets
Cash and cash equivalents	$	265		$	527
Restricted cash		583			633
Accounts receivable:
Customers (net of allowance for doubtful accounts of $71 at June 30, 2010 and $68 at December 31, 2009)		846			859
Accrued unbilled revenue		722			671
Regulatory balancing accounts		1,369			1,109
Other		759			750
Inventories:
Gas stored underground and fuel oil		142			114
Materials and supplies		192			200
Income taxes receivable		—			127
Prepaid expenses and other		734			667

Total current assets		5,612			5,657

Property, Plant, and Equipment
Electric		31,408			30,481
Gas		10,971			10,697
Construction work in progress		2,149			1,888
Other		14			14

Total property, plant, and equipment		44,542			43,080
Accumulated depreciation		(14,559	)		(14,188	)

Net property, plant, and equipment		29,983			28,892

Other Noncurrent Assets
Regulatory assets ($944 and $1,124 related to Energy Recovery Bonds at June 30, 2010 and December 31, 2009, respectively)		5,610			5,522
Nuclear decommissioning trusts		1,854			1,899
Income taxes receivable		693			596
Other		466			379

Total other noncurrent assets		8,623			8,396

TOTAL ASSETS	$	44,218		$	42,945

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


	(Unaudited)
	Balance At
(in millions, except share amounts)	June 30, 2010			December 31, 2009
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	1,057		$	833
Long-term debt, classified as current		595			342
Energy recovery bonds, classified as current		395			386
Accounts payable:
Trade creditors		920			984
Disputed claims and customer refunds		746			773
Regulatory balancing accounts		437			281
Other		356			349
Interest payable		839			818
Income taxes payable		634			214
Deferred income taxes		403			332
Other		1,237			1,501

Total current liabilities		7,619			6,813

Noncurrent Liabilities
Long-term debt		10,179			10,381
Energy recovery bonds		636			827
Regulatory liabilities		4,275			4,125
Pension and other postretirement benefits		2,018			1,773
Asset retirement obligations		1,600			1,593
Deferred income taxes		4,637			4,732
Other		2,131			2,116

Total noncurrent liabilities		25,476			25,547

Commitments and Contingencies
Equity
Shareholders’ Equity
Preferred stock, no par value, authorized 80,000,000 shares, $100 par value, authorized 5,000,000 shares, none issued		—			—
Common stock, no par value, authorized 800,000,000 shares, 390,103,473 shares outstanding (including 476,312 restricted shares) at June 30, 2010 and 371,272,457 shares outstanding (including 670,552 restricted shares) at December 31, 2009		6,646			6,280
Reinvested earnings		4,457			4,213
Accumulated other comprehensive loss		(232	)		(160	)

Total shareholders’ equity		10,871			10,333
Noncontrolling Interest – Preferred Stock of Subsidiary		252			252

Total equity		11,123			10,585

TOTAL LIABILITIES AND EQUITY	$	44,218		$	42,945

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	(Unaudited)
	Six Months Ended June 30,
(in millions)	2010			2009
Cash Flows from Operating Activities
Net income	$	598		$	636
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,038			944
Allowance for equity funds used during construction		(57	)		(47	)
Deferred income taxes and tax credits, net		(3	)		377
Other changes in noncurrent assets and liabilities		(97	)		(46	)
Effect of changes in operating assets and liabilities:
Accounts receivable		(47	)		198
Inventories		(20	)		113
Accounts payable		7			(143	)
Income taxes receivable/payable		458			161
Regulatory balancing accounts, net		(206	)		(228	)
Other current assets		28			10
Other current liabilities		(326	)		(224	)
Other		—			3

Net cash provided by operating activities		1,373			1,754

Cash Flows from Investing Activities
Capital expenditures		(1,786	)		(2,077	)
Decrease in restricted cash		50			15
Proceeds from sales and maturities of nuclear decommissioning trust investments		685			954
Purchases of nuclear decommissioning trust investments		(696	)		(985	)
Other		4			12

Net cash used in investing activities		(1,743	)		(2,081	)

Cash Flows from Financing Activities
Borrowings under revolving credit facilities		30			300
Repayments under revolving credit facilities		—			(300	)
Net issuance (repayments) of commercial paper, net of discount of $1 in 2010 and $3 in 2009		693			(47	)
Proceeds from issuance of short-term debt, net of issuance costs of $1 in 2009		—			499
Proceeds from issuance of long-term debt, net of discount and issuance costs of $5 in 2010 and $16 in 2009		295			884
Short-term debt matured		(500	)		—
Long-term debt matured		—			(600	)
Energy recovery bonds matured		(182	)		(174	)
Common stock issued		89			182
Common stock dividends paid		(320	)		(286	)
Other		3			(12	)

Net cash provided by financing activities		108			446

Net change in cash and cash equivalents		(262	)		119
Cash and cash equivalents at January 1		527			219

Cash and cash equivalents at June 30	$	265		$	338

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(309	)	$	(298	)
Income taxes, net		36			201
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	178		$	155
Capital expenditures financed through accounts payable		209			245
Noncash common stock issuances		253			39

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	(Unaudited)
	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2010			2009			2010			2009
Operating Revenues
Electric	$	2,515		$	2,554		$	5,025		$	4,980
Natural gas		717			640			1,682			1,645

Total operating revenues		3,232			3,194			6,707			6,625

Operating Expenses
Cost of electricity		863			883			1,783			1,766
Cost of natural gas		247			188			742			745
Operating and maintenance		958			1,037			1,948			2,096
Depreciation, amortization, and decommissioning		468			429			919			848

Total operating expenses		2,536			2,537			5,392			5,455

Operating Income		696			657			1,315			1,170
Interest income		2			17			4			26
Interest expense		(164	)		(166	)		(320	)		(339	)
Other income (expense), net		1			15			(5	)		36

Income Before Income Taxes		535			523			994			893
Income tax provision		196			132			391			263

Net Income		339			391			603			630
Preferred stock dividend requirement		4			4			7			7

Income Available for Common Stock	$	335		$	387		$	596		$	623

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS


	(Unaudited)
	Balance At
(in millions)	June 30, 2010			December 31, 2009
ASSETS
Current Assets
Cash and cash equivalents	$	60		$	334
Restricted cash		583			633
Accounts receivable:
Customers (net of allowance for doubtful accounts of $71 at June 30, 2010 and $68 at December 31, 2009)		846			859
Accrued unbilled revenue		722			671
Regulatory balancing accounts		1,369			1,109
Other		794			751
Inventories:
Gas stored underground and fuel oil		142			114
Materials and supplies		192			200
Income taxes receivable		—			138
Prepaid expenses and other		733			662

Total current assets		5,441			5,471

Property, Plant, and Equipment
Electric		31,408			30,481
Gas		10,971			10,697
Construction work in progress		2,149			1,888

Total property, plant, and equipment		44,528			43,066
Accumulated depreciation		(14,546	)		(14,175	)

Net property, plant, and equipment		29,982			28,891

Other Noncurrent Assets
Regulatory assets ($944 and $1,124 related to Energy Recovery Bonds at June 30, 2010 and December 31, 2009, respectively)		5,610			5,522
Nuclear decommissioning trusts		1,854			1,899
Income taxes receivable		740			610
Other		368			316

Total other noncurrent assets		8,572			8,347

TOTAL ASSETS	$	43,995		$	42,709

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS


	(Unaudited)
	Balance At
(in millions, except share amounts)	June 30, 2010			December 31, 2009
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings	$	1,027		$	833
Long-term debt, classified as current		595			95
Energy recovery bonds, classified as current		395			386
Accounts payable:
Trade creditors		920			984
Disputed claims and customer refunds		746			773
Regulatory balancing accounts		437			281
Other		367			363
Interest payable		834			813
Income tax payable		662			223
Deferred income taxes		409			334
Other		1,032			1,307

Total current liabilities		7,424			6,392

Noncurrent Liabilities
Long-term debt		9,831			10,033
Energy recovery bonds		636			827
Regulatory liabilities		4,275			4,125
Pension and other postretirement benefits		1,960			1,717
Asset retirement obligations		1,600			1,593
Deferred income taxes		4,688			4,764
Other		2,099			2,073

Total noncurrent liabilities		25,089			25,132

Commitments and Contingencies
Shareholders’ Equity
Preferred stock without mandatory redemption provisions:
Nonredeemable, 5.00% to 6.00%, 5,784,825 shares outstanding at June 30, 2010 and December 31, 2009		145			145
Redeemable, 4.36% to 5.00%, 4,534,958 shares outstanding at June 30, 2010 and December 31, 2009		113			113
Common stock, $5 par value, authorized 800,000,000 shares, 264,374,809 shares outstanding at June 30, 2010 and December 31, 2009		1,322			1,322
Additional paid-in capital		3,186			3,055
Reinvested earnings		6,942			6,704
Accumulated other comprehensive loss		(226	)		(154	)

Total shareholders’ equity		11,482			11,185

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	43,995		$	42,709

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	(Unaudited)
	Six Months Ended June 30,
(in millions)	2010			2009
Cash Flows from Operating Activities
Net income	$	603		$	630
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,016			932
Allowance for equity funds used during construction		(57	)		(47	)
Deferred income taxes and tax credits, net		(1	)		368
Other changes in noncurrent assets and liabilities		(63	)		(34	)
Effect of changes in operating assets and liabilities:
Accounts receivable		(81	)		199
Inventories		(20	)		113
Accounts payable		4			(140	)
Income taxes receivable/payable		475			64
Regulatory balancing accounts, net		(206	)		(228	)
Other current assets		28			10
Other current liabilities		(316	)		(220	)
Other		—			3

Net cash provided by operating activities		1,382			1,650

Cash Flows from Investing Activities
Capital expenditures		(1,786	)		(2,077	)
Decrease in restricted cash		50			15
Proceeds from sales and maturities of nuclear decommissioning trust investments		685			954
Purchases of nuclear decommissioning trust investments		(696	)		(985	)
Other		11			5

Net cash used in investing activities		(1,736	)		(2,088	)

Cash Flows from Financing Activities
Borrowings under revolving credit facilities		—			300
Repayments under revolving credit facilities		—			(300	)
Net issuance (repayments) of commercial paper, net of discount of $1 in 2010 and $3 in 2009		693			(47	)
Proceeds from issuance of short-term debt, net of issuance costs of $1 in 2009		—			499
Proceeds from issuance of long-term debt, net of discount and issuance costs of $5 in 2010 and $12 in 2009		295			538
Short-term debt matured		(500	)		—
Long-term debt matured		—			(600	)
Energy recovery bonds matured		(182	)		(174	)
Preferred stock dividends paid		(7	)		(7	)
Common stock dividends paid		(358	)		(312	)
Equity contribution		130			653
Other		9			(6	)

Net cash provided by financing activities		80			544

Net change in cash and cash equivalents		(274	)		106
Cash and cash equivalents at January 1		334			52

Cash and cash equivalents at June 30	$	60		$	158

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(287	)	$	(286	)
Income taxes, net		34			70
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	209		$	245

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 primarily 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 U.S. generally accepted accounting principles (“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, 2009 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 2009 Annual Report on Form 10-K filed on February 19, 2010. PG&E Corporation’s and the Utility’s combined 2009 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 “2009 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, environmental remediation liabilities, asset retirement obligations (“ARO”), income tax-related assets and liabilities, pension plan and other postretirement plan obligations, and accruals for legal matters. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations during the period in which such change occurred. This quarterly report should be read in conjunction with the 2009 Annual Report.

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 2009 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 and six-months ended June 30, 2010 and 2009 were as follows:


		Pension Benefits						Other Benefits
		Three Months Ended June 30,						Three Months Ended June 30,
	(in millions)	2010			2009			2010			2009
	Service cost for benefits earned	$	69		$	67		$	9		$	7
	Interest cost		161			155			23			21
	Expected return on plan assets		(156	)		(145	)		(18	)		(17	)
	Amortization of transition obligation		—			—			6			7
	Amortization of prior service cost		13			12			6			4
	Amortization of unrecognized loss		11			24			1			1

	Net periodic benefit cost		98			113			27			23

	Less: transfer to regulatory account ⁽¹⁾		(58	)		(72	)		—			—

	Total	$	40		$	41		$	27		$	23


⁽¹⁾	The Utility recorded $58 million and $72 million for the three month periods ended June 30, 2010 and 2009, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates.

		Pension Benefits						Other Benefits
		Six Months Ended June 30,						Six Months Ended June 30,
	(in millions)	2010			2009			2010			2009
	Service cost for benefits earned	$	139		$	133		$	19		$	15
	Interest cost		322			310			46			42
	Expected return on plan assets		(312	)		(290	)		(36	)		(34	)
	Amortization of transition obligation		—			—			12			13
	Amortization of prior service cost		27			23			12			8
	Amortization of unrecognized loss		21			49			2			2

	Net periodic benefit cost		197			225			55			46

	Less: transfer to regulatory account ⁽¹⁾		(115	)		(143	)		—			—

	Total	$	82		$	82		$	55		$	46


⁽¹⁾	The Utility recorded $115 million and $143 million for the six month periods ended June 30, 2010 and 2009, respectively, to a regulatory account as the amounts are probable of recovery from customers in future rates.

There was no material difference between PG&E Corporation’s and the Utility’s consolidated net periodic benefit costs for the three and six months ended June 30, 2010 and 2009.

On February 16, 2010, the Utility amended its defined benefit medical plans for retirees to provide for additional contributions towards retiree premiums. The plan amendment was accounted for as a plan modification that required re-measurement of the accumulated benefit obligation, plan assets, and periodic benefit costs. The inputs and assumptions used in re-measurement did not change significantly from December 31, 2009 and did not have a material impact on the funded status of the plans. The re-measurement of the accumulated benefit obligation and plan assets resulted in an increase to pension and other postretirement benefits and a decrease to other comprehensive income of $148 million. The impact to net periodic benefit cost was not material.

Adoption of New Accounting Pronouncements

Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities

On January 1, 2010, PG&E Corporation and the Utility adopted an accounting standards update that changes when and how to determine, or re-determine, whether an entity is a variable interest entity (“VIE”), which could require consolidation. In addition, the new guidance replaces the quantitative approach for determining who has a controlling financial interest in a VIE with a qualitative approach, and requires ongoing assessments of whether an entity is the primary beneficiary of a VIE. The adoption of the accounting standards update did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

PG&E Corporation and the Utility are required to consolidate any entities which the companies control. In most cases, control can be determined based on majority ownership or voting interests. However, for certain entities, control is difficult to discern based on equity or voting interests alone. These entities are referred to as VIEs. A VIE is an entity which does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise has a controlling financial interest if it has (1) the obligation to absorb expected losses or receive expected gains that could potentially be significant to the VIE and (2) the power to direct the activities that are most significant to the VIE’s economic performance. The enterprise that has a controlling financial interest is known as the VIE’s primary beneficiary and is the enterprise that is required to consolidate the VIE.

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. In determining whether the Utility has a controlling financial interest in the VIE, the Utility must first assess whether it absorbs any of the VIE’s expected losses or receives portions of the expected residual returns as a result of the power purchase agreement. This assessment includes an evaluation of how the risks and rewards associated with the power plant’s activities are absorbed by variable interest holders. These VIEs are typically exposed to credit risk, production risk, commodity price risk, and any applicable tax incentive risks, among others. The Utility analyzes the variability in the VIE’s gross margin and the impact of the power purchase agreement on the gross margin to determine whether the Utility absorbs variability, resulting in a variable interest. Factors that may be considered when assessing the impact of the power purchase agreement on the VIE’s gross margin include the pricing structure of the agreement and the cost of inputs and production, depending on the technology of the power plant.

For each variable interest, the Utility must also determine whether it has the power to direct the activities of the power plant that most directly impact the VIE’s economic performance. The Utility’s assessment of the activities that are economically significant to the VIE’s performance often include 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 its power purchase agreement with the Utility.

The Utility held a variable interest in several entities that own power plants that generate electricity for sale to the Utility under power purchase agreements. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility utilizing various technologies such as natural gas, wind, solar photovoltaic, solar thermal, hydroelectric, and other technologies. Under each power purchase agreement, the Utility is obligated to purchase electricity or capacity, or both, from the VIEs. The Utility does not provide any other financial or other support to these VIEs and the Utility’s financial exposure is limited to the amount it pays for delivered electricity and capacity. (See Note 11 below.) The Utility does not have the power to direct the activities of the VIE that are most significant to the VIE’s economic performance. As a result, the Utility does not have a controlling financial interest in any of these VIEs. Therefore, at June 30, 2010, the Utility was not the primary beneficiary of any of these VIEs.

