PCG 10-Q Quarterly Report June 30, 2013

PG&E CORP

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10-Q 1 form10q.htm FORM 10-Q 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 June 30, 2013 OR
[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to __________

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

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

Pacific Gas and Electric Company 77 Beale Street P.O. Box 770000 San Francisco, California 94177 ______________________________________				PG&E Corporation 77 Beale Street P.O. Box 770000 San Francisco, California 94177 ______________________________________
Address of principal executive offices, including zip code
Pacific Gas and Electric Company (415) 973-7000 ________________________________________				PG&E Corporation (415) 973-1000 ______________________________________
Registrant's telephone number, including area code

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

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

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

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
Common stock outstanding as of July 22, 2013:
PG&E Corporation:				445,151,814
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, 2013

TABLE OF CONTENTS

				PAGE
GLOSSARY				ii

PART I.	FINANCIAL INFORMATION
ITEM 1 .	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS			1
	PG&E Corporation
		Condensed Consolidated Statements of Income		1
		Condensed Consolidated Statements of Comprehensive Income		2
		Condensed Consolidated Balance Sheets		3
		Condensed Consolidated Statements of Cash Flows		5
	Pacific Gas and Electric Company
		Condensed Consolidated Statements of Income		6
		Condensed Consolidated Statements of Comprehensive Income		7
		Condensed Consolidated Balance Sheets		8
		Condensed Consolidated Statements of Cash Flows		10
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	NOTE 1:		Organization and Basis of Presentation	11
	NOTE 2:		Significant Accounting Policies	12
	NOTE 3:		Regulatory Assets, Liabilities, and Balancing Accounts	14
	NOTE 4:		Debt	15
	NOTE 5:		Equity	15
	NOTE 6:		Earnings Per Share	16
	NOTE 7:		Derivatives	16
	NOTE 8:		Fair Value Measurements	18
	NOTE 9:		Resolution of Remaining Chapter 11 Disputed Claims	24
	NOTE 10:		Commitments and Contingencies	24

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			29
	Cautionary language regarding forward-looking statements			30
	Results of Operations			32
	Liquidity and Financial Resources			36
	Contractual Commitments			39
	Natural Gas Matters			40
	Regulatory Matters			43
	Environmental Matters			45
	Off-Balance Sheet Arrangements			45
	Risk Management Activities			45
	Critical Accounting Policies			45

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			46
ITEM 4.	CONTROLS AND PROCEDURES			46

PART II.	OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS			47
ITEM 1A.	RISK FACTORS			48
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			48
ITEM 5.	OTHER INFORMATION			48
ITEM 6.	EXHIBITS			49

SIGNATURES				50

GLOSSARY

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

2012 Annual Report	PG&E Corporation's and Pacific Gas and Electric Company's combined Annual Report on Form 10-K for the year ended December 31, 2012
AFUDC	allowance for funds used during construction
ALJ	administrative law judge
ASU	accounting standards update
CAISO	California Independent System Operator
CARB	California Air Resources Board
CCSF	City and County of San Francisco
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
DRA	Division of Ratepayer Advocates
DTSC	California Department of Toxic Substances Control
EPA	Environmental Protection Agency
EPS	earnings per common share
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	generally accepted accounting principles
GHG	greenhouse gas
GRC	general rate case
GT&S	gas transmission and storage
IRS	Internal Revenue Service
NEIL	Nuclear Electric Insurance Limited
NRC	Nuclear Regulatory Commission
NTSB	National Transportation Safety Board
PSEP	pipeline safety enhancement plan
ROE	return on equity
SED	Safety and Enforcement Division of the CPUC, formerly known as the Consumer Protection and Safety Division or the CPSD
TO	transmission owner
TURN	The Utility Reform Network
Utility	Pacific Gas and Electric Company
VIE(s)	variable interest entity(ies)

