Edgar Filing: PACIFIC GAS & ELECTRIC Co

form10q.htm


UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C., 20549 FORM 10-Q
(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2012 OR

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

For the transition period from ___________ to __________

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

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

Pacific Gas and Electric Company 77 Beale Street P.O. Box 770000 San Francisco, California 94177 ________________________________________				PG&E Corporation 77 Beale Street P.O. Box 770000 San Francisco, California 94177 ______________________________________
Address of principal executive offices, including zip code

Pacific Gas and Electric Company (415) 973-7000 ________________________________________				PG&E Corporation (415) 267-7000 ______________________________________
Registrant's telephone number, including area code

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
PG&E Corporation:				[X] Yes [ ] No
Pacific Gas and Electric Company:				[X] Yes [ ] No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
PG&E Corporation:			[X] Large accelerated filer		[ ] Accelerated filer
			[ ] Non-accelerated filer		[ ] Smaller reporting company
Pacific Gas and Electric Company:			[ ] Large accelerated filer		[ ] Accelerated filer
			[X] Non-accelerated filer		[ ] Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation:				[ ] Yes [X] No
Pacific Gas and Electric Company:				[ ] Yes [X] No

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
Common stock outstanding as of October 25, 2012:
PG&E Corporation:				429,984,324
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 SEPTEMBER 30, 2012

TABLE OF CONTENTS


PART I.	FINANCIAL INFORMATION		PAGE
ITEM 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	PG&E Corporation
	Condensed Consolidated Statements of Income		3
	Condensed Consolidated Statements of Comprehensive Income		4
	Condensed Consolidated Balance Sheets		5
	Condensed Consolidated Statements of Cash Flows		7
	Pacific Gas and Electric Company
	Condensed Consolidated Statements of Income		8
	Condensed Consolidated Statements of Comprehensive Income		9
	Condensed Consolidated Balance Sheets		10
	Condensed Consolidated Statements of Cash Flows		12
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:	Organization and Basis of Presentation	13
	NOTE 2:	Significant Accounting Policies	13
	NOTE 3:	Regulatory Assets, Liabilities, and Balancing Accounts	16
	NOTE 4:	Debt	19
	NOTE 5:	Equity	20
	NOTE 6:	Earnings Per Share	21
	NOTE 7:	Derivatives	21
	NOTE 8:	Fair Value Measurements	24
	NOTE 9:	Resolution of Remaining Chapter 11 Disputed Claims	29
	NOTE 10:	Commitments and Contingencies	30

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview		39
	Cautionary Language Regarding Forward-Looking Statements		41
	Results of Operations		44
	Liquidity and Financial Resources		49
	Contractual Commitments		53
	Capital Expenditures		53
	Natural Gas Matters		53
	Regulatory Matters		57
	Environmental Matters		60
	Off-Balance Sheet Arrangements		62
	Contingencies		62
	Risk Management Activities		62
	Critical Accounting Policies		64

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		68
ITEM 4.	CONTROLS AND PROCEDURES		68

PART II.	OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS		69
ITEM 1A.	RISK FACTORS		70
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		70
ITEM 5.	OTHER INFORMATION		70
ITEM 6.	EXHIBITS		71

SIGNATURES			72

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in millions, except per share amounts)	2012			2011			2012			2011
Operating Revenues
Electric	$	3,323		$	3,188		$	9,026		$	8,694
Natural gas		653			672			2,184			2,447
Total operating revenues		3,976			3,860			11,210			11,141
Operating Expenses
Cost of electricity		1,283			1,224			3,104			3,018
Cost of natural gas		118			170			593			936
Operating and maintenance		1,344			1,492			4,138			3,955
Depreciation, amortization, and decommissioning		617			566			1,807			1,648
Total operating expenses		3,362			3,452			9,642			9,557
Operating Income		614			408			1,568			1,584
Interest income		2			2			6			7
Interest expense		(178	)		(176	)		(528	)		(527	)
Other income, net		26			18			84			56
Income Before Income Taxes		464			252			1,130			1,120
Income tax provision		100			49			291			349
Net Income		364			203			839			771
Preferred stock dividend requirement of subsidiary		3			3			10			10
Income Available for Common Shareholders	$	361		$	200		$	829		$	761
Weighted Average Common Shares Outstanding, Basic		428			403			422			399
Weighted Average Common Shares Outstanding, Diluted		429			404			423			400
Net Earnings Per Common Share, Basic	$	0.84		$	0.50		$	1.96		$	1.91
Net Earnings Per Common Share, Diluted	$	0.84		$	0.50		$	1.96		$	1.90
Dividends Declared Per Common Share	$	0.46		$	0.46		$	1.37		$	1.37