The Utility continues to consolidate PG&E Energy Recovery Funding LLC (“PERF”) at June 30, 2010, as the Utility is the primary beneficiary of PERF. The Utility has a controlling financial interest in PERF as the Utility is exposed to PERF’s losses and returns through the Utility’s equity investment in PERF, and the Utility was involved in the design of PERF, an activity that is significant to PERF’s economic performance. The assets of PERF were $1.1 billion at June 30, 2010, and primarily consisted of regulatory assets related to energy recovery bonds, which is included in long-term regulatory assets in the Condensed Consolidated Balance Sheets. The liabilities of PERF were $1.0 billion at June 30, 2010, and consisted of energy recovery bonds, which is 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.

As of June 30, 2010, PG&E Corporation’s affiliates had entered into tax equity agreements with two privately held companies, SolarCity Corp. (“SolarCity”) and SunRun, Inc. (“SunRun”), to fund residential and commercial retail solar energy installations. SolarCity and SunRun are VIEs. Under master lease agreements with SolarCity, PG&E Corporation will provide payments of up to $80 million, and in return, receive a share of SolarCity customer lease revenues, along with the benefits of local rebates and federal investment tax credits. Under an agreement with SunRun, PG&E Corporation will fund investments up to $100 million and will receive a share of customer payments, as well as federal investment tax credits and other tax benefits. As of June 30, 2010, PG&E Corporation had made total payments of $33 million under these two arrangements, which was recorded in noncurrent assets – other in the Condensed Consolidated Balance Sheets. PG&E Corporation held a variable interest in these entities as a result of these tax equity agreements. When determining whether PG&E Corporation was the primary beneficiary of the VIEs, PG&E Corporation evaluated which party had control over significant economic activities such as designing the entity, vendor selection, construction, customer selection, and remarketing activities at the end of the customer leases, among other activities. As these activities were under the control of SolarCity and SunRun, PG&E Corporation was not the primary beneficiary of these VIEs at June 30, 2010. PG&E Corporation’s financial exposure for these arrangements is primarily limited to its tax equity investments in SolarCity and SunRun.

Improving Disclosures about Fair Value Measurements

On January 1, 2010, PG&E Corporation and the Utility adopted an accounting standards update that requires disclosures regarding significant transfers in and out of fair value hierarchy levels, and fair value measurement inputs and valuation techniques. Furthermore, the update requires presentation of disaggregated activity within the reconciliation for fair value measurements using significant unobservable (Level 3) inputs, beginning for the first quarter of 2011. The adoption of the accounting standards update did not have a material impact on PG&E Corporation’s or the Utility’s Condensed Consolidated Financial Statements.

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. The regulatory assets are amortized over future periods when 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 June 30, 2010 and December 31, 2009, the Utility had current regulatory assets of $570 million and $427 million, respectively, consisting primarily of the current portion of price risk management regulatory assets. Price risk management regulatory assets represent the deferral of unrealized losses related to price risk management derivative instruments with terms of one year or less. (See Note 7 below for further discussion.) Current regulatory assets are included in prepaid expenses and other in the Condensed Consolidated Balance Sheets.

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:


	Balance at
(in millions)	June 30, 2010		December 31, 2009
Pension benefits	$	1,455	$	1,386
Deferred income taxes		1,116		1,027
Energy recovery bonds		944		1,124
Utility retained generation		701		737
Price risk management		459		346
Environmental compliance costs		398		408
Unamortized loss, net of gain, on reacquired debt		192		203
Other		345		291

Total long-term regulatory assets	$	5,610	$	5,522

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 13 of the Notes to the Consolidated Financial Statements in the 2009 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.

The regulatory asset for energy recovery bonds (“ERBs”) represents the refinancing of the regulatory asset provided for in 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”). (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.

In connection with the Chapter 11 Settlement Agreement, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are 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 14 years.

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 environmental compliance costs represent the portion of estimated environmental remediation costs that the Utility expects to recover in future rates as actual remediation costs are incurred. The Utility expects to recover these costs over the next 32 years. (See Note 11 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 June 30, 2010 and December 31, 2009, “other” consisted of regulatory assets relating to ARO expenses that are probable of future recovery through the ratemaking process, removal costs associated with the replacement of the steam generators in the Utility’s two nuclear generating units at the Diablo Canyon Power Plant (“Diablo Canyon”), and removal costs associated with the replacement of old electromechanical meters with SmartMeter devices. “Other” also consisted of costs that the Utility incurred in terminating a 30-year power purchase agreement, which are being amortized and collected in rates through September 2014, as well as costs incurred in relation to the Utility’s plan of reorganization under Chapter 11 that became effective in April 2004.

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

Regulatory Liabilities

Current Regulatory Liabilities

At June 30, 2010 and December 31, 2009, the Utility had current regulatory liabilities of $81 million and $163 million, respectively, primarily consisting of the amounts that the Utility expects to refund to customers for over-collected electric transmission rates and the current portion of price risk management regulatory liabilities. Price risk management regulatory liabilities represent the deferral of unrealized gains related to price risk management derivative instruments with terms of one year or less. 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)	June 30, 2010		December 31, 2009
Cost of removal obligation	$	3,112	$	2,933
Public purpose programs		604		508
Recoveries in excess of ARO		433		488
Other		126		196

Total long-term regulatory liabilities	$	4,275	$	4,125

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 public purpose programs represents amounts received from customers designated for public purpose program costs that are expected to be incurred in the future. For example, these regulatory liabilities include revenues collected from customers to pay for costs that the Utility expects to incur in the future under the California Solar Initiative to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties.

The regulatory liability for recoveries in excess of ARO represents differences between amounts collected in rates for decommissioning the Utility’s nuclear power facilities and the ARO expenses recorded in accordance with GAAP. 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.

“Other” at June 30, 2010 and December 31, 2009 included the deferral of unrealized gains related to price risk management derivative instruments with terms in excess of one year, the gain associated with the Utility’s acquisition of the permits and other assets related to the Gateway Generating Station as part of a settlement that the Utility entered into with Mirant Corporation, and insurance recoveries for hazardous substance remediation.

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)	June 30, 2010			December 31, 2009
Utility generation	$	542		$	355
Distribution revenue adjustment mechanism		319			152
Public purpose programs		71			83
Gas fixed cost		13			93
Energy procurement costs		(12	)		128
Electric transmission		(39	)		114
Energy recovery bonds		(163	)		(185	)
Other		201			88

Total regulatory balancing accounts, net	$	932		$	828

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 periods of more temperate weather, there is generally an under-collection in this balancing account due to lower electricity sales and lower rates. During the warmer months of summer, there is generally an over-collection due to higher rates and electric usage that cause an increase in generation revenues.

The public purpose programs balancing accounts primarily track the recovery of the authorized public purpose program revenue requirements, the actual costs of such programs, 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 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. The under-collected or over-collected position of this account is dependent on seasonality and volatility in gas volumes.

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 electric transmission balancing accounts represent the difference between electric transmission wheeling revenues received by the Utility from the California Independent System Operator (“CAISO”) (on behalf of electric transmission customers) and refunds of those revenues to customers, the pass-through of transition access charge and credits for high voltage transmission, reliability service charges, and interest accrued on these account balances. In addition, these balancing accounts include the end-user customer refund balancing account, which is used to refund to customers over-collected electric transmission revenues.

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 June 30, 2010 and December 31, 2009, “other” included the California Department of Water Resources (“DWR”) power charge collection balancing account, which ensures amounts collected from customers for DWR-delivered power are remitted to the DWR; balancing accounts that track recovery of the authorized revenue requirements and costs related to the SmartMeter^TM advanced metering project; and balancing accounts that track recoverable hazardous substance clean-up costs incurred by the Utility.

NOTE 4: DEBT

PG&E Corporation

Convertible Subordinated Notes

PG&E Corporation issued 16,370,779 shares of common stock upon conversion of the $247 million principal amount of PG&E Corporation’s 9.50% Convertible Subordinated Notes at a conversion price of $15.09 per share between June 23 and June 29, 2010. These notes were no longer outstanding at June 30, 2010.

In addition to conversion rights, the holders of the Convertible Subordinated Notes were entitled to receive “pass-through dividends” determined by multiplying the cash dividend paid by PG&E Corporation per share of common stock by a number equal to the principal amount of the Convertible Subordinated Notes divided by the conversion price. In the six months ended June 30, 2010, PG&E Corporation paid $14 million of pass-through dividends. The payment of pass-through dividends is recognized as an operating cash flow in PG&E Corporation’s Condensed Consolidated Statement of Cash Flows. Changes in the fair value of the dividend participation rights, which are treated as a derivative, are recognized in PG&E Corporation’s Condensed Consolidated Statement of Income as a non-operating expense or income. (See Note 7 below for further discussion of these instruments.)

Credit Facilities

At June 30, 2010, PG&E Corporation had $30 million of cash borrowings outstanding under its $187 million revolving credit facility which had an average interest rate of 0.70%.

Utility

Senior Notes

On April 1, 2010, the Utility issued $250 million principal amount of 5.8% Senior Notes due March 1, 2037.

Pollution Control Bonds

On April 8, 2010, the California Infrastructure and Economic Development Bank issued $50 million of tax-exempt pollution control bonds series 2010E due on November 1, 2026 and loaned the proceeds to the Utility. The proceeds were used to refund the corresponding related series of pollution control bonds issued in 2005 which were repurchased by the Utility in 2008. The series 2010E bonds bear interest at 2.25% per year through April 1, 2012 and are subject to mandatory tender on April 2, 2012 at a price of 100% of the principal amount plus accrued interest. Thereafter, this series of bonds may be remarketed in a fixed or variable rate mode. Interest is payable semi-annually in arrears on April 1 and October 1.

Credit Facilities and Short-Term Borrowings

On June 8, 2010, the Utility entered into a $750 million unsecured revolving credit agreement with a syndicate of lenders. Of the total credit capacity, $500 million was used to replace the $500 million Floating Rate Senior Notes that matured on June 10, 2010. The aggregate facility of $750 million includes a $75 million commitment for swingline loans, or loans that are made available on a same-day basis and are repayable in full within 30 days. The Utility can, at any time, repay amounts outstanding in whole or in part. The credit agreement expires on February 26, 2012, unless extended for additional periods at the Utility’s request and at the sole discretion of each lender. The Utility has the right to increase, in one or more requests given no more than once a year, the aggregate facility by up to $250 million, provided certain conditions are met.

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

The credit agreement contains covenants that are substantially similar to the covenants contained in the Utility’s existing $1.9 billion credit facility, and are usual and customary for credit facilities of this type. Both 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.

At June 30, 2010, the Utility had no cash borrowings outstanding under its $1.9 billion and $750 million revolving credit facilities.

At June 30, 2010, the Utility had $256 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 June 30, 2010, the Utility had $1.0 billion of commercial paper outstanding at an average yield of 0.45%.

Energy Recovery Bonds

In 2005, PERF, a wholly owned consolidated subsidiary of the Utility, 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 $1.0 billion at June 30, 2010.

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 six months ended June 30, 2010 were as follows:


	PG&E Corporation			Utility
(in millions)	Total Equity			Total Shareholders’ Equity
Balance at December 31, 2009	$	10,585		$	11,185
Net income		598			603
Common stock issued		342			—
Share-based compensation expense		22			—
Common stock dividends declared		(347	)		(358	)
Preferred stock dividend requirement		—			(7	)
Preferred stock dividend requirement of subsidiary		(7	)		—
Tax benefit from employee stock plans		2			1
Other comprehensive income		(72	)		(72	)
Equity contribution		—			130

Balance at June 30, 2010	$	11,123		$	11,482

During the six months ended June 30, 2010, PG&E Corporation issued 16,370,779 shares of common stock upon conversion of the $247 million principal amount of PG&E Corporation’s Convertible Subordinated Notes. In addition, PG&E Corporation issued 2,340,451 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 six months ended June 30, 2010, PG&E Corporation contributed equity of $130 million to the Utility in order to maintain the 52% common equity target 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, cumulative adjustments for employee benefit plans, net of tax, are included in accumulated other comprehensive income.


	PG&E Corporation
	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2010		2009		2010			2009
Net income	$	337	$	392	$	598		$	636
Employee benefit plan adjustment, net of tax⁽¹⁾		8		7		(72	)		14

Comprehensive income	$	345	$	399	$	526		$	650

⁽¹⁾

These balances are net of income tax expense of $6 million and $5 million for the three months ended June 30, 2010 and 2009, respectively. For the six months ended June 30, 2010, the income tax benefit was $49 million and for the six months ended June 30, 2009, the income tax expense was $9 million.


	Utility
	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2010		2009		2010			2009
Net income	$	339	$	391	$	603		$	630
Employee benefit plan adjustment, net of tax⁽¹⁾		8		7		(72	)		14

Comprehensive income	$	347	$	398	$	531		$	644

⁽¹⁾

Dividends

During the six months ended June 30, 2010, PG&E Corporation paid common stock dividends totaling $320 million, net of $6 million that was reinvested in additional shares of common stock by participants in the Dividend Reinvestment and Stock Purchase Plan. On June 16, 2010, the Board of Directors of PG&E Corporation declared dividends of $0.455 per share, totaling $178 million, which were paid on July 15, 2010 to shareholders on record as of June 30, 2010.

During the six months ended June 30, 2010, the Utility paid common stock dividends totaling $358 million to PG&E Corporation.

During the six months ended June 30, 2010, the Utility paid dividends totaling $7 million to holders of its outstanding series of preferred stock. On June 16, 2010, the Board of Directors of the Utility declared dividends totaling $4 million on its outstanding series of preferred stock, payable on August 15, 2010, to shareholders on record as of July 30, 2010.

NOTE 6: EARNINGS PER SHARE

Earnings per common share (“EPS”) is calculated utilizing the “two-class” method, dividing the sum of distributed earnings to common shareholders and undistributed earnings allocated to common shareholders by the weighted average number of common shares outstanding during the period. In applying the two-class method, undistributed earnings are allocated to both common shares and participating securities. PG&E Corporation’s Convertible Subordinated Notes met the criteria of participating securities as the holders were entitled to receive pass-through dividends on a 1:1 basis with shares of common stock.

As of June 30, 2010, all of PG&E Corporation’s Convertible Subordinated Notes have been converted into common stock. (See Note 4 above for further discussion.)

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 June 30,				Six Months Ended June 30,
(in millions, except per share amounts)	2010		2009		2010		2009
*Basic*
Income available for common shareholders	$	333	$	388	$	591	$	629
Less: distributed earnings to common shareholders		178		155		347		309

Undistributed earnings	$	155	$	233	$	244	$	320

Allocation of undistributed earnings to common shareholders
Distributed earnings to common shareholders	$	178	$	155	$	347	$	309
Undistributed earnings allocated to common shareholders		149		223		234		306

Total common shareholders earnings	$	327	$	378	$	581	$	615

Weighted average common shares outstanding, basic		373		368		372		366
Convertible subordinated notes		15		17		16		17

Weighted average common shares outstanding and participating securities		388		385		388		383

Net earnings per common share, basic
Distributed earnings, basic ⁽¹⁾	$	0.48	$	0.42	$	0.93	$	0.84
Undistributed earnings, basic		0.40		0.61		0.63		0.84

Total	$	0.88	$	1.03	$	1.56	$	1.68

⁽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 “if-converted” method to reflect the dilutive effect of the Convertible Subordinated Notes to the extent that the impact is dilutive when compared to basic EPS. In addition, PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS.

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


(in millions, except per share amounts)	Three Months Ended June 30, 2010		Six Months Ended June 30, 2010
*Diluted*
Income available for common shareholders	$	333	$	591
Add earnings impact of assumed conversion of participating securities:
Interest expense on convertible subordinated notes, net of tax		4		8

Income available for common shareholders and assumed conversion	$	337	$	599


Weighted average common shares outstanding, basic		373		372
Add incremental shares from assumed conversions:
Convertible subordinated notes		15		16
Employee share-based compensation		2		1

Weighted average common shares outstanding, diluted		390		389

Total earnings per common share, diluted	$	0.86	$	1.54


(in millions, except per share amounts)	Three Months Ended June 30, 2009		Six Months Ended June 30, 2009
*Diluted*
Income available for common shareholders	$	388	$	629
Less: distributed earnings to common shareholders		155		309

Undistributed earnings	$	233	$	320


Allocation of undistributed earnings to common shareholders
Distributed earnings to common shareholders	$	155	$	309
Undistributed earnings allocated to common shareholders		223		306

Total common shareholders earnings	$	378	$	615


Weighted average common shares outstanding, basic		368		366
Convertible subordinated notes		17		17

Weighted average common shares outstanding and participating securities, basic		385		383

Weighted average common shares outstanding, basic		368		366
Employee share-based compensation		1		1

Weighted average common shares outstanding, diluted		369		367
Convertible subordinated notes		17		17

Weighted average common shares outstanding and participating securities, diluted		386		384

Net earnings per common share, diluted
Distributed earnings, diluted	$	0.42	$	0.84
Undistributed earnings, diluted		0.60		0.83

Total earnings per common share, diluted	$	1.02	$	1.67

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 faces market risk primarily related to electricity and natural gas commodity prices. All of the Utility’s risk management activities involving derivatives occur to reduce the volatility of commodity costs on behalf of its customers. The CPUC and the FERC allow 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. As these costs are passed through to customers in rates, the Utility’s earnings are not exposed to the commodity price risk inherent in the purchase and sale of 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;

•

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

•

futures contracts that are exchange-traded contracts committing the Utility to make a cash settlement at a specified price and future date.