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in millions, except per share amounts)	2013			2012			2013			2012
Operating Revenues
Electric	$	3,059		$	2,931		$	5,858		$	5,703
Natural gas		717			662			1,590			1,531
Total operating revenues		3,776			3,593			7,448			7,234
Operating Expenses
Cost of electricity		1,189			962			2,172			1,821
Cost of natural gas		179			132			525			475
Operating and maintenance		1,256			1,426			2,594			2,794
Depreciation, amortization, and decommissioning		516			606			1,019			1,190
Total operating expenses		3,140			3,126			6,310			6,280
Operating Income		636			467			1,138			954
Interest income		2			3			4			4
Interest expense		(177	)		(176	)		(353	)		(350	)
Other income, net		24			32			52			58
Income Before Income Taxes		485			326			841			666
Income tax provision		153			87			267			191
Net Income		332			239			574			475
Preferred stock dividend requirement of subsidiary		4			4			7			7
Income Available for Common Shareholders	$	328		$	235		$	567		$	468
Weighted Average Common Shares Outstanding, Basic		442			423			438			419
Weighted Average Common Shares Outstanding, Diluted		443			425			439			421
Net Earnings Per Common Share, Basic	$	0.74		$	0.56		$	1.29		$	1.12
Net Earnings Per Common Share, Diluted	$	0.74		$	0.55		$	1.29		$	1.11
Dividends Declared Per Common Share	$	0.46		$	0.46		$	0.91		$	0.91

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in millions)	2013			2012			2013			2012
Net Income	$	332		$	239		$	574		$	475
Other Comprehensive Income, net of income tax
Pension and other postretirement benefit plans
Unrecognized prior service credit		6			6			12			12
Unrecognized net gain		17			19			34			40
Unrecognized net transition obligation		-			4			-			8
Transfer to regulatory account		(19	)		(21	)		(38	)		(42	)
Other investments		16			-			22			-
Total other comprehensive income, net of income tax		20			8			30			18
Comprehensive Income		352			247			604			493
Preferred stock dividend requirement of subsidiary		4			4			7			7
Comprehensive Income Attributable to Common Shareholders	$	348		$	243		$	597		$	486

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	June 30,			December 31,
(in millions)	2013			2012
ASSETS
Current Assets
Cash and cash equivalents	$	281		$	401
Restricted cash		305			330
Accounts receivable:
Customers (net of allowance for doubtful accounts of $80 and $87
at respective dates)		1,034			937
Accrued unbilled revenue		766			761
Regulatory balancing accounts		1,205			936
Other		272			365
Regulatory assets		508			564
Inventories:
Gas stored underground and fuel oil		148			135
Materials and supplies		327			309
Income taxes receivable		365			211
Other		231			172
Total current assets		5,442			5,121
Property, Plant, and Equipment
Electric		41,227			39,701
Gas		13,162			12,571
Construction work in progress		2,030			1,894
Other		1			1
Total property, plant, and equipment		56,420			54,167
Accumulated depreciation		(17,353	)		(16,644	)
Net property, plant, and equipment		39,067			37,523
Other Noncurrent Assets
Regulatory assets		6,786			6,809
Nuclear decommissioning trusts		2,214			2,161
Income taxes receivable		126			176
Other		689			659
Total other noncurrent assets		9,815			9,805
TOTAL ASSETS	$	54,324		$	52,449

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	June 30,			December 31,
(in millions, except share amounts)	2013			2012
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	952		$	492
Long-term debt, classified as current		1,288			400
Accounts payable:
Trade creditors		1,155			1,241
Disputed claims and customer refunds		156			157
Regulatory balancing accounts		1,002			634
Other		456			444
Interest payable		877			870
Income taxes payable		17			6
Deferred income taxes		106			-
Other		1,373			2,012
Total current liabilities		7,382			6,256
Noncurrent Liabilities
Long-term debt		11,917			12,517
Regulatory liabilities		5,226			5,088
Pension and other postretirement benefits		3,665			3,575
Asset retirement obligations		2,932			2,919
Deferred income taxes		6,988			6,748
Other		2,092			2,020
Total noncurrent liabilities		32,820			32,867
Commitments and Contingencies (Note 10)
Equity
Shareholders' Equity
Preferred stock		-			-
Common stock, no par value, authorized 800,000,000 shares,
444,717,704 and 430,718,293 shares outstanding at respective dates		9,032			8,428
Reinvested earnings		4,909			4,747
Accumulated other comprehensive loss		(71	)		(101	)
Total shareholders' equity		13,870			13,074
Noncontrolling Interest - Preferred Stock of Subsidiary		252			252
Total equity		14,122			13,326
TOTAL LIABILITIES AND EQUITY	$	54,324		$	52,449