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in millions)	2012			2011			2012			2011
Net Income	$	364		$	203		$	839		$	771
Other Comprehensive Income
Pension and other postretirement benefit plans
Unrecognized prior service credit (net of income tax of $5 and $7 in the three months ended September 30, 2012 and 2011, respectively, and $15 and $18 in the nine months ended September 30, 2012 and 2011, respectively)		7			9			19			28
Unrecognized net gain (net of income tax of $12 and $6 in the three months ended September 30, 2012 and 2011, respectively, and $38 and $17 in the nine months ended September 30, 2012 and 2011, respectively)		18			8			58			23
Unrecognized net transition obligation (net of income tax of $2 and $3 in the three months ended September 30, 2012 and 2011, respectively, and $6 and $7 in the nine months ended September 30, 2012 and 2011, respectively)		4			4			12			12
Transfer to regulatory account (net of income tax of $14 and $8 in the three months ended September 30, 2012 and 2011, respectively, and $44 and $26 in the nine months ended September 30, 2012 and 2011, respectively)		(21	)		(13	)		(63	)		(37	)
Total other comprehensive income		8			8			26			26
Comprehensive Income		372			211			865			797
Preferred stock dividend requirement of subsidiary		3			3			10			10
Comprehensive Income Attributable to Common Shareholders	$	369		$	208		$	855		$	787

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance at
	September 30,			December 31,
(in millions)	2012			2011
ASSETS
Current Assets
Cash and cash equivalents	$	296		$	513
Restricted cash ($88 and $51 related to energy recovery bonds at September 30, 2012 and December 31, 2011, respectively)		418			380
Accounts receivable
Customers (net of allowance for doubtful accounts of $85 and $81 at September 30, 2012 and December 31, 2011, respectively)		1,185			992
Accrued unbilled revenue		779			763
Regulatory balancing accounts		908			1,082
Other		665			839
Regulatory assets ($0 and $336 related to energy recovery bonds at September 30, 2012 and December 31, 2011, respectively)		567			1,090
Inventories
Gas stored underground and fuel oil		158			159
Materials and supplies		296			261
Income taxes receivable		19			183
Other		302			218
Total current assets		5,593			6,480
Property, Plant, and Equipment
Electric		37,635			35,851
Gas		12,280			11,931
Construction work in progress		2,095			1,770
Other		1			15
Total property, plant, and equipment		52,011			49,567
Accumulated depreciation		(16,361	)		(15,912	)
Net property, plant, and equipment		35,650			33,655
Other Noncurrent Assets
Regulatory assets		6,527			6,506
Nuclear decommissioning trusts		2,155			2,041
Income taxes receivable		333			386
Other		610			682
Total other noncurrent assets		9,625			9,615
TOTAL ASSETS	$	50,868		$	49,750

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance at
	September 30,			December 31,
(in millions)	2012			2011
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	397		$	1,647
Long-term debt, classified as current		-			50
Energy recovery bonds, classified as current		110			423
Accounts payable
Trade creditors		1,054			1,177
Disputed claims and customer refunds		164			673
Regulatory balancing accounts		459			374
Other		423			420
Interest payable		821			843
Income taxes payable		15			110
Deferred income taxes		-			196
Other		1,993			1,836
Total current liabilities		5,436			7,749
Noncurrent Liabilities
Long-term debt		12,915			11,766
Regulatory liabilities		5,107			4,733
Pension and other postretirement benefits		3,570			3,396
Asset retirement obligations		1,661			1,609
Deferred income taxes		6,724			6,008
Other		2,070			2,136
Total noncurrent liabilities		32,047			29,648
Commitments and Contingencies (Note 10)
Equity
Shareholders’ Equity
Preferred stock		-			-
Common stock, no par value, authorized 800,000,000 shares, 429,357,175 shares outstanding at September 30, 2012 and 412,257,082 shares outstanding at December 31, 2011		8,362			7,602
Reinvested earnings		4,957			4,712
Accumulated other comprehensive loss		(186	)		(213	)
Total shareholders’ equity		13,133			12,101
Noncontrolling Interest – Preferred Stock of Subsidiary		252			252
Total equity		13,385			12,353
TOTAL LIABILITIES AND EQUITY	$	50,868		$	49,750