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

Commodity-Related Price Risk

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.

The following is a discussion of the Utility’s use of derivative instruments intended to mitigate commodity-related price risk for its customers.

Electricity Procurement

The Utility obtains electricity from a diverse mix of resources, including third-party power purchase agreements, amounts allocated under DWR contracts, and its own electricity generation facilities. The amount of electricity the Utility needs to meet the demands of customers and that is not satisfied from the Utility’s own generation facilities, existing purchase contracts, or DWR contracts allocated to the Utility’s 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;

•

fluctuation in the output of hydroelectric and other renewable power 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; and

•

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

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 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 CAISO implemented its new day-ahead wholesale electricity market as part of its Market Redesign and Technology Upgrade on April 1, 2009. The CAISO created congestion revenue rights (“CRRs”) to allow market participants, including load-serving entities, to hedge the financial risk of CAISO-imposed congestion charges in the new 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 CRRs held by the Utility are considered derivative instruments.

Natural Gas Procurement (Electric 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 futures, 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 (Small Commercial and Residential Customers)

The Utility enters into physical natural gas commodity contracts to fulfill the needs of its small commercial and residential, or “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 markets 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

Other Risk

PG&E Corporation issued 16,370,779 shares of common stock upon conversion of the $247 million principal amount of PG&E Corporation’s Convertible Subordinated Notes at a conversion price of $15.09 per share. Prior to conversion, the holders of the Convertible Subordinated Notes were entitled to receive “pass-through dividends” determined by multiplying the cash dividend paid by PG&E Corporation per share of common stock by a number equal to the principal amount of the Convertible Subordinated Notes divided by the conversion prices. These “pass-through dividends” were classified as embedded derivative instruments and bifurcated from the Convertible Subordinated Notes and recorded at fair value in PG&E Corporation’s Condensed Consolidated Financial Statements. Upon conversion of the notes, the dividend participation rights ceased to exist. For the six months ended June 30, 2010, PG&E Corporation paid $14 million of pass-through dividends associated with the Convertible Subordinated Notes. (See Note 4 above for further information.)

Volume of Derivative Activity

At June 30, 2010, the volume 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, Futures, and Swaps	366,497,007	254,825,476	15,180,000	—
	Options	222,787,080	142,750,000	15,600,000	—
Electricity (Megawatt-hours)	Forwards, Futures, and Swaps	5,059,221	8,305,259	4,446,487	5,388,528
	Options	628,718	—	196,632	463,860
	Congestion Revenue Rights	59,215,388	67,233,474	67,167,528	103,387,526

⁽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 2015 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 June 30, 2010, 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 Utility)
Current assets – prepaid expenses and other	$	30		$	(18	)	$	49	$	61
Other noncurrent assets – other		81			(62	)		65		84
Current liabilities – other		(342	)		18			147		(177	)
Noncurrent liabilities – other		(521	)		62			129		(330	)

Total commodity risk	$	(752	)	$	—		$	390	$	(362	)

⁽¹⁾	See Note 8 below for a discussion of the valuation techniques used to calculate the fair value of these instruments.

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

At December 31, 2009, 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 Utility)
Current assets – prepaid expenses and other	$	76		$	(12	)	$	77	$	141
Other noncurrent assets – other		64			(44	)		13		33
Current liabilities – other		(231	)		12			54		(165	)
Noncurrent liabilities – other		(390	)		44			44		(302	)

Total commodity risk	$	(481	)	$	—		$	188	$	(293	)

Other Risk Instruments ⁽²⁾ (PG&E Corporation Only)
Current liabilities – other	$	(13	)	$	—		$	—	$	(13	)

Total derivatives	$	(494	)	$	—		$	188	$	(306	)

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

⁽²⁾	This category relates to the dividend participation rights of PG&E Corporation’s Convertible Subordinated Notes, which were fully converted as of June 30, 2010.

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


	Commodity Risk (PG&E Corporation and Utility)
	Three months ended June 30,						Six months ended June 30,
(in millions)	2010			2009			2010			2009
Unrealized gain/(loss) - regulatory assets and liabilities ⁽¹⁾	$	18		$	147		$	(271	)	$	(160	)
Realized gain/(loss) - cost of electricity ⁽²⁾		(175	)		(223	)		(281	)		(425	)
Realized gain/(loss) - cost of natural gas ⁽²⁾		(5	)		(6	)		(44	)		(29	)

Total commodity risk instruments	$	(162	)	$	(82	)	$	(596	)	$	(614	)

⁽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 recognized in operating cash flows on PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Cash Flows.

The majority of the Utility’s commodity risk-related derivative instruments contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. 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 June 30, 2010, the additional cash collateral the Utility would be required to post if its credit-risk-related contingent features were triggered was as follows:


(in millions)
Derivatives in a liability position with credit-risk-related contingencies that are not fully collateralized	$	(708	)
Related derivatives in an asset position		78
Collateral posting in the normal course of business related to these derivatives		204

Net position of derivative contracts/additional collateral posting requirements ⁽¹⁾	$	(426	)

⁽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—Include 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 also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. (See Note 11 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report for further discussion of fair value measurements.)

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 June 30, 2010


(in millions)	Level 1		Level 2		Level 3		Total
Assets:
Money market investments	$	204	$	—	$	—	$	204

Nuclear decommissioning trusts
U.S. equity securities ⁽¹⁾		706		20		—		726
Non-U.S. equity securities		282		—		—		282
U.S. government and agency securities		720		58		—		778
Municipal securities		5		87		—		92
Other fixed income securities		—		79		—		79

Total nuclear decommissioning trusts ⁽²⁾		1,713		244		—		1,957

Price risk management instruments
Electric ⁽³⁾		74		—		—		74

Total price risk management instruments		74		—		—		74

Rabbi trusts
Equity securities		23		—		—		23
Life insurance contracts		—		64		—		64

Total rabbi trusts		23		64		—		87

Long-term disability trust
U.S. equity securities ⁽¹⁾		3		23		—		26
Corporate debt securities ⁽¹⁾		—		142		—		142

Total long-term disability trust		3		165		—		168

Total assets	$	2,017	$	473	$	—	$	2,490

Liabilities:
Price risk management instruments
Electric ⁽⁴⁾		—		35		358		393
Gas ⁽⁵⁾		—		1		42		43

Total price risk management instruments		—		36		400		436

Other liabilities		—		—		2		2

Total liabilities	$	—	$	36	$	402	$	438

⁽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 deferred taxes on appreciation of investment value.

⁽³⁾	Balances include the impact of netting adjustments of $280 million to Level 1. Includes natural gas for electric portfolio.

⁽⁴⁾	Balances include the impact of netting adjustments of $43 million to Level 2, and $33 million to Level 3. Includes natural gas for electric portfolio.

⁽⁵⁾	Balances include the impact of netting adjustments of $34 million to Level 3. Includes natural gas for core customers.

Fair Value Measurements at December 31, 2009


(in millions)	Level 1		Level 2		Level 3		Total
Assets:
Money market investments	$	189	$	—	$	4	$	193

Nuclear decommissioning trusts
U.S. equity securities ⁽¹⁾		762		6		—		768
Non-U.S. equity securities		344		—		—		344
U.S. government and agency securities		653		51		—		704
Municipal securities		1		89		—		90
Other fixed income securities		—		108		—		108

Total nuclear decommissioning trusts ⁽²⁾		1,760		254		—		2,014

Rabbi trusts
Equity securities		21		—		—		21
Life insurance contracts		60		—		—		60

Total rabbi trusts		81		—		—		81

Long-term disability trust
U.S. equity securities ⁽¹⁾		52		23		—		75
Corporate debt securities ⁽¹⁾		—		113		—		113

Total long-term disability trust		52		136		—		188

Total assets	$	2,082	$	390	$	4	$	2,476

Liabilities:
Dividend participation rights	$	—	$	—	$	12	$	12

Price risk management instruments
Electric ⁽³⁾		2		73		157		232
Gas ⁽⁴⁾		1		—		60		61

Total price risk management instruments		3		73		217		293

Other liabilities		—		—		3		3

Total liabilities	$	3	$	73	$	232	$	308

⁽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 taxes on appreciation of investment value.

⁽³⁾	Balances include the impact of netting adjustments of $108 million to Level 1, $48 million to Level 2, and $19 million to Level 3. Includes natural gas for electric portfolio.

⁽⁴⁾	Balances include the impact of netting adjustments of $13 million to Level 3. Includes natural gas for core customers.

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. Equity securities primarily include investments in common stock and commingled funds comprised of equity across multiple industry sectors in the U.S. and other regions of the world. Debt securities are comprised primarily of fixed income securities that include U.S. government and agency securities, municipal securities, and corporate debt securities. Equity securities and debt securities are generally valued based on unadjusted prices in active markets for identical transactions or unadjusted prices in active markets for similar transactions. A market based valuation approach is generally used to estimate the fair value of debt securities classified as Level 2 instruments in the tables above. 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. No trust assets were measured at fair value using significant unobservable inputs (Level 3) at June 30, 2010.

Price Risk Management Instruments

Price risk management instruments are composed of physical and financial derivative contracts, including futures, forwards, swaps, options, and CRRs that are exchange-traded or over-the-counter traded contracts. Futures, forwards, and swaps are valued using observable market prices for the underlying commodity or an identical instrument. As observable market prices are available, these instruments are classified as Level 1 or Level 2 instruments.

Certain exchange-traded contracts are classified as Level 2 measurements because the contract term extends to a point at which the market is no longer considered active but where prices are still observable. This determination is based on an analysis of the relevant characteristics of the market such as trading hours and volumes, frequency of available quotes, and open interest. In addition, a number of over the counter contracts have been valued using unadjusted exchange prices of similar instruments in active markets. Such instruments are classified as Level 2 measurements as they are not exchange-traded instruments.

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. Some of these assumptions are derived from internal models as they are unobservable. The Utility’s demand response contracts with third-party aggregators of retail electricity customers contain a call option entitling the Utility to require that the aggregator reduce electric usage by the aggregator’s customers at times of peak energy demand or in response to a CAISO alert or other emergency.

The Utility holds CRRs to hedge financial risk of CAISO-imposed congestion charges in the day-ahead markets. CRRs are valued based on the forecasted settlement price at the delivery points underlying the CRR using internal models. The Utility also uses the most current annual auction prices published by the CAISO to calibrate internal models. Limited market data is available between auction dates; therefore, CRRs are classified as Level 3 measurements.

The Utility enters into power purchase agreements for the purchase of electricity to meet the demand of its customers. Certain power purchase agreements meet the definition of a derivative instrument. Some of these power purchase agreements do not qualify as normal purchases and sales, therefore, the fair value of these power purchase agreements are recorded on the Condensed Consolidated Balance Sheets. The Utility uses internal models to determine the fair value of these power purchase agreements. These power purchase agreements include contract terms that extend beyond the point for which an active market exists. The Utility utilizes market data for the underlying commodity to the extent that it is available in determining the fair value. For periods where market data is not available, the Utility extrapolates forward prices based on historical data. These power purchase agreements are considered Level 3 instruments as the determination of their fair value includes the use of unobservable forward prices.

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 six month period ended June 30, 2010. The following tables present reconciliations for assets and liabilities measured and recorded at fair value on a recurring basis, using significant unobservable inputs (Level 3), for the three and six month periods ended June 30, 2010 and 2009:


	PG&E Corporation Only					PG&E Corporation and the Utility
(in millions)	Money Market		Dividend Participation Rights			Price Risk Management Instruments			Nuclear Decommission- ing Trusts Equity Securities ⁽¹⁾		Long- Term Disability Equity Securities		Long-Term Disability Corp. Debt Securities		Other Liabilities			Total
Asset (liability) balance as of March 31, 2010	$	—	$	(7	)	$	(336	)	$	—	$	—	$	—	$	(1	)	$	(344	)
Realized and unrealized gains (losses):
Included in earnings		—		—			—			—		—		—		—			—
Included in regulatory assets and liabilities or balancing accounts		—		—			(64	)		—		—		—		(1	)		(65	)
Purchases, issuances, and settlements		—		7			—			—		—		—		—			7
Transfers into Level 3		—		—			—			—		—		—		—			—
Transfers out of Level 3		—		—			—			—		—		—		—			—
Asset (liability) balance as of June 30, 2010	$	—	$	—		$	(400	)	$	—	$	—	$	—	$	(2	)	$	(402	)

⁽¹⁾	Excludes deferred taxes on appreciation of investment value.


	PG&E Corporation Only						PG&E Corporation and the Utility
(in millions)	Money Market			Dividend Participation Rights			Price Risk Management Instruments			Nuclear Decommission- ing Trusts Equity Securities ⁽¹⁾		Long- Term Disability Equity Securities		Long-Term Disability Corp. Debt Securities		Other Liabilities			Total
Asset (liability) balance as of March 31, 2009	$	8		$	(33	)	$	(176	)	$	4	$	47	$	24	$	(1	)	$	(127	)

Realized and unrealized gains (losses):
Included in earnings		—			(1	)		—			—		10		—		—			9
Included in regulatory assets and liabilities or balancing accounts		—			—			(13	)		1		—		—		(2	)		(14	)
Purchases, issuances, and settlements		(3	)		7			—			—		—		—		—			4
Transfers into Level 3		—			—			—			—		—		—		—			—
Transfers out of Level 3		—			—			—			—		—		—		—			—

Asset (liability) balance as of June 30, 2009	$	5		$	(27	)	$	(189	)	$	5	$	57	$	24	$	(3	)	$	(128	)

⁽¹⁾	Excludes deferred taxes on appreciation of investment value.


	PG&E Corporation Only						PG&E Corporation and the Utility
(in millions)	Money Market			Dividend Participation Rights			Price Risk Management Instruments			Nuclear Decommission- ing Trusts Equity Securities ⁽¹⁾		Long- Term Disability Equity Securities		Long-Term Disability Corp. Debt Securities		Other Liabilities			Total
Asset (liability) balance as of December 31, 2009	$	4		$	(12	)	$	(217	)	$	—	$	—	$	—	$	(3	)	$	(228	)

Realized and unrealized gains (losses):
Included in earnings		—			—			—			—		—		—		—			—
Included in regulatory assets and liabilities or balancing accounts		—			—			(183	)		—		—		—		1			(182	)
Purchases, issuances, and settlements		(4	)		12			—			—		—		—		—			8
Transfers into Level 3		—			—			—			—		—		—		—			—
Transfers out of Level 3		—			—			—			—		—		—		—			—

Asset (liability) balance as of June 30, 2010	$	—		$	—		$	(400	)	$	—	$	—	$	—	$	(2	)	$	(402	)

⁽¹⁾	Excludes deferred taxes on appreciation of investment value.


	PG&E Corporation Only						PG&E Corporation and the Utility
(in millions)	Money Market			Dividend Participation Rights			Price Risk Management Instruments			Nuclear Decommission- ing Trusts Equity Securities ⁽¹⁾		Long- Term Disability Equity Securities		Long-Term Disability Corp. Debt Securities		Other Liabilities			Total
Asset (liability) balance as of December 31, 2008	$	12		$	(42	)	$	(156	)	$	5	$	54	$	24	$	(2	)	$	(105	)

Realized and unrealized gains (losses):
Included in earnings		—			1			—			—		3		—		—			4
Included in regulatory assets and liabilities or balancing accounts		—			—			(33	)		—		—		—		(1	)		(34	)
Purchases, issuances, and settlements		(7	)		14			—			—		—		—		—			7
Transfers into Level 3		—			—			—			—		—		—		—			—
Transfers out of Level 3		—			—			—			—		—		—		—			—

Asset (liability) balance as of June 30, 2009	$	5		$	(27	)	$	(189	)	$	5	$	57	$	24	$	(3	)	$	(128	)

⁽¹⁾	Excludes deferred taxes on appreciation of investment value.

Financial Instruments

The Utility values its long-term debt using quoted market prices that are readily available. The carrying amount and fair value of PG&E Corporation’s and the Utility’s financial instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):


	At June 30,				At December 31,
	2010				2009
(in millions)	Carrying Amount		Fair Value⁽²⁾		Carrying Amount		Fair Value⁽²⁾
Debt (Note 4):
PG&E Corporation ⁽¹⁾	$	—	$	—	$	597	$	1,096
Utility		9,540		10,553		9,240		9,824
Energy recovery bonds		1,031		1,171		1,213		1,269

⁽¹⁾	PG&E Corporation Convertible Subordinated Notes were no longer outstanding as of June 30, 2010.