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)	2013			2012
Cash Flows from Operating Activities
Net income	$	574		$	475
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		1,019			1,190
Allowance for equity funds used during construction		(52	)		(53	)
Deferred income taxes and tax credits, net		346			234
Other		157			137
Effect of changes in operating assets and liabilities:
Accounts receivable		(22	)		13
Inventories		(31	)		5
Accounts payable		28			(125	)
Income taxes receivable/payable		(143	)		153
Other current assets and liabilities		(367	)		74
Regulatory assets, liabilities, and balancing accounts, net		(192	)		(115	)
Other noncurrent assets and liabilities		142			186
Net cash provided by operating activities		1,459			2,174
Cash Flows from Investing Activities
Capital expenditures		(2,521	)		(2,219	)
Decrease (increase) in restricted cash		25			(1	)
Proceeds from sales and maturities of nuclear decommissioning
trust investments		795			666
Purchases of nuclear decommissioning trust investments		(786	)		(716	)
Other		16			64
Net cash used in investing activities		(2,471	)		(2,206	)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities		140			-
Net issuances (repayments) of commercial paper, net of discount of $1 and $2
at respective dates		321			(566	)
Proceeds from issuance of long-term debt, net of premium, discount, and issuance
costs of $8 and $6 at respective dates		742			394
Long-term debt matured or repurchased		(461	)		(50	)
Energy recovery bonds matured		-			(200	)
Common stock issued		562			561
Common stock dividends paid		(386	)		(368	)
Other		(26	)		40
Net cash provided by (used in) financing activities		892			(189	)
Net change in cash and cash equivalents		(120	)		(221	)
Cash and cash equivalents at January 1		401			513
Cash and cash equivalents at June 30	$	281		$	292
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(312	)	$	(319	)
Income taxes, net		(65	)		114
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	202		$	194
Capital expenditures financed through accounts payable		253			256
Noncash common stock issuances		11			12
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						Six Months Ended
	June 30,						June 30,
(in millions)	2013			2012			2013			2012
Operating Revenues
Electric	$	3,057		$	2,930		$	5,855		$	5,701
Natural gas		718			662			1,591			1,531
Total operating revenues		3,775			3,592			7,446			7,232
Operating Expenses
Cost of electricity		1,189			962			2,172			1,821
Cost of natural gas		179			132			525			475
Operating and maintenance		1,256			1,425			2,592			2,791
Depreciation, amortization, and decommissioning		516			606			1,019			1,190
Total operating expenses		3,140			3,125			6,308			6,277
Operating Income		635			467			1,138			955
Interest income		3			2			4			3
Interest expense		(171	)		(171	)		(341	)		(339	)
Other income, net		22			22			46			45
Income Before Income Taxes		489			320			847			664
Income tax provision		160			93			281			206
Net Income		329			227			566			458
Preferred stock dividend requirement		4			4			7			7
Income Available for Common Stock	$	325		$	223		$	559		$	451

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in millions)	2013			2012			2013			2012
Net Income	$	329		$	227		$	566		$	458
Other Comprehensive Income, net of income tax
Pension and other postretirement benefit plans
Unrecognized prior service credit		6			6			12			12
Unrecognized net gain		17			19			35			40
Unrecognized net transition obligation		-			4			-			8
Transfer to regulatory account		(19	)		(21	)		(38	)		(42	)
Total other comprehensive income, net of income tax		4			8			9			18
Comprehensive Income	$	333		$	235		$	575		$	476

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	June 30,			December 31,
(in millions)	2013			2012
ASSETS
Current Assets
Cash and cash equivalents	$	61		$	194
Restricted cash		305			330
Accounts receivable:
Customers (net of allowance for doubtful accounts of $80 and $87
at respective dates)		1,034			937
Accrued unbilled revenue		766			761
Regulatory balancing accounts		1,205			936
Other		275			366
Regulatory assets		508			564
Inventories:
Gas stored underground and fuel oil		148			135
Materials and supplies		327			309
Income taxes receivable		361			186
Other		169			160
Total current assets		5,159			4,878
Property, Plant, and Equipment
Electric		41,227			39,701
Gas		13,162			12,571
Construction work in progress		2,030			1,894
Total property, plant, and equipment		56,419			54,166
Accumulated depreciation		(17,352	)		(16,643	)
Net property, plant, and equipment		39,067			37,523
Other Noncurrent Assets
Regulatory assets		6,786			6,809
Nuclear decommissioning trusts		2,214			2,161
Income taxes receivable		122			171
Other		417			381
Total other noncurrent assets		9,539			9,522
TOTAL ASSETS	$	53,765		$	51,923