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Nine Months Ended
	September 30,
(in millions)	2012			2011
Cash Flows from Operating Activities
Net income	$	839		$	771
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,807			1,648
Allowance for equity funds used during construction		(79	)		(64	)
Deferred income taxes and tax credits, net		624			552
Other		230			223
Effect of changes in operating assets and liabilities:
Accounts receivable		(326	)		(186	)
Inventories		(34	)		(60	)
Accounts payable		(55	)		93
Income taxes receivable/payable		69			(71	)
Other current assets and liabilities		16			(170	)
Regulatory assets, liabilities, and balancing accounts, net		66			70
Other noncurrent assets and liabilities		295			426
Net cash provided by operating activities		3,452			3,232
Cash Flows from Investing Activities
Capital expenditures		(3,361	)		(2,968	)
(Increase) decrease in restricted cash		(38	)		170
Proceeds from sales and maturities of nuclear decommissioning trust investments		903			1,574
Purchases of nuclear decommissioning trust investments		(964	)		(1,604	)
Other		101			(102	)
Net cash used in investing activities		(3,359	)		(2,930	)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities		-			358
Repayments under revolving credit facilities		-			(283	)
Net (repayments) issuances of commercial paper, net of discount of $3 in 2012 and $2 in 2011		(1,247	)		196
Proceeds from issuance of long-term debt, net of discount and issuance costs of $10 in 2012 and $6 in 2011		1,140			544
Long-term debt matured or repurchased		(50	)		(700	)
Energy recovery bonds matured		(313	)		(299	)
Common stock issued, net of issuance costs of $3 in 2012 and $2 in 2011		702			391
Common stock dividends paid		(556	)		(525	)
Other		14			2
Net cash used in financing activities		(310	)		(316	)
Net change in cash and cash equivalents		(217	)		(14	)
Cash and cash equivalents at January 1		513			291
Cash and cash equivalents at September 30	$	296		$	277
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(486	)	$	(536	)
Income taxes, net		114			8
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	195		$	184
Capital expenditures financed through accounts payable		228			225
Noncash common stock issuances		18			18
Terminated capital leases		136			-

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in millions)	2012			2011			2012			2011
Operating Revenues
Electric	$	3,321		$	3,187		$	9,022		$	8,691
Natural gas		653			672			2,184			2,447
Total operating revenues		3,974			3,859			11,206			11,138
Operating Expenses
Cost of electricity		1,283			1,224			3,104			3,018
Cost of natural gas		118			170			593			936
Operating and maintenance		1,343			1,497			4,134			3,951
Depreciation, amortization, and decommissioning		617			566			1,807			1,648
Total operating expenses		3,361			3,457			9,638			9,553
Operating Income		613			402			1,568			1,585
Interest income		2			2			5			6
Interest expense		(172	)		(171	)		(511	)		(511	)
Other income, net		19			19			64			52
Income Before Income Taxes		462			252			1,126			1,132
Income tax provision		122			56			328			376
Net Income		340			196			798			756
Preferred stock dividend requirement		3			3			10			10
Income Available for Common Stock	$	337		$	193		$	788		$	746

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
(in millions)	2012			2011			2012			2011
Net Income	$	340		$	196		$	798		$	756
Other Comprehensive Income
Pension and other postretirement benefit plans
Unrecognized prior service credit (net of income tax of $5 and $7 in the three months ended September 30, 2012 and 2011, respectively, and $15 and $18 in the nine months ended September 30, 2012 and 2011, respectively)		7			9			19			28
Unrecognized net gain (net of income tax of $12 and $6 in the three months ended September 30, 2012 and 2011, respectively, and $38 and $17 in the nine months ended September 30, 2012, and 2011, respectively)		18			8			58			23
Unrecognized net transition obligation (net of income tax of $2 and $3 in the three months ended September 30, 2012 and 2011, respectively, and $6 and $7 in the nine months ended September 30, 2012 and 2011, respectively)		4			4			12			12
Transfer to regulatory account (net of income tax of $14 and $8 in the three months ended September 30, 2012 and 2011, respectively, and $44 and $26 in the nine months ended September 30, 2012 and 2011, respectively)		(21	)		(13	)		(63	)		(37	)
Total other comprehensive income		8			8			26			26
Comprehensive Income	$	348		$	204		$	824		$	782

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance at
	September 30,			December 31,
(in millions)	2012			2011
ASSETS
Current Assets
Cash and cash equivalents	$	86		$	304
Restricted cash ($88 and $51 related to energy recovery bonds at September 30, 2012 and December 31, 2011, respectively)		418			380
Accounts receivable
Customers (net of allowance for doubtful accounts of $85 and $81 at September 30, 2012 and December 31, 2011, respectively)		1,185			992
Accrued unbilled revenue		779			763
Regulatory balancing accounts		908			1,082
Other		667			840
Regulatory assets ($0 and $336 related to energy recovery bonds at September 30, 2012 and December 31, 2011, respectively)		567			1,090
Inventories
Gas stored underground and fuel oil		158			159
Materials and supplies		296			261
Income taxes receivable		-			242
Other		295			213
Total current assets		5,359			6,326
Property, Plant, and Equipment
Electric		37,635			35,851
Gas		12,280			11,931
Construction work in progress		2,095			1,770
Total property, plant, and equipment		52,010			49,552
Accumulated depreciation		(16,360	)		(15,898	)
Net property, plant, and equipment		35,650			33,654
Other Noncurrent Assets
Regulatory assets		6,527			6,506
Nuclear decommissioning trusts		2,155			2,041
Income taxes receivable		331			384
Other		324			331
Total other noncurrent assets		9,337			9,262
TOTAL ASSETS	$	50,346		$	49,242