⁽²⁾	Fair values are determined using readily available quoted market prices.

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 summarizes unrealized gains and losses related to available-for-sale investments held in the Utility’s nuclear decommissioning trusts:


	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Estimated ⁽¹⁾ Fair Value
(in millions)
As of June 30, 2010
U.S. equity securities	$	360	$	371	$	(5	)	$	726
Non-U.S. equity securities		177		109		(4	)		282
U.S. government and agency securities		698		80		—			778
Municipal securities		91		2		(1	)		92
Other fixed income securities		77		2		—			79

Total	$	1,403	$	564	$	(10	)	$	1,957

As of December 31, 2009
U.S. equity securities	$	344	$	425	$	(1	)	$	768
Non-U.S. equity securities		182		163		(1	)		344
U.S. government and agency securities		656		52		(4	)		704
Municipal securities		89		1		—			90
Other fixed income securities		108		2		(2	)		108

Total	$	1,379	$	643	$	(8	)	$	2,014

⁽¹⁾	Excludes taxes on appreciation of investment value.

The following table summarizes the estimated fair value of debt securities classified by the contractual maturity date of the security:


	At June 30,
	2010
(in millions)
Less than 1 year	$	40
1–5 years		424
5–10 years		248
More than 10 years		237

Total maturities of debt securities	$	949

The following table provides a summary of activity for available-for-sale securities:


	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009
(in millions)
Proceeds received from sales of securities	$	348		$	567		$	685		$	954
Gross realized gains on sales of securities held as available-for-sale		7			4			22			12
Gross realized losses on sales of securities held as available-for-sale		(1	)		(16	)		(6	)		(50	)

In general, investments held in the nuclear decommissioning trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. It is reasonably possible that changes in the market values of investment securities could occur in the near term, and such changes could materially affect the trusts’ fair value.

NOTE 9: RELATED PARTY AGREEMENTS AND TRANSACTIONS

The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services. Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services. PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies. Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.

The Utility’s significant related party transactions were as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in millions)	2010		2009		2010		2009
Utility revenues from:
Administrative services provided to PG&E Corporation	$	2	$	1	$	3	$	2
Utility expenses from:
Administrative services received from PG&E Corporation	$	9	$	14	$	25	$	33
Utility employee benefit due to PG&E Corporation		5		3		15		9

At June 30, 2010 and December 31, 2009, the Utility had a receivable of $60 million and $26 million, respectively, from PG&E Corporation included in accounts receivable – other and other noncurrent assets – other on the Utility’s Condensed Consolidated Balance Sheets, and a payable of $12 million and $16 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Condensed Consolidated Balance Sheets.

NOTE 10: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

Various electricity suppliers filed claims in the Utility’s proceeding under Chapter 11 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 June 30, 2010 and December 31, 2009, the Utility held $512 million and $515 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 credited to customers.

The following table presents the changes in the remaining disputed claims liability and interest accrued from December 31, 2009 to June 30, 2010:


(in millions)
Balance at December 31, 2009	$	946
Interest accrued		15
Less: supplier settlements		(41	)

Balance at June 30, 2010	$	920

At June 30, 2010, the Utility’s net disputed claims liability was $920 million, consisting of $746 million of remaining disputed claims (classified on the Condensed Consolidated Balance Sheets within accounts payable – disputed claims and customer refunds) and interest accrued at the FERC-ordered rate of $668 million (classified on the Condensed Consolidated Balance Sheets within interest payable) partially offset by accounts receivable from the CAISO and the PX of $494 million (classified on the Condensed Consolidated Balance Sheets within accounts receivable – other).

Interest accrues on the 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 11: 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 June 30, 2010, the undiscounted future expected power purchase agreement payments were as follows:


(in millions)
2010	$	1,202
2011		2,329
2012		2,466
2013		2,726
2014		2,739
Thereafter		44,625

Total	$	56,087

Payments made by the Utility under power purchase agreements amounted to $1,094 million and $1,154 million for the six months ended June 30, 2010 and June 30, 2009, respectively. The amounts above do not include payments related to the DWR purchases for the benefit of the Utility’s customers, as the Utility only acts as an agent for the DWR.

Some of the power purchase agreements that the Utility entered into with independent power producers that are qualifying facilities (“QF”s) are treated as capital leases. The following table shows the future fixed capacity payments due under the QF contracts that are treated as capital leases. (These amounts are also included in the table above.) The fixed capacity payments are discounted to their present value using the Utility’s incremental borrowing rate at the inception of the leases. The amount of this discount is shown as the amount representing interest.


(in millions)
2010	$	29
2011		50
2012		50
2013		50
2014		42
Thereafter		162

Total fixed capacity payments		383
Amount representing interest		81

Present value of fixed capacity payments	$	302

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 Utility’s recognition of the lease expense conforms to the ratemaking treatment for the Utility’s recovery of the cost of electricity. The QF contracts that are treated as capital leases expire between April 2014 and September 2021.

At June 30, 2010 and December 31, 2009, PG&E Corporation and the Utility had, respectively, $33 million and $32 million included in current liabilities – other, and $269 million and $282 million included in noncurrent liabilities – other, respectively, representing the present value of the fixed capacity payments due under these contracts recorded on PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. The corresponding assets at June 30, 2010 and December 31, 2009 of $302 million and $314 million, including amortization of $106 million and $94 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. The contract lengths and natural gas sources of the Utility’s portfolio of natural gas procurement contracts can fluctuate based on market conditions. The Utility also contracts for natural gas transportation to transport natural gas from the points at which the Utility takes delivery (typically in Canada and the southwestern United States supply basins) to the points at which the Utility’s natural gas transportation system begins. In addition, the Utility has contracted for gas storage services in its market area in order to better meet winter peak customer loads.

The Utility also purchases natural gas to fuel its owned-generation facilities. Contract terms typically range in length from one to three years.

At June 30, 2010, the Utility’s undiscounted obligations for natural gas purchases, gas transportation services, and gas storage were as follows:


(in millions)
2010	$	443
2011		455
2012		78
2013		59
2014		44
Thereafter		115

Total ⁽¹⁾	$	1,194

⁽¹⁾	Total does not include Ruby Pipeline reservation cost commitment described below.

Payments for natural gas purchases, gas transportation services, and gas storage amounted to $912 million and $737 million for the six months ended June 30, 2010 and June 30, 2009, respectively.

Ruby Pipeline

On April 5, 2010, the FERC issued an order authorizing El Paso Corporation to construct, operate, and maintain its proposed 675-mile gas transmission pipeline (“Ruby Pipeline”), which would begin at the Opal Hub in Wyoming and terminate at the Malin, Oregon, interconnect, near California’s northern border and have an initial capacity of 1.5 billion cubic feet per day. Construction of the project is scheduled to begin in the third quarter of 2010, and the facilities are scheduled to be in service in the spring of 2011. The Utility has contracted for firm service rights on the Ruby Pipeline of approximately 0.4 billion cubic feet per day beginning in 2011. Under these agreements the Utility will have a cumulative commitment of $1.4 billion over 15 years.

Nuclear Fuel Agreements

The Utility has entered into several purchase agreements for nuclear fuel. These agreements have terms ranging from 1 to 16 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 2014, while contracts for fuel fabrication services provide for 100% coverage of reactor requirements through 2011. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.

At June 30, 2010, the undiscounted obligations under nuclear fuel agreements were as follows:


(in millions)
2010	$	58
2011		82
2012		69
2013		107
2014		135
Thereafter		1,215

Total	$	1,666

Payments for nuclear fuel amounted to $95 million and $61 million for the six months ended June 30, 2010 and June 30, 2009, respectively.

Contingencies

PG&E Corporation

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

The CPUC has established a ratemaking mechanism to provide incentives to the California investor-owned utilities to meet the CPUC’s energy savings goals through implementation of the utilities’ 2006-2008 energy efficiency programs. In accordance with this mechanism, the CPUC has awarded the Utility interim incentive revenues totaling $75 million through December 31, 2009 based on the energy savings achieved through implementation of the Utility’s energy efficiency programs during the 2006 through 2008 program cycle. The amount of additional incentive revenues the Utility may earn, if any, is subject to the CPUC’s completion of the final true-up process. In April 2010, the assigned CPUC commissioner directed the parties to hold settlement discussions in an effort to agree on the 2010 final true-up amounts. The CPUC commissioner also directed the Energy Division to calculate various true-up amounts based on a range of possible scenarios that use different assumptions about energy savings, goals, and costs, noting that the CPUC can consider alternative approaches to calculate the final true-up amounts instead of relying solely on the Energy Division’s evaluation of the final energy savings over the 2006-2008 program cycle.

On May 4, 2010, the Energy Division released various scenarios of additional incentive amounts using data from the Energy Division’s draft evaluation report released on April 15, 2010. The calculation scenarios for the Utility range from a penalty of $75 million, based on a scenario using the Energy Division’s evaluated results, to a reward of $105 million. The Energy Division’s draft report did not include the scenario jointly proposed by the utilities. On July 9, 2010, the Energy Division released its final evaluation report and updated the results of its scenario calculations. The range of possible final true-up amounts contained in the final scenario report are substantially the same as the amounts contained in the scenario report released in May 2010. On July 16, 2010, the utilities submitted data to the CPUC to support the utilities’ joint scenario using the verified results in the Energy Division’s final evaluation report. Based on this scenario, the Utility would be entitled to additional incentive revenues of approximately $63 million.

The CPUC is scheduled to issue a final decision to complete the true-up process by the end of 2010. PG&E Corporation and the Utility are unable to predict the amount, if any, of additional incentive revenues or penalties the Utility may be assessed 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.

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 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 is still pending in the U.S. Court of Appeals for the Ninth Circuit. The appellants claim that the NRC failed to adequately consider environmental impacts of a potential terrorist attack at Diablo Canyon. The Ninth Circuit has set November 4, 2010 as the date for oral argument.

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 Utility incurred approximately $188 million between 2005 and 2009 to build on-site storage facilities. The Utility will also seek to recover these costs from the DOE. 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 $40 million per one-year policy term.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants that have been “certified” by the Secretary of the Treasury. For a certified act of terrorism, NEIL can obtain compensation from the federal government and will provide up to the full policy limits to the Utility for an insured loss. If one or more non-certified acts of terrorism cause property damage 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 $3.2 billion within a 12-month period plus the additional amounts recovered by NEIL for these losses from reinsurance.

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 an 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.

Environmental Matters

The Utility may be required to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party under environmental laws. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances at former manufactured gas plant (“MGP”) sites, power plant sites, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials, even if the Utility 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 gross environmental remediation liability of $615 million at June 30, 2010 and $586 million at December 31, 2009. The following table presents the changes in the environmental remediation liability from December 31, 2009:


(in millions)
Balance at December 31, 2009	$	586
Additional remediation costs accrued:
Transfer to regulatory account for recovery		68
Amounts not recoverable from customers		16
Less: Payments		(55	)

Balance at June 30, 2010	$	615

The $615 million accrued at June 30, 2010 consists of the following:

•

$42 million for remediation at the Utility’s natural gas compressor site located near Hinkley, California;

•

$177 million for remediation at the Utility’s natural gas compressor site located on the California border, near Topock, Arizona;

•

$87 million related to remediation at divested generation facilities;

•

$121 million related to remediation costs for the Utility’s generation and other facilities and for third-party disposal sites;

•

$139 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

•

$49 million related to remediation decommissioning fossil-fueled sites.

The Utility has a program, in cooperation with the California Environmental Protection Agency, to evaluate and take appropriate action to mitigate any potential environmental concerns posed by certain former MGPs located throughout the Utility’s service territory. Of the 41 MGP sites owned or operated by the Utility, 33 have been or are in the process of being remediated. The Utility has notified the owners of properties located on the remaining eight sites and offered to test the soil for residues, and depending on the results of such tests, to take appropriate remedial action. Two of these sites are located in urban, residential areas of San Francisco and one site is located in a predominantly commercial area of San Francisco. Although the Utility has entered into or is negotiating site access agreements with several of the property owners, others have not responded to the Utility’s offer. Until its investigation is complete, the extent of its obligation to remediate is established, and appropriate remedial actions are determined, the Utility is unable to estimate the ultimate amount it may incur with respect to the remediation of these sites.

The Utility expects to recover $326 million of the $615 million environmental remediation liability, in accordance with a CPUC-approved ratemaking mechanism under which the Utility is authorized to recover 90% of hazardous waste remediation costs without a

reasonableness review. (Environmental remediation associated with the Hinkley natural gas compressor site is not recoverable under this mechanism.) In addition, the CPUC and the FERC have authorized the Utility to recover $123 million in rates relating to remediation costs for decommissioning fossil-fueled sites and certain of the Utility’s transmission stations. 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 $1.1 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. In addition, it is reasonably possible that the Utility will incur losses related to certain MGP sites located in San Francisco, but the Utility is unable to reasonably estimate the amount of such loss.

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.

PG&E Corporation and the Utility make 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. 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 for legal matters is included in PG&E Corporation’s and the Utility’s current liabilities – other in the Condensed Consolidated Balance Sheets and totaled $56 million at June 30, 2010 and $57 million at December 31, 2009. PG&E Corporation and the Utility are not able to predict the ultimate outcome of the various legal matters, but after consideration of these accruals, PG&E Corporation and the Utility do not believe that losses associated with these matters would have a material adverse impact on their financial condition or results of operations.

Tax Matters

PG&E Corporation and the Utility receive a federal subsidy for maintaining a retiree medical benefit plan with prescription drug benefits that is actuarially equivalent to Medicare Part D. For federal income tax purposes, the subsidy was deductible when contributed to the benefit plan maintained for these benefits. On March 30, 2010, federal healthcare legislation was signed eliminating the deduction for subsidy contributions after 2012. As a result, PG&E Corporation and the Utility recognized an expense of $20 million (recorded as an increase to income tax provision and a reduction to deferred income tax asset for subsidy amounts included in the calculation of accrued retiree medical benefit obligation).

The Internal Revenue Service (“IRS”) is currently auditing PG&E Corporation’s consolidated 2005–2007 income tax returns. For 2008 and 2009, PG&E Corporation participates in the Compliance Assurance Process (“CAP”), a real-time IRS audit intended to expedite matter resolution. The CAP audit culminates with a letter from the IRS indicating their acceptance of the return. The IRS accepted the 2008 return but held back several matters for further review. The most significant of these relates to a tax accounting method change used 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 maintained the right to further review the amount of the additional deduction. This review has not progressed significantly because the IRS is working with the utility industry in an effort to resolve this matter in a consistent manner for all utilities before auditing individual companies. Although the IRS is still reviewing PG&E Corporation’s 2009 tax return, PG&E Corporation anticipates that the IRS will hold back the same matters for further review.

The California Franchise Tax Board is auditing PG&E Corporation’s 2004 and 2005 combined California income tax returns, as well as 1997-2007 amended income tax returns reflecting IRS settlements for these years and claim filings that apply only to California. Based on recent communications with the Franchise Tax Board, PG&E Corporation does not expect the California audits to be completed prior to the latter part of 2011.

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.

As of June 30, 2010, PG&E Corporation has $25 million of federal and California capital loss carry forwards based on filed tax returns, of which approximately $10 million will expire if not used by 2011. For all periods presented, PG&E Corporation has provided a full valuation allowance against its deferred income tax assets for capital loss carry forwards.

For a discussion of unrecognized tax benefits, see Note 9 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report. It is reasonably possible that unrecognized tax benefits could decrease in the next 12 months by an amount ranging from $0 to $30 million for PG&E Corporation and the Utility.

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 June 30, 2010. The Utility had $44.0 billion in assets at June 30, 2010 and generated revenues of $6.7 billion in the six months ended June 30, 2010.

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, 2009 which incorporates by reference each company’s audited Consolidated Financial Statements, the Notes to the Consolidated Financial Statements, and other information incorporated by reference (“2009 Annual Report”).

Significant developments that have occurred since the 2009 Annual Report was filed with the Securities and Exchange Commission on February 19, 2010 are discussed in this Quarterly Report on Form 10-Q.

Summary of Changes in Earnings per Common Share and Income Available for Common Shareholders for the Three and Six Months Ended June 30, 2010

PG&E Corporation’s diluted earnings per common share (“EPS”) for the three months ended June 30, 2010 was $0.86 compared to $1.02 for the same period in 2009. For the six months ended June 30, 2010, PG&E Corporation’s diluted EPS was $1.54 compared to $1.67 for the same period in 2009. PG&E Corporation’s income available for common shareholders for the three months ended June 30, 2010 decreased by $55 million, or 14%, to $333 million, compared to $388 million for the same period in 2009. For the six months ended June 30, 2010, income available for common shareholders decreased by $38 million, or 6%, to $591 million, compared to $629 million for the same period in 2009. The primary factors for these decreases are discussed below.

Diluted EPS and income available for common shareholders decreased for both the three and six months ended June 30, 2010, as compared to the same periods in 2009 when the Utility recognized a $28 million, after tax, recovery of costs previously incurred in connection with its hydroelectric generation facilities and a $56 million, after tax, income benefit as a result of a tax settlement.

For the three months ended June 30, 2010, the Utility incurred costs of $20 million, after tax, to support Proposition 16 - Taxpayers Right to Vote Act (“Proposition 16”) that also contributed to a decrease in diluted EPS and income available for common shareholders during the quarter. These negative factors were partially offset by (1) an increase of $19 million, after tax, that the Utility earned on higher authorized capital investments, (2) a decrease of $4 million, after tax, in employee termination costs, and (3) a decrease of $11 million, after tax, representing costs the Utility incurred during the three months ended June 30, 2009 to perform accelerated natural gas leak surveys.

For the six months ended June 30, 2010, the Utility incurred (1) $45 million, after tax, of costs to support Proposition

16, (2) a $20 million, after tax, charge triggered by the elimination of the tax deductibility of the Medicare Part D federal subsidy, and (3) $12 million, after tax, of storm-related costs. These negative factors were partially offset by (1) an increase of $40 million, after tax, that the Utility earned on higher authorized capital investments, (2) a decrease of $22 million, after tax, representing costs the Utility incurred in 2009 in connection with a scheduled refueling outage at Diablo Canyon, (3) a decrease of $10 million, after tax, in employee termination costs, (4) a decrease of $16 million, after tax, representing costs the Utility incurred during the six months ended June 30, 2009 to perform accelerated natural gas leak surveys, and (5) a decrease of $7 million, after tax, in uncollectible expense as a result of customer outreach and increased collection efforts as compared to the same period in 2009.

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 Regulatory Proceedings. There are several rate cases that are currently pending at the CPUC and the FERC, the outcome of which will determine the majority of the Utility’s base revenue requirements for 2011 and several years thereafter. In the 2011 General Rate Case (“2011 GRC”), the CPUC will authorize the Utility’s revenue requirements for its electric and natural gas distribution operations and its electric generation operations from 2011 through 2013. The CPUC will also authorize the Utility’s revenue requirements for its natural gas transportation and storage services from 2011 through 2014 in the pending gas transmission and storage rate case. In addition, on July 28, 2010, the Utility filed its 13^th Electric Transmission Owner (“TO”) rate case requesting the FERC to determine the amount of electric transmission revenues the Utility can recover beginning in March 2011. (See “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. (See “Capital Expenditures” below.) The outcome of these regulatory proceedings can be affected by many factors, including general economic conditions, the level of customer rates, and political and regulatory policies.

•

The Ability of the Utility to Control Costs While Improving Operational Efficiency and Reliability. The Utility’s revenue requirements in general rate cases and TO rate cases are generally set at a level to allow the Utility the opportunity to recover its basic forecasted operating expenses, as well as to earn a return on equity (“ROE”) and recover depreciation, tax, and interest expense associated with authorized capital expenditures. Differences in the amount or timing of forecasted and actual operating expenses and capital expenditures can affect the Utility’s ability to earn its CPUC-authorized rate of return and the amount of PG&E Corporation’s income available for common shareholders. In addition, the Utility may incur higher than anticipated operating expenses than provided for in the last general rate case. The Utility continuously re-prioritizes spending to meet customer needs and seeks to achieve sustainable operational efficiencies to maximize its ability to earn its authorized return while maintaining and improving operational safety and reliability. (See “Results of Operations” below.) The Utility also seeks to make the amount and timing of its capital expenditures consistent with customer demand and forecasted amounts and timing and to manage separately funded projects within approved cost limits. When capital expenditures are higher than authorized levels, the Utility incurs associated depreciation, property tax, and interest expense but does not recover revenues to fully offset these expenses or earn an ROE until the increased capital expenditures are added to rate base in future rate cases. (See “Capital Expenditures” below.)

•

Capital Structure and Financing. The CPUC has authorized a capital structure for the Utility’s electric and natural gas distribution and electric generation rate base that consists of 52% common equity and 48% debt and preferred stock. This authorized capital structure will remain in effect through 2012. The CPUC also has authorized the Utility to earn a rate of return on each component of its capital structure, including a ROE of 11.35%. These rates will remain in effect through 2010. The rates for 2011 and 2012 are subject to an annual adjustment mechanism that will be triggered if the 12-month October-through-September average yield for the applicable Moody’s Investors Service utility bond index increases or decreases by more than 1% as compared to the applicable benchmark. The amount of the Utility’s authorized equity earnings is determined by the 52% equity component, the 11.35% ROE, and the aggregate amount of rate base authorized by the CPUC. The rate of return that the Utility earns on its FERC-jurisdictional rate base is not specifically

authorized, but rates are designed to allow the Utility to earn a reasonable rate of return. The CPUC periodically 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 timing and amount of the Utility’s future financing will depend on various factors, as discussed in “Liquidity and Financial Resources” below. PG&E Corporation contributes equity to the Utility as needed by the Utility to maintain its CPUC-authorized capital structure. PG&E Corporation may issue debt or equity in the future to fund these equity contributions.

In addition to the key factors discussed above, PG&E Corporation’s and the Utility’s future results of operations and financial condition are subject to risk factors. (See “Risk Factors” in the 2009 Annual Report.)

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 and legal proceedings; 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;

•

the outcome of pending and future regulatory proceedings and whether the Utility is able to timely recover its costs through rates;

•

the adequacy and price of electricity and natural gas supplies and whether the new day-ahead, hour-ahead, and real-time wholesale electricity markets established by the California Independent System Operator (“CAISO”) will continue to function effectively, 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, 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 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 the Utility’s application to renew the operating licenses for Diablo Canyon, and potential changes in laws or regulations promulgated by the NRC or environmental agencies with respect to the storage of spent nuclear fuel, security, safety, 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 implement its program to install advanced meters for its electric and natural gas customers and integrate the new meters with its customer billing and other systems, the outcome of the independent investigation ordered by the CPUC and the California Legislature into customer concerns about the new meters, and the ability of the Utility to implement various rate changes including “dynamic pricing” by offering 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 outcome of litigation, including litigation involving the application of various California wage and hour laws, and the extent to which PG&E Corporation or the Utility incurs costs and liabilities in connection with litigation that are not recoverable through rates, from insurance, 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 and the costs of compliance and remediation;

•

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.

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 discussion in the section entitled “Risk Factors” in the 2009 Annual Report. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

RESULTS OF OPERATIONS

The table below details certain items from the accompanying Condensed Consolidated Statements of Income for the three and six months ended June 30, 2010 and 2009:


	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2010			2009			2010			2009

Utility
Electric operating revenues	$	2,515		$	2,554		$	5,025		$	4,980
Natural gas operating revenues		717			640			1,682			1,645

Total operating revenues		3,232			3,194			6,707			6,625

Cost of electricity		863			883			1,783			1,766
Cost of natural gas		247			188			742			745
Operating and maintenance		958			1,037			1,948			2,096
Depreciation, amortization, and decommissioning		468			429			919			848

Total operating expenses		2,536			2,537			5,392			5,455

Operating Income		696			657			1,315			1,170
Interest income		2			17			4			26
Interest expense		(164	)		(166	)		(320	)		(339	)
Other income (expense), net		1			15			(5	)		36

Income Before Income Taxes		535			523			994			893
Income tax provision		196			132			391			263

Net Income		339			391			603			630
Preferred stock dividend requirement		4			4			7			7

Income Available for Common Stock	$	335		$	387		$	596		$	623

PG&E Corporation, Eliminations, and Other⁽¹⁾
Operating revenues	$	—		$	—		$	—		$	—
Operating expenses		1			1			2			1

Operating Loss		(1	)		(1	)		(2	)		(1	)
Interest income		—			—			—			—
Interest expense		(11	)		(12	)		(23	)		(20	)
Other income, net		1			7			1			4

Loss Before Income Taxes		(11	)		(6	)		(24	)		(17	)
Income tax benefit		(9	)		(7	)		(19	)		(23	)

Net Income (Loss)	$	(2	)	$	1		$	(5	)	$	6

Consolidated Total
Operating revenues	$	3,232		$	3,194		$	6,707		$	6,625
Operating expenses		2,537			2,538			5,394			5,456

Operating Income		695			656			1,313			1,169
Interest income		2			17			4			26
Interest expense		(175	)		(178	)		(343	)		(359	)
Other income (expense), net		2			22			(4	)		40

Income Before Income Taxes		524			517			970			876
Income tax provision		187			125			372			240

Net Income		337			392			598			636
Preferred stock dividend requirement of subsidiary		4			4			7			7

Income Available for Common Shareholders	$	333		$	388		$	591		$	629

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

Utility

The following presents the Utility’s operating results for the three and six months ended June 30, 2010 and 2009.

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, and 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’ demand for electricity (“load”) is satisfied by electricity provided under long-term contracts between the California Department of Water Resources (“DWR”) and various power suppliers.

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


	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2010			2009			2010			2009
Electric revenues	$	2,820		$	3,012		$	5,685		$	5,833
DWR pass-through revenues⁽¹⁾		(305	)		(458	)		(660	)		(853	)

Total electric operating revenues	$	2,515		$	2,554		$	5,025		$	4,980

⁽¹⁾	These are revenues collected on behalf of the DWR for electricity allocated to the Utility’s customers under contracts between the DWR and power suppliers, and are not included in the Utility’s Condensed Consolidated Statements of Income.

The Utility’s total electric operating revenues, including revenues intended to recover costs that are passed through to customers, decreased by $39 million, or 2%, in the three months ended June 30, 2010 as compared to the same period in 2009. Costs that are passed through to customers and do not impact net income decreased by about $55 million due to lower costs of electric procurement, lower costs associated with public purpose programs and a decrease in the amount of collateral posted with the ISO. (See “Cost of Electricity” and “Operating and Maintenance” below.) Electric operating revenues, excluding costs passed through to customers, increased by $16 million. This was primarily due to an increase of $52 million in authorized base revenues, which was partially offset by a decrease in revenues of $35 million, representing the amount the Utility received in 2009 to recover costs it had previously incurred in connection with its hydroelectric generation facilities.

The Utility’s total electric operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $45 million, or 1%, in the six months ended June 30, 2010, as compared to the same period in 2009. Costs that are passed through to customers and do not impact net income decreased by about $26 million primarily due to a decrease in the amount of collateral posted with the ISO and a decrease in the cost of public purpose programs, offset by higher costs of electric procurement. (See “Operating and Maintenance” and “Cost of Electricity” below.) Electric operating revenues, excluding costs passed through to customers, increased by $71 million. This was primarily due to a $106 million increase in authorized base revenues, which was partially offset by a decrease in revenues of $35 million, representing the amount the Utility received in 2009 to recover costs it had previously incurred in connection with its hydroelectric generation facilities.

The Utility’s future electric operating revenues will depend on the amount of revenue requirements authorized by the FERC and the CPUC in various regulatory proceedings. Additionally, the Utility’s future electric operating revenues will be impacted by the cost of electricity. The Utility also expects to continue to collect revenue requirements to recover capital expenditures related to specific projects approved by the CPUC. (See “Capital Expenditures” below.) Revenue requirements associated with new or expanded public purpose, energy efficiency, and demand response programs will also impact electric operating revenues. Finally, the CPUC has not yet determined how the existing energy efficiency incentive mechanism will be modified, so the amount of incentive revenues the Utility may earn for the implementation of its programs in 2009 and future years is uncertain. (See “Regulatory Matters” below.)

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2010		2009		2010		2009
Cost of purchased power	$	811	$	835	$	1,653	$	1,673
Fuel used in own generation		52		48		130		93

Total cost of electricity	$	863	$	883	$	1,783	$	1,766

Average cost of purchased power per kWh ⁽¹⁾	$	0.084	$	0.088	$	0.083	$	0.085

Total purchased power (in millions of kWh)		9,708		9,488		19,825		19,714

⁽¹⁾	Kilowatt-hour

The Utility’s total cost of electricity decreased by $20 million, or 2%, in the three months ended June 30, 2010, as compared to the same period in 2009, primarily due to a decrease in the price of purchased power.

The Utility’s total cost of electricity increased by $17 million, or 1%, in the six months ended June 30, 2010, as compared to the same period in 2009. This was caused by an increase in the cost of fuel used in the Utility’s own generation facilities as the

Utility increased its non-nuclear generation to replace power that had previously been provided under a DWR contract that expired at the end of 2009 (costs associated with power provided to the Utility’s customers under DWR contracts are not included in the Utility’s cost of purchased power). The Utility’s mix of resources is determined by 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 level of hydroelectric and nuclear power produced by the Utility, the cost of procuring more renewable energy, changes in customer demand, and the amount and timing of power purchases needed to replace power previously supplied under the DWR contracts as those contracts expire or are terminated, novated, or renegotiated.

The Utility’s future cost of electricity may also be affected by federal or state legislation or rules that may be adopted to regulate the emissions of greenhouse gases (“GHG”) from the Utility’s electricity generating facilities or the generating facilities from which the Utility procures electricity. In particular, costs are likely to increase in the future when California’s statewide GHG emissions reduction law is implemented. (See “Environmental Matters” below.)

Natural Gas Operating Revenues

The Utility sells natural gas, natural gas transportation services, and natural gas storage services. The Utility’s transportation services are provided by a transmission system and a distribution system. The transmission system transports gas throughout its service territory for delivery to the Utility’s distribution system, which, in turn, delivers natural gas to end-use customers. The transmission system also delivers natural gas 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 June 30,				Six Months Ended June 30,
(in millions)	2010		2009		2010		2009
Bundled natural gas revenues	$	619	$	555	$	1,494	$	1,478
Transportation service-only revenues		98		85		188		167

Total natural gas operating revenues	$	717	$	640	$	1,682	$	1,645

The Utility’s total natural gas operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $77 million, or 12%, in the three months ended June 30, 2010 as compared to the same period in 2009. This reflects a $59 million increase in the total cost of natural gas due to higher market prices which is passed through to customers and does not impact net income. (See “Cost of Natural Gas” below.) Natural gas operating revenues, excluding items passed through to customers, increased by $18 million primarily due to a $13 million increase in authorized base revenues.

The Utility’s total natural gas operating revenues, including revenues intended to recover costs that are passed through to customers, increased by $37 million, or 2%, in the six months ended June 30, 2010 as compared to the same period in 2009. This reflects an $11 million increase in the cost of public purpose programs which is passed through to customers and does not impact net income. (See “Operating and Maintenance” below.) Natural gas operating revenues, excluding items passed through to customers, increased by $26 million primarily due to a $23 million increase in authorized base revenues.

The Utility’s future natural gas operating revenues will depend on the amount of revenue requirements authorized by the CPUC in various regulatory proceedings. (See “Regulatory Matters” below.) Additionally, the Utility’s future natural gas operating revenues will be impacted by the cost of natural gas. The Utility also expects future natural gas operating revenues to increase to the extent that the CPUC approves the Utility’s separately funded capital projects. The CPUC has not yet determined how the existing energy efficiency incentive mechanism will be modified, so the amount of incentive revenues that the Utility may earn for the implementation of its programs in 2009 and future years is uncertain. (See “Regulatory Matters” below.)

Cost of Natural Gas

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2010		2009		2010		2009
Cost of natural gas sold	$	204	$	149	$	654	$	664
Transportation cost of natural gas sold		43		39		88		81

Total cost of natural gas	$	247	$	188	$	742	$	745

Average cost per Mcf of natural gas sold	$	3.58	$	2.87	$	4.63	$	4.34

Total natural gas sold (in millions of Mcf)		57		52		152		153

The Utility’s total cost of natural gas increased by $59 million, or 31%, in the three months ended June 30, 2010, as compared to the same period in 2009, primarily due to higher market prices for natural gas, which are passed through to customers and do not impact net income.

In the six months ended June 30, 2010, the Utility’s total cost of natural gas decreased by $3 million, or less than 1%, due to the $49 million the Utility received in the first quarter of 2010 to be refunded to customers as part of a settlement of litigation arising from the manipulation of the natural gas market by third parties during 1999-2002. This decrease was partially offset by higher market prices for natural gas, which are passed through to customers.