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	September 30,			December 31,
(in millions, except share amounts)	2012			2011
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings	$	397		$	1,647
Long-term debt, classified as current		-			50
Energy recovery bonds, classified as current		110			423
Accounts payable
Trade creditors		1,054			1,177
Disputed claims and customer refunds		164			673
Regulatory balancing accounts		459			374
Other		444			417
Interest payable		811			838
Income taxes payable		29			118
Deferred income taxes		-			199
Other		1,777			1,628
Total current liabilities		5,245			7,544
Noncurrent Liabilities
Long-term debt		12,566			11,417
Regulatory liabilities		5,107			4,733
Pension and other postretirement benefits		3,496			3,325
Asset retirement obligations		1,661			1,609
Deferred income taxes		6,888			6,160
Other		2,006			2,070
Total noncurrent liabilities		31,724			29,314
Commitments and Contingencies (Note 10)
Shareholders’ Equity
Preferred stock		258			258
Common stock, $5 par value, authorized 800,000,000 shares, 264,374,809 shares outstanding at September 30, 2012 and December 31, 2011		1,322			1,322
Additional paid-in capital		4,511			3,796
Reinvested earnings		7,461			7,210
Accumulated other comprehensive loss		(175	)		(202	)
Total shareholders’ equity		13,377			12,384
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	50,346		$	49,242

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Nine Months Ended
	September 30,
(in millions)	2012			2011
Cash Flows from Operating Activities
Net income	$	798		$	756
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning		1,807			1,648
Allowance for equity funds used during construction		(79	)		(64	)
Deferred income taxes and tax credits, net		633			564
Other		189			193
Effect of changes in operating assets and liabilities:
Accounts receivable		(327	)		(125	)
Inventories		(34	)		(60	)
Accounts payable		(31	)		97
Income taxes receivable/payable		153			(156	)
Other current assets and liabilities		15			(153	)
Regulatory assets, liabilities, and balancing accounts, net		66			70
Other noncurrent assets and liabilities		315			491
Net cash provided by operating activities		3,505			3,261
Cash Flows from Investing Activities
Capital expenditures		(3,361	)		(2,968	)
(Increase) decrease in restricted cash		(38	)		170
Proceeds from sales and maturities of nuclear decommissioning trust investments		903			1,574
Purchases of nuclear decommissioning trust investments		(964	)		(1,604	)
Other		14			13
Net cash used in investing activities		(3,446	)		(2,815	)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities		-			208
Repayments under revolving credit facilities		-			(208	)
Net (repayments) issuances of commercial paper, net of discount of $3 in 2012 and $2 in 2011		(1,247	)		196
Proceeds from issuance of long-term debt, net of discount and issuance costs of $10 in 2012 and $6 in 2011		1,140			544
Long-term debt matured or repurchased		(50	)		(700	)
Energy recovery bonds matured		(313	)		(299	)
Preferred stock dividends paid		(10	)		(10	)
Common stock dividends paid		(537	)		(537	)
Equity contribution		715			350
Other		25			12
Net cash used in financing activities		(277	)		(444	)
Net change in cash and cash equivalents		(218	)		2
Cash and cash equivalents at January 1		304			51
Cash and cash equivalents at September 30	$	86		$	53
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(476	)	$	(525	)
Income taxes, net		174			6
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	228		$	225
Terminated capital leases		136			-

See accompanying Notes to the Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

PG&E Corporation is a holding company that conducts its business through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is regulated by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). In addition, the Nuclear Regulatory Commission (“NRC”) oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. The Utility’s accounts for electric and gas operations are maintained in accordance with the Uniform System of Accounts prescribed by the FERC.

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

The accompanying Condensed Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial statements and in accordance with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X promulgated by the Securities and Exchange Commission (“SEC”) and therefore do not contain all of the information and footnotes required by GAAP and the SEC for annual financial statements. PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of their financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2011 in both PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets incorporated by reference into their combined 2011 Annual Report on Form 10-K filed with the SEC on February 16, 2012. PG&E Corporation’s and the Utility’s combined 2011 Annual Report on Form 10-K, together with the information incorporated by reference into such report, is referred to in this quarterly report as the “2011 Annual Report.” This quarterly report should be read in conjunction with the 2011 Annual Report.