The Utility’s future cost of natural gas will be affected by the market price of natural gas and changes in customer demand. The Utility’s future cost of gas may also 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 decreased by $79 million, or 8%, in the three months ended June 30, 2010. During the three months ended June 30, 2010, the pass-through costs of collateral payments to the CAISO and public purpose programs decreased by $20 million and $14 million, respectively. Excluding costs passed through to customers, operating and maintenance expenses decreased by $45 million, including an $18 million decrease in labor and other costs attributable to accelerated natural gas leak surveys and associated remedial work that was performed in 2009 but not in 2010, a $7 million decrease in severance costs as compared to 2009 when severance costs were incurred in connection with the consolidation of certain regional facilities, and a $4 million decrease in uncollectible customer accounts as a result of customer outreach and increased collection efforts. These decreases were partially offset by an increase in employee benefits of $15 million, primarily due to a reduction in investment gains earned on employee benefit plan trust assets as compared to 2009. Additionally, operating and maintenance expenses decreased as a result of a $31 million decrease in other miscellaneous operating and maintenance expenses, including costs associated with environmental remediation and pass-through costs associated with the new day-ahead market.

The Utility’s operating and maintenance expenses decreased by $148 million, or 7%, in the six months ended June 30, 2010, compared to the same period in 2009. During the six months ended June 30, 2010, the pass-through costs of collateral payments to the CAISO and public purpose programs decreased by $20 million and $7 million, respectively. Excluding costs passed through to customers, operating and maintenance expenses decreased by $121 million, including a $79 million decrease in labor costs and other costs as compared to 2009 when costs were incurred in connection with the scheduled refueling outage at Diablo Canyon and accelerated natural gas leak surveys and associated remedial work, a $17 million decrease in severance costs as compared to 2009 when severance costs were incurred in connection with the consolidation of certain regional facilities, and a $16 million decrease in uncollectible customer accounts as a result of customer outreach and increased collection efforts. These decreases were partially offset by $21 million of higher costs related to the January 2010 winter storms. Additionally, operating and maintenance expenses decreased as a result of a $30 million decrease in other miscellaneous operating and

maintenance expenses, including costs associated with environmental remediation and pass-through costs associated with the new day-ahead market.

The Utility expects that it will incur higher expenses in future periods to obtain permits or comply with permitting requirements and to maintain its aging electric and natural gas infrastructure. The Utility will seek to recover its costs to serve customers in future proceedings and will continue its efforts to identify and implement initiatives to achieve operational efficiencies and to create future sustainable cost savings.

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 June 30, 2010, and $71 million, or 8%, in the six months ended June 30, 2010, as compared to the same periods in 2009. These changes are primarily due to an increase in capital additions.

The Utility’s depreciation expense for future periods is expected to increase as a result of an overall increase in net capital additions. Additionally, depreciation expense in subsequent years will be impacted by the depreciation rates set by the CPUC in the 2011 GRC and the 2011 gas transmission and storage rate case, and by the FERC in future TO rate cases.

Interest Income

In the three and six months ended June 30, 2010, the Utility’s interest income decreased by $15 million, or 88%, and $22 million, or 85%, as compared to the same periods in 2009, primarily due to lower interest rates earned on various regulatory balancing accounts and lower balances for those accounts. In addition, interest income decreased for both the three and six months ended June 30, 2010, as compared to the same period in 2009, when the Utility recovered $12 million of interest costs related to the proposed divestiture of its hydroelectric generation facilities. Also, interest income earned on funds held in escrow pending the disposition of Chapter 11 disputed claims decreased due to lower interest rates and a lower escrow balance. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements for information about the Chapter 11 disputed claims.)

The Utility’s interest income in future periods primarily will be 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.

Interest Expense

In the three and six months ended June 30, 2010, the Utility’s interest expense decreased by $2 million and $19 million, or 1% and 6%, respectively, as compared to the same periods in 2009. This decrease was primarily attributable to lower interest rates on outstanding short-term debt and decreases in the outstanding balances of the liability for Chapter 11 disputed claims and various regulatory balancing accounts and regulatory assets. This decrease was partially offset by interest that accrued on higher outstanding balances of long-term debt due to the timing of senior note issuances. (See Note 4 of the Notes to the Condensed Consolidated Financial Statements for further discussion.)

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.

Other Income (Expense), Net

The Utility’s other income (expense), net changed by $14 million, or 93%, in the three months ended June 30, 2010 and $41 million, or 114% in the six months ended June 30, 2010, as compared to the same periods in 2009. The change was primarily due to an increase in other expenses as a result of costs the Utility incurred to support the Taxpayers’ Right to Vote Act, a California ballot initiative that appeared on the June 8, 2010 ballot. These costs are not recovered in rates.

Income Tax Provision

The Utility’s income tax provision increased by $64 million, or 48%, for the three months ended June 30, 2010, and $128 million, or 49% for the six months ended June 30, 2010, as compared to the same period in 2009. The effective tax rates for the three months ended June 30, 2010 and 2009 were 37% and 25%, respectively. The increase in the effective tax rate for the three months ended June 30, 2010 was primarily due to an income tax benefit received in 2009 from settling a claim with the Internal Revenue Service (“IRS”) related to 1998 and 1999 with no comparable benefit in 2010, and non-deductible expenses incurred to support the ballot initiative discussed above. The effective tax rates for the six months ended June 30, 2010 and 2009 were 39% and 30%, respectively. The increase in the effective tax rate for the six months ended June 30, 2010 was primarily due to the items discussed above for the second quarter of 2010 and the reversal of a deferred tax asset that had been recorded to reflect the future tax benefits attributable to the Medicare Part D subsidy after 2012 which were eliminated as part of the federal healthcare legislation passed during March 2010. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements for a discussion of “Tax Matters.”)

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 Convertible Subordinated Notes and 5.8% Senior Notes, and is not allocated to affiliates.

There were no material changes to PG&E Corporation’s operating income in the three and six months ended June 30, 2010, as compared to the same periods in 2009.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

The Utility’s ability to fund operations depends on the levels of its operating cash flow and access to the capital markets. The levels of the Utility’s operating cash and short-term debt fluctuate as a result of seasonal demand for electricity 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 Utility has short-term borrowing authority of $4.0 billion, including $500 million that is restricted for use in 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 capital 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 markets.

Credit Facilities and Short Term Borrowings

The following table summarizes PG&E Corporation’s and the Utility’s outstanding commercial paper and revolving credit facilities at June 30, 2010:


(in millions)
Authorized Borrower	Termination Date	Facility Limit			Letters of Credit Outstanding		Cash Borrowings		Commercial Paper Backup		Availability
PG&E Corporation	February 2012	$	187	⁽¹⁾	$	—	$	30		N/A	$	157
Utility	February 2012		1,940	⁽²⁾		256		—	$	1,027		657
Utility	February 2012		750	⁽³⁾		N/A		—		—		750

Total credit facilities		$	2,877		$	256	$	30	$	1,027	$	1,564

⁽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.

On June 8, 2010, the Utility entered into a $750 million unsecured revolving credit agreement with a syndicate of lenders. The Utility will use $500 million of the credit capacity under the credit agreement to support its electric procurement hedging activities. This credit capacity replaced the $500 million Floating Rate Senior Notes that matured on June 10, 2010. The remaining credit capacity of $250 million will be used for general working capital purposes. The credit agreement contains 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 $1.9 billion 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 June 30, 2010, PG&E Corporation and the Utility were in compliance with all covenants under each of the revolving credit facilities listed in the table above.

2010 Financings

On April 1, 2010, the Utility issued $250 million principal amount of 5.8% Senior Notes due March 1, 2037. The proceeds from this issuance were used to repay a portion of outstanding commercial paper.

On April 8, 2010, the California Infrastructure and Economic Development Bank issued $50 million of tax-exempt pollution control bonds series 2010E due on November 1, 2026 for the benefit of the Utility and loaned the proceeds to the Utility. The proceeds were used to refund the corresponding related series of pollution control bonds issued in 2005 which were repurchased by the Utility in 2008. The series 2010E bonds bear interest at 2.25% per year through April 1, 2012 and are subject to mandatory tender on April 2, 2012 at a price of 100% of the principal amount plus accrued interest. Thereafter, this series of bonds may be remarketed in a fixed or variable rate mode. Interest is payable semi-annually in arrears on April 1 and October 1.

PG&E Corporation issued 2,340,451 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 $89 million of cash during the six months ended June 30, 2010. PG&E Corporation issued 16,370,779 shares of common stock upon conversion of the $247 million principal amount of PG&E Corporation’s Convertible Subordinated Notes at a conversion price of $15.09 per share between June 23 and June 29, 2010. These notes were no longer outstanding at June 30, 2010, and the conversion had no impact on cash.

PG&E Corporation also contributed $130 million of cash to the Utility during the six months ended June 30, 2010 to ensure that the Utility had adequate capital to fund its capital expenditures and to maintain the 52% common equity target authorized by the CPUC.

Future Financing Needs

The amount and timing of the Utility’s future financing needs will depend on various factors, including the timing and amount of forecasted capital expenditures, the amount of cash internally generated through normal business operations, the conditions in the capital markets, and other factors. The Utility’s future financing needs will also depend on the timing of the resolution of the Chapter 11 disputed claims and the amount of interest on these claims that the Utility will be required to pay. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.)

PG&E Corporation may issue debt or equity in the future to fund equity contributions to the Utility and to fund investments to the extent that internally generated funds are not sufficient. As of June 30, 2010, PG&E Corporation made certain tax equity investments (see “PG&E Corporation” below) and may fund similar investments in the future, resulting in additional financing needs. Assuming that PG&E Corporation and the Utility can access the capital markets on reasonable terms, PG&E Corporation and the Utility believe that the Utility’s cash flow from operations, existing sources of liquidity, and future financings will provide adequate resources to fund operating activities, meet anticipated obligations, and finance future capital expenditures and investments.

Dividends

During the six months ended June 30, 2010, the Utility paid common stock dividends totaling $358 million to PG&E Corporation.

Utility

Operating Activities

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

The Utility’s cash flows from operating activities for the six months ended June 30, 2010 and 2009 were as follows:


	Six Months Ended June 30,
(in millions)	2010			2009
Net income	$	603		$	630
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,016			932
Allowance for equity funds used during construction		(57	)		(47	)
Deferred income taxes and tax credits, net		(1	)		368
Other changes in noncurrent assets and liabilities		(63	)		(34	)
Effect of changes in operating assets and liabilities:
Accounts receivable		(81	)		199
Inventories		(20	)		113
Accounts payable		4			(140	)
Income taxes receivable/payable		475			64
Regulatory balancing accounts, net		(206	)		(228	)
Other current assets		28			10
Other current liabilities		(316	)		(220	)
Other		—			3

Net cash provided by operating activities	$	1,382		$	1,650

In the six months ended June 30, 2010, net cash provided by operating activities decreased by $268 million compared to the same period in 2009 primarily due to an increase of $206 million in net collateral paid by the Utility related to price risk management activities in 2010. Collateral payables and receivables are included in other changes in noncurrent assets and liabilities, other current assets, and other current liabilities in the table above. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.) The decrease also reflects $36 million of additional net tax refunds received in 2009 compared to 2010. The remaining decreases in cash flows from operating activities consisted of miscellaneous other changes in operating assets and liabilities due to timing differences.

Various factors can affect the Utility’s future operating cash flows, including the timing of cash collateral payments and receipts related to price risk management activity. The Utility’s cash collateral activity will fluctuate based on changes in the Utility’s net credit exposure to counterparties which primarily depends on electricity and gas price movement.

The Utility’s operating cash flows also will be impacted by electricity procurement costs and the timing of rate adjustments authorized to recover these costs. The CPUC has established a balancing account mechanism to adjust the Utility’s electric rates whenever the forecasted aggregate over-collections or under-collections of the Utility’s electric procurement costs for the current year exceed 5% of the Utility’s prior-year generation revenues, excluding generation revenues for DWR contracts. The Utility updated its forecasted 2010 electricity procurement costs in November 2009 for inclusion in the annual electric true-up proceeding, which adjusted electric and gas rates on January 1, 2010 to (1) reflect over- and under-collections in the Utility’s major electric and gas balancing accounts, and (2) implement various other electricity and gas revenue requirement changes authorized by the CPUC and the FERC.

Additionally, effective on June 1, 2010, the Utility began a program to provide expedited rate relief to customers. The program, which will continue through the end of 2010, includes a reduction in system bundled average electric rates coupled with a rebalancing of the residential rate tiers to reduce rates in the highest tiers. The rate reduction is expected to reduce 2010 retail electric revenues by $268

million. To provide this reduction, the Utility has accelerated the refund of various over-collections that otherwise would not be reflected in adjusted rates until January 2011 and the Utility has suspended collection of the authorized revenue requirement for the currently under-spent funds in the California Solar Initiative Program. The rate relief program will have no impact on net income for the Utility.

Investing Activities

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

The Utility’s cash flows from investing activities for the six months ended June 30, 2010 and 2009 were as follows:


	Six Months Ended June 30,
(in millions)	2010			2009
Capital expenditures	$	(1,786	)	$	(2,077	)
Decrease in restricted cash		50			15
Proceeds from sales and maturities of nuclear decommissioning trust investments		685			954
Purchases of nuclear decommissioning trust investments		(696	)		(985	)
Other		11			5

Net cash used in investing activities	$	(1,736	)	$	(2,088	)

Net cash used in investing activities decreased by $352 million in the six months ended June 30, 2010, compared to the same period in 2009. This decrease was primarily due to a decrease of $291 million in capital expenditures as a result of the timing of capital projects.

Future cash flows used in investing activities are largely dependent on expected capital expenditures. (See “Capital Expenditures” below and in the 2009 Annual Report for further discussion of expected spending and significant capital projects.)

Financing Activities

The Utility’s cash flows from financing activities for the six months ended June 30, 2010 and 2009 were as follows:


	Six Months Ended June 30,
(in millions)	2010			2009
Borrowings under revolving credit facilities	$	—		$	300
Repayments under revolving credit facilities		—			(300	)
Net issuance (repayments) of commercial paper, net of discount of $1 in 2010 and $3 in 2009		693			(47	)
Proceeds from issuance of short-term debt, net of issuance costs of $1 in 2009		—			499
Proceeds from issuance of long-term debt, net of discount and issuance costs of $5 in 2010 and $12 in 2009		295			538
Short-term debt matured		(500	)		—
Long-term debt matured		—			(600	)
Energy recovery bonds matured		(182	)		(174	)
Preferred stock dividends paid		(7	)		(7	)
Common stock dividends paid		(358	)		(312	)
Equity contribution		130			653
Other		9			(6	)

Net cash provided by financing activities	$	80		$	544

In the six months ended June 30, 2010, net cash provided by financing activities decreased by $464 million compared to the same period in 2009. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities and the level of cash provided by or used in investing activities. The Utility generally utilizes long-term senior unsecured debt issuances and equity contributions from PG&E Corporation to fund debt maturities and capital expenditures and to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.

PG&E Corporation

In addition to the investments above, PG&E Corporation had the following material cash flows on a stand-alone basis for the six months ended June 30, 2010 and 2009; dividend payments, interest, common stock issuance, the issuance of 5.75% Senior Notes in the principal amount of $350 million in March 2009, net tax refunds of $131 million in 2009, and transactions between PG&E Corporation and the Utility.

CONTRACTUAL COMMITMENTS

PG&E Corporation and the Utility enter into contractual commitments in connection with business activities. These future obligations primarily relate to financing arrangements (such as long-term debt, preferred stock, and certain forms of regulatory financing), purchases of electricity and natural gas for customers, purchases of transportation capacity, purchases of renewable energy, and the purchase of fuel and transportation to support the Utility’s generation activities. In addition to those commitments disclosed in the 2009 Annual Report and those arising from normal business activities, the Utility issued $250 million of senior notes on April 1, 2010, entered into a loan agreement to repay the California Infrastructure and Economic Development Bank which issued $50 million of tax-exempt pollution control bonds on behalf of the Utility on April 8, 2010, and entered into a $750 million unsecured revolving credit agreement with a syndicate of lenders on June 8, 2010. (Refer to the 2009 Annual Report, the Liquidity and Financial Resources section above and Notes 4 and 11 of the Notes to the Condensed Consolidated Financial Statements.)

CAPITAL EXPENDITURES

Utility

Most of the Utility’s revenue requirements to recover forecasted capital expenditures are authorized in the GRC, TO rate cases, and gas transmission and storage rate cases. (See “Regulatory Matters” below.) The Utility also collects additional revenue requirements to recover capital expenditures related to projects that have been specifically authorized by the CPUC, such as new power plants, gas or electric distribution projects, and the SmartMeter^TM advanced metering infrastructure. The Utility’s proposals for significant capital projects that have been submitted for CPUC approval are discussed in the 2009 Annual Report. Recent developments in authorized or proposed capital projects since the 2009 Annual Report was filed are discussed below.

Electric Distribution Reliability Program

On June 24, 2010, the CPUC authorized the Utility to recover capital expenditures of $357 million beginning in 2010 and continuing through 2013 to implement electric distribution reliability improvement projects designed to decrease the frequency and duration of electricity outages. The Utility had requested that the CPUC approve a more comprehensive six-year reliability improvement program at an estimated capital cost of approximately $2.0 billion. The CPUC determined that the Utility had not demonstrated the need for the entirety of the requested capital expenditure amount and authorized a scaled-back three-year program to implement portions of the Utility’s proposed program. The CPUC also noted that any future investment in reliability projects can be considered in the Utility’s 2014 General Rate Case and subsequent general rate cases. The CPUC adopted the Utility’s proposal to set rates based on the adopted cost forecasts with a balancing account to accumulate any difference in revenue requirement based on recorded costs compared to the adopted forecast. The Utility is required to file annual reports (by March 1) to describe work performed during the previous calendar year and to include a forecast of work to be performed in the current year.

New Generation Facilities

Proposed Oakley Generation Facility

In September 2009, the Utility requested that the CPUC approve several agreements for new long-term generation resources to meet forecasted customer demand, including three power purchase agreements and an agreement for a third party to develop and construct a new 586 megawatt (“MW”) natural gas-fired facility in Oakley, California that would be transferred to the Utility upon completion. On July 29, 2010, the CPUC approved the power purchase agreements but the CPUC denied the Utility’s request for approval of the proposed Oakley generation facility finding that the new facility is not needed to meet forecasted customer demand. The CPUC indicated that the Utility may submit another application for approval of this project under certain circumstances.

Humboldt Bay Generating Station

As of June 30, 2010, the Utility has incurred $187 million to construct a 163 MW power plant to re-power the Utility’s existing power plant at Humboldt Bay which is at the end of its useful life. The CPUC has authorized the Utility to recover associated capital costs of $239 million for the construction. Humboldt Bay began operational testing in June 2010 and is expected to commence commercial operations in the third quarter of 2010.

Colusa Generating Station

As of June 30, 2010, the Utility has incurred project costs of $599 million to construct a 657 MW combined cycle generating facility located in Colusa County, California. The CPUC has authorized the Utility to recover capital costs of $673 million for the construction of the facility. Subject to meeting operational performance requirements and other conditions, it is anticipated that the Colusa Generating Station will commence operations by the end of 2010.

New Renewable Energy Development

On April 22, 2010, the CPUC approved the Utility’s proposed five-year program for the development of renewable generation resources based on solar photovoltaic (“PV”) technology. The CPUC authorized the Utility to develop up to 250 MW of PV facilities and to enter into power purchase agreements for an additional 250 MW of PV facilities to be developed by third parties. The Utility has been authorized to build 50 MW of utility-owned PV facilities each year of the program. If the Utility builds less than 50 MW in a program year, it may roll forward no more than 10 MW of un-deployed capacity to be developed in a subsequent program year. The CPUC has authorized the Utility to recover its actual capital costs to develop utility-owned PV facilities, subject to an aggregate price cap of up to $1.45 billion based on the maximum 250 MW authorized to be developed by the Utility. If total capital costs exceed the cost cap, the Utility could only recover such costs after obtaining CPUC approval. The CPUC also established an incentive mechanism that allows the Utility shareholders to retain 10% of the savings if the actual average per-kilowatt capital cost of the Utility-owned PV facilities is less than $3,920 per kilowatt. The remaining 90% of any such savings would be passed through to customers. As the Utility’s new PV facilities begin commercial operation, the project costs would be included in the Utility’s rate base and the Utility would be entitled to earn a rate of return on the additional rate base.

The Utility has submitted advice letters to the CPUC requesting approval of the processes to be used by the Utility to solicit offers from third-parties to develop the Utility-owned portion of the PV program and to solicit offers to enter into power purchase agreements. These requests have not yet been approved. The first year of the PV program will not begin until the approval of the solicitation process for the Utility-owned portion of the program becomes final and non-appealable. It is uncertain when the solicitation process will be approved and when the approval will become final and non-appealable.

PG&E Corporation

PG&E Corporation, through its subsidiary, PG&E Strategic Capital, Inc., along with Fort Chicago Energy Partners, L.P. and Williams Gas Pipeline Company, LLC, have been jointly pursuing the development of the proposed Pacific Connector Gas Pipeline, an interstate gas transmission pipeline that would connect with the proposed liquefied natural gas (“LNG”) terminal in Coos Bay, Oregon being developed by Fort Chicago Energy Partners, L.P. as lead investor. The construction of the pipeline is dependent upon the construction of the LNG terminal. In December 2009, the FERC issued an order to authorize construction and operation of the LNG terminal and the pipeline. There are additional federal, state, and local permits and authorizations that must be obtained before construction can proceed. In addition, commitments must be obtained from LNG suppliers and shippers under long-term contracts of sufficient volumes to justify moving forward with construction of the LNG terminal and the pipeline. The desire of LNG suppliers to make such commitments is dependent on the world market for LNG, the price in various markets compared to the U.S. price, and the overall level of supply and demand for LNG. In the U.S., the gas supply landscape has changed considerably since the LNG terminal and pipeline were first contemplated. Enhanced drilling techniques have increased access to shale gas and created significant gas reserves which may decrease the need for LNG sourced natural gas. As such, PG&E Corporation cannot predict whether construction of the proposed LNG terminal and associated pipeline will occur nor whether PG&E Corporation will continue to invest in the proposed pipeline project.

OFF-BALANCE SHEET ARRANGEMENTS

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources.

CONTINGENCIES

PG&E Corporation and the Utility have significant contingencies; including Chapter 11 disputed claims, tax matters, legal matters, and environmental matters, which are discussed in Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements.

REGULATORY MATTERS

This section of MD&A discusses significant regulatory developments that have occurred since the 2009 Annual Report was filed with the SEC.

2011 General Rate Case Application

On July 30, 2010, following the conclusion of the CPUC hearings in the Utility’s 2011 GRC, the Utility and the CPUC’s Division of Ratepayer Advocates (“DRA”) filed a joint comparison exhibit with the CPUC showing differences between updated revenue requirement amounts requested by the Utility and amounts recommended by the DRA. The Utility’s updated revenue requirement is approximately $6.6 billion, as compared to approximately $6.7 billion, the amount originally requested in its December 21, 2009 GRC application. The DRA currently recommends that the Utility’s 2011 revenue requirement be set at a level that is $883 million lower than the amount currently requested by the Utility. The DRA’s current recommendation is lower than the amount recommended in its May 5, 2010 report. The Utility requests a $1.1 billion revenue increase comprised of increases in electric distribution, utility-owned generation, and gas distribution revenue requirements of $527 million, $329 million, and $208 million, respectively. The DRA’s revised recommendation would result in a total revenue requirement increase of $181 million comprised of electric distribution and utility-owned generation increases of $144 million and $49 million, respectively, and a gas distribution revenue requirement reduction of $12 million.

The $883 million difference between the Utility’s request and the DRA’s recommendation reflects reductions in all cost categories including operating and maintenance costs, administrative and general expense, and capital investments. Among other assumptions as to future costs which differ from the Utility’s request, the DRA has assumed that the Utility would connect fewer customers, undertake less preventative maintenance, and replace aging equipment more slowly. The DRA has also recommended reductions in employee benefit costs and other overhead costs. The DRA recommends funding the Utility’s electric and gas distribution, and existing electric generation capital expenditures at approximately $2.1 billion in 2011, as compared to the Utility’s projection of average annual capital expenditures of $2.6 billion from 2011 to 2013. (Capital expenditures related to the GRC do not include projected capital spending related to electric and gas transmission and other separately funded capital projects such as proposed new generation resources.)

The DRA has recommended revised attrition increases of $115 million for 2012 and $106 million for 2013, based on forecasted increases in the consumer price index, as compared to the Utility’s updated forecast of attrition increases of $262 million in 2012 and $334 million in 2013.

According to the CPUC’s procedural schedule, a proposed decision is calendared to be released by November 16, 2010 and a final CPUC decision to be issued by December 16, 2010.

PG&E Corporation and the Utility are unable to predict the amount of the revenue requirements that the CPUC will authorize or whether the current schedule will be maintained.

Electric Transmission Owner Rate Cases

On July 27, 2010, the FERC approved an uncontested settlement of the Utility’s 12^th TO rate case. The settlement sets the Utility’s annual retail transmission base revenue requirement at $875 million effective March 1, 2010. Retail electric rates were adjusted on June 1, 2010 to reflect the revenue requirement adopted in the settlement and the Utility has reserved the difference between revenues collected in the rates requested by the Utility in its TO rate application,

from March 1, 2010 until May 31, 2010, and the rates agreed to in the settlement. As a result, the settlement will not impact the Utility’s results of operations or financial condition. The Utility will refund any over-collected amounts to customers, with interest, through an adjustment to rates in 2011.

On July 28, 2010, the Utility filed an application for its 13^th TO rate case at the FERC requesting an annual retail revenue requirement of approximately $1.0 billion, a $151 million increase over the rates included in the settlement discussed above. This increase is largely driven by the Utility’s expectation to make investments of $765 million in 2010 and $810 million in 2011 in various capital projects, including projects to add transmission capacity, expand automation technology, improve overall system reliability, and maintain and replace equipment at substations. The Utility requested that new rates become effective on October 1, 2010. In accordance with past practice, the Utility expects that the FERC will suspend the requested increase for an additional five months which would result in a March 1, 2011 effective date.

On June 17, 2010, the FERC issued a notice of proposed rulemaking and established a proceeding to examine, among other issues, whether to change the FERC’s existing policy that provides incumbent traditional public utilities a “right of first refusal” to own, construct, and operate transmission facilities within their respective service territories. The rules that the FERC adopts in this proceeding may introduce additional competition from merchant or independent transmission project developers for the construction of certain transmission facilities that does not exist today. The rules that the FERC may adopt are not expected to impact the Utility’s transmission investment in 2010 or 2011.

2011 Gas Transmission and Storage Rate Case

In the Utility’s 2011 gas transmission and storage rate case, the CPUC will determine the rates and terms and conditions of the Utility’s gas transmission and storage services beginning January 1, 2011 and continuing through 2014. On July 29, 2010, a settlement conference was held to discuss a proposed settlement, the terms of which are confidential until the agreement is submitted to the CPUC for approval.

If the CPUC does not issue a final decision by the end of 2010, the rates and terms and conditions of service in effect as of December 31, 2010 will remain in effect, with an automatic 2% escalation in rates, for local transmission only, starting January 1, 2011. The CPUC has amended its procedural schedule to permit a final decision to be issued by the second quarter of 2011 with the authorized revenue requirements retroactive to January 1, 2011. The Utility would be authorized to request permission from the CPUC to adjust rates for the remainder of the year to recover its authorized annual revenues for 2011.

Energy Efficiency Programs and Incentive Ratemaking

The CPUC’s rulemaking proceeding to consider modifications to the existing incentive ratemaking mechanism that would apply to future energy efficiency program cycles is still pending. It is uncertain when the CPUC will issue a decision in this proceeding.

Direct Access

As authorized by California Senate Bill 695, on March 11, 2010, the CPUC adopted a plan to re-open “direct access” on a limited and gradual basis to allow eligible customers of the three California investor-owned utilities to purchase electricity from independent electric service providers rather than from a utility. Effective April 11, 2010, all qualifying non-residential customers became eligible to take direct access service subject to annual and absolute caps. It is estimated that the total amount of direct access that will be allowed in the Utility’s service territory by the end of the four-year phase-in period will be equal to approximately 11% of the Utility’s total annual retail sales at the end of the period, roughly the highest level that was reached before the CPUC suspended direct access. Further legislative action is required to exceed these limits. The adopted phase-in schedule is designed to provide enough lead time for the utilities to account for small shifts in load and avoid unwarranted cost shifting and stranded costs.

2009 Energy Resource Recovery Account Compliance Proceeding

The Utility recovers its electricity procurement costs and the fuel costs for the Utility’s own generation facilities (but excluding the costs of electricity allocated to the Utility’s customers under DWR contracts) through the Energy Resource Recovery Account (“ERRA”), a balancing account that tracks the difference between (1) billed/unbilled ERRA revenues and (2) electric procurement costs incurred under the Utility’s authorized procurement plans. To determine rates used to collect ERRA revenues, each year the CPUC reviews the Utility’s forecasted costs under power purchase agreements and fuel costs and approves a forecasted revenue requirement. The CPUC also performs an annual compliance review of the procurement activities recorded in the ERRA to ensure that the Utility’s procurement activities are in compliance with its approved procurement plans.

On July 9, 2010, the DRA filed testimony in the 2009 ERRA compliance proceeding that recommended that the CPUC disallow $176 million of costs that the DRA estimates the Utility incurred in 2009 to buy power during 110 outages of the Utility’s own generation facilities. The DRA argued that since the Utility did not present evidence of the reasonableness of its outage management activities and the related replacement costs in its initial application and testimony, these costs should be disallowed. On July 16, 2010, the Utility requested that the CPUC strike the DRA’s testimony, noting that the Utility had not been required to provide such evidence in previous ERRA compliance applications, and that the Utility has provided such information through the discovery process.

If the Utility is unable to conclude that the costs the DRA recommends be disallowed are probable of recovery through the ERRA ratemaking mechanism or other cost recovery mechanisms, the Utility would incur a charge to income for the amount of such costs. The Utility continues to believe that these costs are probable of recovery and that it is remote the costs would be disallowed.

CPUC Rulemaking Proceeding Regarding Electric Vehicles

On July 29, 2010, the CPUC approved a decision finding that the California Legislature did not intend that the CPUC regulate providers of electric vehicle charging services as public utilities. However, the decision also finds that the CPUC has authority to regulate aspects of electric vehicle charging services, including rules relating to the deployment of electric vehicles; the terms under which a utility will provide services to the electric vehicle charging provider; retail electricity rates paid by the electric vehicle charging provider to a regulated utility; standards and protocols to ensure functionality and interoperability between utilities and electric vehicle charging providers; and various electricity procurement requirements that apply to electricity service providers generally, such as resource adequacy and renewable energy procurement standards. A second phase of the CPUC proceeding will examine the role of the regulated utility in electric vehicle charging programs, ways to manage the impact of such programs on the electric infrastructure, the cost to customers of such programs, and other issues.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. (See “Risk Factors” in the 2009 Annual Report.) These laws and requirements relate to a broad range of the Utility’s activities, including the discharge of pollutants into the air, water, and soil; the transportation, handling, storage, and disposal of spent nuclear fuel; remediation of hazardous wastes; and the reporting and reduction of carbon dioxide and other GHG emissions. Recent developments since the 2009 Annual Report was filed are discussed below.

Climate Change

The California Global Warming Solutions Act of 2006 (“AB 32”) requires the gradual reduction of GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2012. (See “Environmental Matters” in the 2009 Annual Report.) In December 2008, the California Air Resources Board (“CARB”), the state agency charged with setting and monitoring emission limits, adopted a scoping plan that contains recommendations for achieving the maximum technologically feasible and cost-effective GHG reductions to meet the 2020 reduction target. These recommendations include increasing renewable energy supplies, increasing energy efficiency goals, expanding the use of combined heat and power facilities, and developing a multi-sector cap-and-trade program. On November 2, 2010, Californians will vote on Proposition 23, a ballot initiative that seeks to suspend AB 32. PG&E Corporation and the Utility oppose this ballot initiative and intend to continue working closely with the state Legislature, the CARB, the CPUC, the CEC, and other concerned stakeholders to ensure responsible implementation of AB 32.

In July 2010, PG&E Corporation and the Utility posted their annual Corporate Responsibility and Sustainability Report at http://www.pgecorp.com. This report includes the Utility’s third-party verified GHG emissions data for 2008. (Preliminary emissions data for 2008 was contained in the 2009 Annual Report.) The Corporate Responsibility and Sustainability Report also discusses measures that PG&E Corporation and the Utility are taking to address GHG emissions and to work collaboratively to develop and implement responsible policies and practices related to climate change.

Renewable Energy Resources

In an effort to reduce GHG emissions, California law requires California retail sellers of electricity, such as the Utility, to comply with a renewable portfolio standard (“RPS”) by increasing their deliveries of renewable energy (such as biomass, hydroelectric facilities with a capacity of 30 MW or less, wind, solar, and geothermal energy) each year, so that the amount of electricity delivered from these eligible renewable resources equals at least 20% of their total retail sales by the end of 2010. If a retail seller is unable to meet its target for a particular year, the current CPUC “flexible compliance” rules allow the retail seller to use future energy deliveries from already-executed contracts to satisfy any shortfalls, provided those deliveries occur within three years of the shortfall. For the year ending December 31, 2009, the Utility’s RPS-eligible renewable resource deliveries equaled 14.4% of its total retail electricity sales. Most of the renewable energy that was delivered was purchased by the Utility from third parties, mainly under agreements with qualifying facility generators, irrigation districts and other bilateral contracts. As of June 30, 2010, the Utility believes it will meet the RPS mandate for 2010 through reliance on the CPUC’s flexible compliance rules. The California Legislature also is considering legislation, Senate Bill 722, that proposes to establish a 33% RPS by 2020. The current session of the California Legislature is scheduled to end on August 31, 2010.