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

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies used by PG&E Corporation and the Utility are discussed in Note 2 of the Notes to the Consolidated Financial Statements in the 2011 Annual Report.

Pension and Other Postretirement Benefits

PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees and retirees (referred to collectively as “pension benefits”) and contributory postretirement medical plans for eligible employees and retirees and their eligible dependents and non-contributory postretirement life insurance plans for eligible employees and retirees (referred to collectively as “other benefits”). PG&E Corporation and the Utility have elected that certain of the trusts underlying these plans be treated under the Internal Revenue Code of 1986, as amended (“Code”), as qualified trusts. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain Code limitations. PG&E Corporation and the Utility use a December 31 measurement date for all plans.

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2012 and 2011 were as follows:

	Pension Benefits						Other Benefits
	Three Months Ended						Three Months Ended
	September 30,						September 30,
(in millions)	2012			2011			2012			2011
Service cost for benefits earned	$	100		$	76		$	14		$	9
Interest cost		165			167			21			23
Expected return on plan assets		(150	)		(168	)		(19	)		(22	)
Amortization of transition obligation		-			-			6			7
Amortization of prior service cost		5			8			7			8
Amortization of unrecognized loss		29			13			1			1
Net periodic benefit cost		149			96			30			26
Less: transfer to regulatory account (1)		(75	)		(32	)		-			-
Total	$	74		$	64		$	30		$	26

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

	Pension Benefits						Other Benefits
	Nine Months Ended						Nine Months Ended
	September 30,						September 30,
(in millions)	2012			2011			2012			2011
Service cost for benefits earned	$	297		$	240		$	37		$	31
Interest cost		494			495			63			69
Expected return on plan assets		(449	)		(502	)		(58	)		(62	)
Amortization of transition obligation		-			-			18			19
Amortization of prior service cost		15			26			19			20
Amortization of unrecognized loss		92			37			4			3
Net periodic benefit cost		449			296			83			80
Less: transfer to regulatory account (1)		(225	)		(104	)		-			-
Total	$	224		$	192		$	83		$	80

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

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

During 2012, the Pacific Gas and Electric Company Retirement Plan was amended to offer a new cash balance benefit formula. Eligible employees hired after December 31, 2012 will be covered by the new formula. Eligible employees hired before January 1, 2013 will have a one-time opportunity to elect to be covered by the new formula going forward, beginning on January 1, 2014. As long as pension benefit costs continue to be recoverable through customer rates, PG&E Corporation and the Utility anticipate that this amendment will have no impact on net income.

Variable Interest Entities

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

In determining whether consolidation of a particular entity is required, PG&E Corporation and the Utility first evaluate whether the entity is a VIE. If the entity is a VIE, PG&E Corporation and the Utility use a qualitative approach to determine if either is the primary beneficiary of the VIE.

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility subject to the terms of a power purchase agreement. In determining whether the Utility is the primary beneficiary of any of these VIEs, it assesses whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement. This assessment includes an evaluation of how the risks and rewards associated with the power plant’s activities are absorbed by variable interest holders, as well as an analysis of the variability in the VIE’s gross margin and the impact of the power purchase agreement on the gross margin. Under each of these power purchase agreements, the Utility is obligated to purchase electricity or capacity, or both, from the VIE. The Utility does not provide any other support to these VIEs, and the Utility’s financial exposure is limited to the amount it pays for delivered electricity and capacity. (See Note 10 below.) The Utility does not have any decision-making rights associated with the design of these VIEs, nor does the Utility have the power to direct the activities that are most significant to the economic performance of these VIEs such as dispatch rights, operating and maintenance activities, or re-marketing activities of the power plant after the termination of the VIEs’ respective power purchase agreement with the Utility. Since the Utility was not the primary beneficiary of any of these VIEs at September 30, 2012, it did not consolidate any of them.

The Utility continued to consolidate the financial results of PG&E Energy Recovery Funding LLC (“PERF”), another VIE, at September 30, 2012, since the Utility is the primary beneficiary of PERF. PERF was formed in 2005 as a wholly owned subsidiary of the Utility to issue energy recovery bonds (“ERB”s) in connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code (“Chapter 11 Settlement Agreement”). The Utility has a controlling financial interest in PERF since the Utility is exposed to PERF’s losses and returns through the Utility’s 100% equity investment in PERF and the Utility was involved in the design of PERF, which was an activity that was significant to PERF’s economic performance. The assets of PERF were $156 million at September 30, 2012 and primarily consisted of assets related to ERBs. The liabilities of PERF were $111 million at September 30, 2012 and consisted of ERBs, which are included in current liabilities in the Condensed Consolidated Balance Sheets. PERF is expected to be dissolved in 2013, after the ERBs mature. (See Note 4 below.)

At September 30, 2012, PG&E Corporation affiliates had entered into four tax equity agreements to fund residential and commercial retail solar energy installations with two privately held companies that are considered VIEs. Under these agreements, PG&E Corporation has agreed to provide lease payments and investment contributions of up to $396 million to these companies in exchange for the right to receive benefits from local rebates, federal grants, and a share of the customer payments made to these companies. The majority of these amounts are recorded in other noncurrent assets – other in PG&E Corporation’s Condensed Consolidated Balance Sheets. At September 30, 2012, PG&E Corporation had made total payments of $361 million under these agreements and received $225 million in benefits and customer payments. In determining whether PG&E Corporation is the primary beneficiary of any of these VIEs, it assesses which of the variable interest holders has control over these companies’ significant economic activities, such as the design of the companies, vendor selection, construction, customer selection, and re-marketing activities after the termination of customer leases. PG&E Corporation determined that these companies control these activities, while its financial exposure from these agreements is generally limited to its lease payments and investment contributions to these companies. Since PG&E Corporation was not the primary beneficiary of any of these VIEs at September 30, 2012, it did not consolidate any of them.

Adoption of New Accounting Standards

Amendments to Fair Value Measurement Requirements

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

Presentation of Comprehensive Income

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

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

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

The Utility tracks differences between customer billings and the Utility’s authorized revenue requirements for revenue that is independent, or “decoupled,” from the volume of electricity and natural gas sales. The Utility also tracks differences between incurred costs and customer billings or authorized revenue requirements meant to recover those costs. These differences are recorded to regulatory balancing accounts that represent amounts expected to be collected from or refunded to customers. Regulatory balancing accounts that are not expected to be collected from or refunded to customers over the next 12 months are included in other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Condensed Consolidated Balance Sheets.

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

Regulatory Assets

Current Regulatory Assets

At September 30, 2012 and December 31, 2011, the Utility had current regulatory assets of $567 million and $1,090 million, respectively, primarily consisting of the price risk management regulatory asset, the Utility’s retained generation regulatory assets, and the electromechanical meters regulatory asset. At December 31, 2011, current regulatory assets also included regulatory assets related to ERBs.

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

	Balance at
(in millions)	September 30, 2012		December 31, 2011
Pension benefits	$	3,019	$	2,899
Deferred income taxes		1,584		1,444
Utility retained generation		567		613
Environmental compliance costs		576		520
Price risk management		223		339
Electromechanical meters		207		247
Unamortized loss, net of gain, on reacquired debt		147		163
Other		204		281
Total long-term regulatory assets	$	6,527	$	6,506

The regulatory asset for pension benefits represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP and also includes amounts that otherwise would be recorded to accumulated other comprehensive loss in the Condensed Consolidated Balance Sheets. (See Note 12 of the Notes to the Consolidated Financial Statements in the 2011 Annual Report.)

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

In connection with the Chapter 11 Settlement Agreement, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. The weighted average remaining life of the assets is 13 years.

The regulatory asset for environmental compliance costs represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP. The Utility expects to recover these costs over the next 32 years, as the environmental compliance work is performed. (See Note 10 below.)

The regulatory asset for price risk management represents the unrealized losses related to price risk management derivative instruments expected to be recovered as they are realized over the next 10 years as part of the Utility’s energy procurement costs. (See Note 7 below.)

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

The regulatory asset for unamortized loss, net of gain, on reacquired debt represents the expected future recovery of costs related to debt reacquired or redeemed prior to maturity with associated discount and debt issuance costs. These costs are expected to be recovered over the next 14 years, which is the remaining amortization period of the reacquired debt.

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

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

Regulatory Liabilities

Current Regulatory Liabilities

At September 30, 2012 and December 31, 2011, the Utility had current regulatory liabilities of $379 million and $161 million, respectively, consisting of amounts that it expects to refund to customers over the next 12 months, primarily including electricity supplier settlement agreements. (See Note 9 below.) At September 30, 2012, current regulatory liabilities also included a U.S. Department of Energy (“DOE”) settlement agreement. Current regulatory liabilities are included within current liabilities – other in the Condensed Consolidated Balance Sheets.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

	Balance at
(in millions)	September 30, 2012		December 31, 2011
Cost of removal obligations	$	3,595	$	3,460
Recoveries in excess of AROs		649		611
Public purpose programs		613		499
Other		250		163
Total long-term regulatory liabilities	$	5,107	$	4,733

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

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

The regulatory liability for public purpose programs represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs designed to encourage the manufacture, design, distribution, and customer use of energy efficient appliances and other energy-using products, the California Solar Initiative program to promote the use of solar energy in residential homes and commercial, industrial, and agricultural properties, and the Self-Generation Incentive program to promote distributed generation technologies installed on the customer’s side of the utility meter.