Uncertainty still exists regarding whether tradable renewable energy credits (“RECs”), the green attributes of renewable power, can be used to comply with the current RPS requirements. A tradable REC refers to a certificate of proof of the procurement of the green attributes unbundled from the associated energy, which certificate may be transferred to any third party and resold. The CPUC issued a decision in March 2010 which, among other provisions, permits investor-owned utilities to use tradable RECs to comply with up to 25% of their annual RPS procurement target in any year and carry over any excess RECs for compliance in future years. For purposes of computing the annual 25% limit, the CPUC has defined a REC to include not only a transaction for the procurement of unbundled RECs without energy but also a transaction for the procurement of both RECs and energy if the generator’s first point of interconnection is not with a California balancing authority or the energy is not dynamically transferred to a California balancing authority area. As a result, most of the Utility’s existing power purchase contracts with out-of-state renewable generation facilities would be classified as REC-only contracts under the March 2010 decision. After several parties, including the Utility, requested the CPUC to modify its decision the CPUC stayed the effectiveness of its decision and imposed a temporary moratorium on CPUC approval of any power purchase contracts that would be classified as REC-only transactions under its decision. The Utility is unable to predict when the CPUC will act on the petitions and lift the moratorium. In addition, it is uncertain how Senate Bill 722, if it is enacted, would affect the use of RECs in complying with a new higher RPS requirement.

In addition, on June 3, 2010, the CARB, the state agency charged with setting and monitoring emission limits, issued revised draft regulations that propose to establish a renewable electricity standard (“RES”) that would create higher renewable energy requirements than established under the current RPS law. The proposed RES would require all load-serving entities, including the Utility, to meet renewable energy targets of 20% in 2012 through 2014, 24% in 2015 through 2017, 28% in 2018 through 2019, and 33% in 2020 and beyond. Regulated parties would be allowed to use an unlimited number of unbundled RECs to comply with the new RES, but unlike the definition of RECs adopted by the CPUC, the associated energy would not have to be purchased or delivered into California. Under the proposed RES, penalties could be imposed for failure to meet one of the RES compliance interval targets. The CARB has postponed its vote on the new RES regulations until September 23, 2010 to accommodate the ongoing legislative discussions about Senate Bill 722.

Water Quality

There is continuing uncertainty about the status of state and federal regulations issued under Section 316(b) of the Clean Water Act, which require that cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, reflect the best technology available to minimize adverse environmental impacts. Although the EPA has not yet issued revised regulations, on May 4, 2010, the California Water Resources Control Board (“Water Board”) adopted a policy on once-through cooling. The policy, which is subject to approval by the California Office of Administrative Law, generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities by at least 85%. However, with respect to the state’s nuclear power generation facilities, the policy allows other compliance measures to be taken if the costs to install cooling towers are “wholly out of proportion” to the costs considered by the Water Board in developing its policy or if the installation of cooling towers would be “wholly unreasonable” after considering non-cost factors such as engineering and permitting constraints and adverse environmental impacts. The Utility believes that the costs to install cooling towers at Diablo Canyon, which could be as much as $4.5 billion, will meet the “wholly out of proportion” test. The Utility also believes that the installation of cooling towers at Diablo Canyon would be “wholly unreasonable.” If the Water Board disagreed and if the installation of cooling towers at Diablo Canyon were not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge. (See Note 16 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report for more information.) Assuming the Water Board does not require the installation of cooling towers at Diablo Canyon, the Utility could incur significant costs to comply with alternative compliance measures or to make payments to support various environmental mitigation projects. The Utility would seek to recover such costs in rates. The Utility’s Diablo Canyon operations must be in compliance with the Water Board’s policy by December 31, 2024.

Remediation

The Utility has a program, in cooperation with the California Environmental Protection Agency, to evaluate and take appropriate action to mitigate any potential environmental concerns posed by certain former MGPs located throughout the Utility’s service territory. Of the 41 MGP sites owned or operated by the Utility, 33 have been or are in the process of being remediated. The Utility has notified the owners of properties located on the remaining eight sites and offered to test the soil for residues, and depending on the results of such tests, to take appropriate remedial action. Two of these sites are located in urban, residential areas of San Francisco and one site is located in a predominantly commercial area of San Francisco. Although the Utility has entered into or is negotiating site access agreements with some of the property owners, others have not responded to the Utility’s offer. Until its investigation is complete, the extent of its obligation to remediate is established, and appropriate remedial actions are determined, the Utility is unable to estimate the ultimate amount it may incur with respect to the remediation of these sites. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements, for a discussion of estimated environmental remediation liabilities.)

OTHER MATTERS

SmartMeter^TM Technology

The CPUC has authorized the Utility to recover $2.2 billion in estimated project costs, including $1.8 billion of capital expenditures to install approximately 10 million advanced electric and gas meters throughout the Utility’s service territory by the end of 2012. In addition, the Utility can recover in rates 90% of up to $100 million in costs that exceed the authorized $2.2 billion without a reasonableness review by the CPUC. The remaining 10% will not be recoverable in rates. If additional costs exceed the $100 million threshold, the Utility may request recovery of the additional costs, subject to a reasonableness review. As of June 30, 2010, the Utility has incurred $ 1.7 billion in connection with its SmartMeter™ program.

Advanced electric meters, which record energy usage in hourly or quarter-hourly increments, allow customers to track energy usage throughout the billing month and thus enable greater customer control over electricity costs. Usage data is collected through a wireless communication network and transmitted to the Utility’s information system where the data is stored and used for billing and other Utility business purposes. These meters will allow the implementation of “dynamic pricing” rates that the CPUC has ordered the Utility to implement. Dynamic pricing rates are designed to reflect the cost of electricity production during periods of high demand.

As of June 30, 2010, the Utility has installed approximately 6.1 million meters. Based on the tests that the Utility has performed, more than 99% of the meters perform accurately and as designed. The Utility found that a small percentage of the meters recorded inaccurate energy usage, were not properly installed, or were affected by issues relating to the meter’s data storage capabilities or wireless communication features. The Utility continues to believe that there is no design defect in the technology and that the SmartMeter^™ system is performing within expectations. When issues are identified, the Utility is taking prompt action with the technology and services vendors to remediate the issues. In addition, the Utility has implemented new pre-installation quality control procedures. The Utility also has increased its customer education and outreach efforts, including posting weekly data reports on its website to inform customers and the public about the status of the Utility’s continuing assessment.

An independent consultant selected by CPUC has been assessing the Utility’s SmartMeter™ program, including meter and billing accuracy, customer complaints, end-to-end operational processes, and overall program planning and performance. It is expected that the independent CPUC assessment will be completed before the end of August 2010.

On June 17, 2010, the City and County of San Francisco (“CCSF”) filed a petition requesting the CPUC to impose a temporary moratorium on the installation of additional SmartMeter™ devices until the CPUC has completed its independent assessment. The CPUC has not yet ruled on this request. Several other municipalities and counties in the Utility’s service territory support CCSF’S request for a moratorium or have indicated that they are considering taking other action to regulate or prohibit the installation of SmartMeter^™ devices in their communities. The CPUC is also considering a request for a moratorium filed by a private group on April 15, 2010 until the CPUC conducts an evidentiary hearing on the potential health, environmental, and safety impacts of the radio frequency technology used in the Utility’s SmartMeter™ program. The class action lawsuit filed against the Utility in the Superior Court in Bakersfield, California, containing allegations that the new meters, wireless network, and software and billing system have led to electric bill overcharges, remains stayed pending the results of the CPUC’s investigation.

A California State Senate committee is continuing to investigate and review the deployment of the “smart grid” throughout California, focusing on the Utility’s SmartMeter™ program and the integrity and reliability of new metering technologies and the consumer protections in place with respect to billing, disconnection, and real-time pricing. The Utility has provided all requested information to the committee about the installed meters. The committee is expected to submit its report to the California Senate, including recommendations for appropriate legislation, by November 30, 2010.

On June 1, 2010, a federal class action complaint was filed in San Francisco federal court alleging that the new meters report electric consumption in amounts materially greater than the electricity that the class members actually consumed, resulting in electric bill overcharges. The lawsuit names the various companies that have supplied SmartMeter™ devices, components, and software to the Utility but does not name the Utility as a defendant. The defendants have not yet responded to the complaint.

The Utility is continuing to install the new meters. The outcome of the matters discussed above may have an effect on the Utility’s ability to recover costs to implement advanced metering if the CPUC finds that the costs are not reasonable or are otherwise disallowed. Further, if the Utility is prohibited from continuing to install the new meters or if the Utility otherwise fails to recognize the expected benefits of its advanced metering infrastructure, PG&E Corporation’s and the Utility’s financial condition, results of operations or cash flows could be materially adversely affected.

RISK MANAGEMENT ACTIVITIES

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

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

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

Price Risk

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

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

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

The Utility’s value-at-risk calculated under the methodology described above was $17 million at June 30, 2010. The Utility’s high, low, and average values-at-risk at June 30, 2010 were $18 million, $10 million, and $14 million, respectively.

See Note 7 of the Notes to the Condensed Consolidated Financial Statements for further discussion of price risk management activities.

Interest Rate Risk

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At June 30, 2010, if interest rates changed by 1% for all current PG&E Corporation and the Utility variable rate and short-term debt and investments, the change would affect net income for the next 12 months by $9 million, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

Credit Risk

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

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

The following table summarizes the Utility’s net credit risk exposure to its counterparties, as well as the Utility’s credit risk exposure to counterparties accounting for greater than 10% net credit exposure, as of June 30, 2010 and December 31, 2009:


(in millions)	Gross Credit Exposure Before Credit Collateral⁽¹⁾		Credit Collateral		Net Credit Exposure⁽²⁾		Number of Wholesale Customers or Counterparties >10%	Net Exposure to Wholesale Customers or Counterparties >10%
June 30, 2010	$	189	$	36	$	153	2	$	124
December 31, 2009	$	202	$	24	$	178	3	$	154

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

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

CRITICAL ACCOUNTING POLICIES

The preparation of Condensed Consolidated Financial Statements in accordance with U.S. generally accepted accounting principles involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting policies, due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ substantially from these estimates. These policies and their key characteristics are discussed in detail in the 2009 Annual Report. They include:

•

regulatory assets and liabilities;

•

environmental remediation liabilities;

•

asset retirement obligations;

•

accounting for income taxes; and

•

pension and other postretirement plans.

For the six-months ended June 30, 2010, there were no changes in the methodology for computing critical accounting estimates, no additional accounting estimates met the standards for critical accounting policies, and no material changes to the important assumptions underlying the critical accounting estimates.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4. CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of June 30, 2010, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities Exchange Act of 1934 (“1934 Act”) is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the 1934 Act is accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal control over financial reporting that occurred during the quarter ended June 30, 2010 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Diablo Canyon Power Plant

On May 4, 2010, the Water Board adopted a policy on once-through cooling. The policy, which is subject to approval by the California Office of Administrative Law, generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities by at least 85%. However, with respect to the state’s nuclear power generation facilities, the policy allows other compliance measures to be taken if the costs to install cooling towers are “wholly out of proportion” to the costs considered by the Water Board in developing its policy or if the installation of cooling towers would be “wholly unreasonable” after considering non-cost factors such as engineering and permitting constraints and adverse environmental impacts. The policy could affect future negotiations between the Water Board and the Utility regarding the status of the 2003 settlement agreement concerning a proposed draft Cease and Desist Order issued by the Water Board against the Utility. For more information about the settlement agreement, see PG&E Corporation’s and the Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2009. For more information about the state once-through cooling policy, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Environmental Matters – Water Quality” above.

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

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

During the quarter ended June 30, 2010, PG&E Corporation made equity contributions totaling $110 million to the Utility in order to maintain the 52% common equity component of its CPUC-authorized capital structure and to ensure that the Utility has adequate capital to fund its capital expenditures.

During the quarter ended June 30, 2010, PG&E Corporation issued 16,370,779 shares of common stock at a conversion price of $15.09 per share in unregistered offerings upon the conversion of $247 million principal amount of PG&E Corporation Convertible Subordinated Notes originally issued in an unregistered offering in 2002. The Utility did not make any sales of unregistered equity securities during the quarter ended June 30, 2010.

Issuer Purchases of Equity Securities

During the quarter ended June 30, 2010, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the quarter ended June 30, 2010, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

ITEM 5. OTHER INFORMATION

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

The Utility’s earnings to fixed charges ratio for the six months ended June 30, 2010 was 3.55. The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the six months ended June 30, 2010 was 3.48. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and Exhibits into the Utility’s Registration Statement Nos. 33-62488 and 333-149361 relating to various series of the Utility’s first preferred stock and its senior notes, respectively.

PG&E Corporation’s earnings to fixed charges ratio for the six months ended June 30, 2010 was 3.28. The statement of the foregoing ratio, together with the statement of the computation of the foregoing ratio filed as Exhibit 12.3 hereto, is included herein for the purpose of incorporating such information and Exhibit into PG&E Corporation’s Registration Statement No. 333-149360 relating to its senior notes.

ITEM 6. EXHIBITS


4		Ninth Supplemental Indenture dated as of April 1, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Current Report on Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)

*10.1		PG&E Corporation 2006 Long-Term Incentive Plan, as amended May 12, 2010

10.2		Credit Agreement dated June 8, 2010, among (1) Pacific Gas and Electric Company, as borrower, (2) Wells Fargo Bank, N.A., as administrative agent and a lender, (3) The Royal Bank of Scotland plc, as syndication agent and a lender, (4) Banco Bilbao Vizcaya Argentaria, S.A., New York Branch, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, and U.S. Bank, N.A., as documentation agents and lenders, and (5) the following other lenders: Bank of America, N.A., Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, New York Branch, Goldman Sachs Bank USA, Mizuho Corporate Bank (USA), Morgan Stanley Bank, N.A., Royal Bank of Canada, UBS Loan Finance LLC, Citibank, N.A., East West Bank, RBC Bank (USA), JPMorgan Chase Bank, N.A., and The Northern Trust Company.

12.1		Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company

12.2		Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company

12.3		Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation

31.1		Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002

**32.1		Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002

**32.2		Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

***101.INS		XBRL Instance Document

***101.SCH		XBRL Taxonomy Extension Schema

***101.CAL		XBRL Taxonomy Extension Calculation

***101.DEF		XBRL Extension Definition

***101.LAB		XBRL Taxonomy Extension Label

***101.PRE		XBRL Taxonomy Extension Presentation

*	Management contract or compensatory agreement.

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

***

Pursuant to Rule 406T of SEC Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under these sections. These files are being submitted only by PG&E Corporation and not by its subsidiary, Pacific Gas and Electric Company.

SIGNATURES

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

PG&E CORPORATION

KENT M. HARVEY

Kent M. Harvey

Senior Vice President and Chief Financial Officer

(duly authorized officer and principal financial officer)

PACIFIC GAS AND ELECTRIC COMPANY

SARA A. CHERRY

Sara A. Cherry

Vice President, Finance and Chief Financial Officer

(duly authorized officer and principal financial officer)

Dated: August 4, 2010

EXHIBIT INDEX


4		Ninth Supplemental Indenture dated as of April 1, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Current Report on Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)

*10.1		PG&E Corporation 2006 Long-Term Incentive Plan, as amended May 12, 2010

10.2		Credit Agreement dated June 8, 2010, among (1) Pacific Gas and Electric Company, as borrower, (2) Wells Fargo Bank, N.A., as administrative agent and a lender, (3) The Royal Bank of Scotland plc, as syndication agent and a lender, (4) Banco Bilbao Vizcaya Argentaria, S.A., New York Branch, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, and U.S. Bank, N.A., as documentation agents and lenders, and (5) the following other lenders: Bank of America, N.A., Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, New York Branch, Goldman Sachs Bank USA, Mizuho Corporate Bank (USA), Morgan Stanley Bank, N.A., Royal Bank of Canada, UBS Loan Finance LLC, Citibank, N.A., East West Bank, RBC Bank (USA), JPMorgan Chase Bank, N.A., and The Northern Trust Company.

12.1		Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company

12.2		Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company

12.3		Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation

31.1		Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002

**32.1		Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002

**32.2		Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

***101.INS		XBRL Instance Document

***101.SCH		XBRL Taxonomy Extension Schema

***101.CAL		XBRL Taxonomy Extension Calculation

***101.DEF		XBRL Extension Definition

***101.LAB		XBRL Taxonomy Extension Label

***101.PRE		XBRL Taxonomy Extension Presentation

*	Management contract or compensatory agreement.

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

***

PACIFIC GAS & ELECTRIC Co - FORM 10-Q - August 4, 2010

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