At September 30, 2012 and December 31, 2011, “other” primarily consisted of the regulatory liability related to the gain associated with the Utility’s acquisition of the permits and other assets of the Gateway Generating Station as part of the settlement that the Utility entered into with Mirant Corporation, the price risk management regulatory liability representing the unrealized gains associated with price risk management derivative instruments expected to be refunded to customers as they are realized beyond the next 12 months as part of the Utility’s energy procurement costs (see Note 7 below), and the regulatory liability related to the tax benefit associated with SmartMeters.TM

Regulatory Balancing Accounts

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

Current Regulatory Balancing Accounts, Net

	Receivable (Payable)
	Balance at
(in millions)	September 30, 2012			December 31, 2011
Distribution revenue adjustment mechanism	$	92		$	223
Utility generation		68			241
Hazardous substance		56			57
Public purpose programs		53			97
Gas fixed cost		105			16
Energy recovery bonds		(57	)		(105	)
Energy procurement		(19	)		(48	)
Other		151			227
Total regulatory balancing accounts, net	$	449		$	708

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

The hazardous substance balancing accounts are used to record and recover hazardous substance remediation costs that are eligible for recovery through a CPUC-approved ratemaking mechanism. (See Note 10 below.)

The public purpose programs balancing accounts are primarily used to record and recover the authorized revenue requirements associated with administering public purpose programs as well as incentive awards earned by the Utility for achieving regulatory targets in the customer energy efficiency programs. The public purpose programs primarily consist of energy efficiency programs, low-income energy efficiency programs, demand response programs, research, development, and demonstration programs, and renewable energy programs.

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

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

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

At September 30, 2012 and December 31, 2011, “other” consisted of various balancing accounts, such as the SmartMeterTM advanced metering project balancing account, which tracks the recovery of the related authorized revenue requirements and costs, and balancing accounts that track the recovery of authorized meter reading costs.

NOTE 4: DEBT

Revolving Credit Facilities – PG&E Corporation and the Utility

At September 30, 2012, PG&E Corporation had no cash borrowings or letters of credit outstanding under its $300 million revolving credit facility.

At September 30, 2012, the Utility had no cash borrowings and $330 million of letters of credit outstanding under its $3.0 billion revolving credit facility.

Utility

Senior Notes

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

On August 16, 2012, the Utility issued $400 million principal amount of 2.45% Senior Notes due August 15, 2022 and $350 million principal amount of 3.75% Senior Notes due August 15, 2042.

Pollution Control Bonds

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

At September 30, 2012, the interest rates on the $614 million principal amount of pollution control bonds Series 1996 C, E, F, and 1997 B and the related loan agreements ranged from 0.16% to 0.21%. At September 30, 2012, the interest rates on the $309 million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements ranged from 0.17% to 0.20%.

Commercial Paper Program

At September 30, 2012, the Utility had $145 million of commercial paper outstanding.

Other Short-Term Borrowings

At September 30, 2012 the interest rate on the Utility’s $250 million principal amount of Floating Rate Senior Notes, due November 20, 2012, was 0.88%.

Energy Recovery Bonds

At September 30, 2012, the total amount of ERB principal outstanding was $110 million. The ERBs mature on December 25, 2012.

While PERF is a wholly owned consolidated subsidiary of the Utility, it is legally separate from the Utility. The assets, including the right to be paid a specified amount collected through the Utility’s electric rates (known as “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 nine months ended September 30, 2012 were as follows:

	PG&E Corporation			Utility
	Total			Total
(in millions)	Equity			Total Shareholders’ Equity
Balance at December 31, 2011	$	12,353		$	12,384
Comprehensive income		865			824
Common stock issued		720			-
Share-based compensation expense		41			1
Common stock dividends declared		(584	)		(537	)
Preferred stock dividend requirement		-			(10	)
Preferred stock dividend requirement of subsidiary		(10	)		-
Equity contributions		-			715
Balance at September 30, 2012	$	13,385		$	13,377

During the nine months ended September 30, 2012, PG&E Corporation issued 5,446,542 shares of its common stock under its 401(k) plan, its Dividend Reinvestment and Stock Purchase Plan, and its share-based compensation plans for total cash proceeds of $214 million.

During the nine months ended September 30, 2012, PG&E Corporation issued 5,446,760 shares of its common stock under the Equity Distribution Agreement executed in November 2011 for cash proceeds of $234 million, net of fees and commissions of $2 million. At September 30, 2012, PG&E Corporation had the ability to issue an additional $64 million of its common stock under the Equity Distribution Agreement.

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

During the nine months ended September 30, 2012, PG&E Corporation contributed equity of $715 million to the Utility to maintain the Utility’s CPUC-authorized capital structure, which consists of 52% common equity and 48% debt and preferred stock.

NOTE 6: EARNINGS PER SHARE

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in millions, except per share amounts)	2012		2011		2012		2011
Income available for common shareholders	$	361	$	200	$	829	$	761
Weighted average common shares outstanding, basic		428		403		422		399
Add incremental shares from assumed conversions:
Employee share-based compensation		1		1		1		1
Weighted average common shares outstanding, diluted		429		404		423		400
Total earnings per common share, diluted	$	0.84	$	0.50	$	1.96	$	1.90

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

NOTE 7: DERIVATIVES

Use of Derivative Instruments

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

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

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

·	option contracts that provide the Utility with the right to buy a commodity at a predetermined price and option contracts that require payments from counterparties if market prices exceed a predetermined price.

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

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

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

Electricity Procurement

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

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

Electric Transmission Congestion Revenue Rights

The California electric transmission grid, controlled by the California Independent System Operator (“CAISO”), is subject to transmission constraints when there is insufficient transmission capacity to supply the market. The CAISO imposes congestion charges on market participants to manage transmission congestion. The revenue generated from congestion charges is allocated to holders of congestion revenue rights (“CRRs”). CRRs allow market participants to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. The CAISO releases CRRs through an annual and monthly process, each of which includes an allocation phase (in which load-serving entities, such as the Utility, are allocated CRRs at no cost based on the customer demand or “load” they serve) and an auction phase (in which CRRs are priced at market and available to all market participants). The Utility participates in the allocation and auction phases of the annual and monthly CRR processes. CRRs are considered derivatives.

Natural Gas Procurement (Electric Fuels Portfolio)

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

Natural Gas Procurement (Core Gas Supply Portfolio)

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

Volume of Derivative Activity

At September 30, 2012, the volume of PG&E Corporation’s and the Utility’s outstanding derivatives was as follows:

		Contract Volume (1)
Underlying Product	Instruments	Less Than 1 Year		Greater Than 1 Year but Less Than 3 Years		Greater Than 3 Years but Less Than 5 Years		Greater Than 5 Years (2)
Natural Gas (3) (MMBtus (4))	Forwards and Swaps		364,202,485		129,569,788		3,150,000		-
	Options		230,838,408		247,180,353		4,200,000		-
Electricity (Megawatt-hours)	Forwards and Swaps		2,978,823		3,927,621		2,009,505		2,689,804
	Options		-		214,665		239,233		143,857
	Congestion Revenue Rights		53,856,688		75,797,340		74,225,248		34,225,866

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

(2) Derivatives in this category expire between 2017 and 2022.

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

(4) Million British Thermal Units.

Presentation of Derivative Instruments in the Financial Statements

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

At September 30, 2012, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
(in millions)	Gross Derivative Balance			Netting			Cash Collateral		Total Derivative Balance
Current assets – other	$	52		$	(37	)	$	75	$	90
Other noncurrent assets – other		94			(36	)		-		58
Current liabilities – other		(280	)		37			119		(124	)
Noncurrent liabilities – other		(259	)		36			17		(206	)
Total commodity risk	$	(393	)	$	-		$	211	$	(182	)

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

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

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

	Commodity Risk
	Three Months Ended								Nine Months Ended
	September 30,								September 30,
(in millions)	2012				2011				2012				2011
Unrealized gain/(loss) - regulatory assets and liabilities (1)		$	162			$	(61	)		$	327			$	97
Realized gain/(loss) - cost of electricity (2)			(108	)			(149	)			(383	)			(406	)
Realized gain/(loss) - cost of natural gas (2)			(5	)			(4	)			(32	)			(66	)
Total commodity risk		$	49			$	(214	)		$	(88	)		$	(375	)

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

The majority of the Utility’s derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. At September 30, 2012, the Utility’s credit rating was investment grade. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to collateralize fully some of its net liability derivative positions.

At September 30, 2012, the additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows:

(in millions)
Derivatives in a liability position with credit risk-related contingencies that are not fully collateralized	$	(325	)
Related derivatives in an asset position		74
Collateral posting in the normal course of business related to these derivatives		132
Net position of derivative contracts/additional collateral posting requirements (1)	$	(119	)

(1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit risk-related contingencies.

NOTE 8: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, trust assets, and price risk management instruments at fair value. Fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or a liability. A three-tier fair value hierarchy is established as a basis for considering such assumptions and for inputs used in the valuation methodologies in measuring fair value:

·	Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

·	Level 2 – Other inputs that are directly or indirectly observable in the marketplace.

·	Level 3 – Unobservable inputs which are supported by little or no market activities.

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

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

Fair Value Measurements

At September 30, 2012

(in millions)

Level 1

Level 2

Level 3

Netting (1)