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	June 30,			December 31,
(in millions, except share amounts)	2013			2012
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	692		$	372
Long-term debt, classified as current		938			400
Accounts payable:
Trade creditors		1,155			1,241
Disputed claims and customer refunds		156			157
Regulatory balancing accounts		1,002			634
Other		471			419
Interest payable		872			865
Income taxes payable		25			12
Deferred income taxes		85			-
Other		1,155			1,794
Total current liabilities		6,551			5,894
Noncurrent Liabilities
Long-term debt		11,917			12,167
Regulatory liabilities		5,226			5,088
Pension and other postretirement benefits		3,583			3,497
Asset retirement obligations		2,932			2,919
Deferred income taxes		7,191			6,939
Other		2,031			1,959
Total noncurrent liabilities		32,880			32,569
Commitments and Contingencies (Note 10)
Shareholders' Equity
Preferred stock		258			258
Common stock, $5 par value, authorized 800,000,000 shares, 264,374,809
shares outstanding at respective dates		1,322			1,322
Additional paid-in capital		5,346			4,682
Reinvested earnings		7,492			7,291
Accumulated other comprehensive loss		(84	)		(93	)
Total shareholders' equity		14,334			13,460
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	53,765		$	51,923

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

COND ENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Six Months Ended June 30,
(in millions)	2013			2012
Cash Flows from Operating Activities
Net income	$	566		$	458
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		1,019			1,190
Allowance for equity funds used during construction		(52	)		(53	)
Deferred income taxes and tax credits, net		337			242
Other		126			108
Effect of changes in operating assets and liabilities:
Accounts receivable		(24	)		(50	)
Inventories		(31	)		5
Accounts payable		68			(107	)
Income taxes receivable/payable		(162	)		216
Other current assets and liabilities		(317	)		78
Regulatory assets, liabilities, and balancing accounts, net		(192	)		(115	)
Other noncurrent assets and liabilities		126			202
Net cash provided by operating activities		1,464			2,174
Cash Flows from Investing Activities
Capital expenditures		(2,521	)		(2,219	)
Decrease (increase) in restricted cash		25			(1	)
Proceeds from sales and maturities of nuclear decommissioning
trust investments		795			666
Purchases of nuclear decommissioning trust investments		(786	)		(716	)
Other		8			11
Net cash used in investing activities		(2,479	)		(2,259	)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $1 and $2
at respective dates		321			(566	)
Proceeds from issuance of long-term debt, net of premium, discount, and issuance
costs of $8 and $6 at respective dates		742			394
Long-term debt matured or repurchased		(461	)		(50	)
Energy recovery bonds matured		-			(200	)
Preferred stock dividends paid		(7	)		(7	)
Common stock dividends paid		(358	)		(358	)
Equity contribution		665			565
Other		(20	)		48
Net cash provided by (used in) financing activities		882			(174	)
Net change in cash and cash equivalents		(133	)		(259	)
Cash and cash equivalents at January 1		194			304
Cash and cash equivalents at June 30	$	61		$	45
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(300	)	$	(309	)
Income taxes, net		(86	)		111
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	253		$	256
Terminated capital leases		-			136

See accompanying Notes to the Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NOTE 1 : ORGANIZATION AND BASIS OF PRESENTATION

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

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

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

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

NOTE 2 : SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies used by PG&E Corporation and the Utility are discussed in Note 2 of the Notes to the Consolidated Financial Statements in the 2012 Annual Report.

Pension and Other Postretirement Benefits

PG&E Corporation and the Utility provide a non-contributory defined benefit pension plan for eligible employees, as well as contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees.

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and six months ended June 30, 2013 and 2012 were as follows:

	Pension Benefits						Other Benefits
	Three Months Ended June 30,
(in millions)	2013			2012			2013			2012
Service cost for benefits earned	$	115		$	98		$	13		$	11
Interest cost		156			165			18			21
Expected return on plan assets		(163	)		(150	)		(20	)		(20	)
Amortization of transition obligation		-			-			-			6
Amortization of prior service cost		5			5			5			6
Amortization of unrecognized loss		28			32			2			2
Net periodic benefit cost		141			150			18			26
Less: transfer to regulatory account (1)		(56	)		(75	)		-			-
Total	$	85		$	75		$	18		$	26

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

	Pension Benefits						Other Benefits
	Six Months Ended June 30,
(in millions)	2013			2012			2013			2012
Service cost for benefits earned	$	230		$	197		$	26		$	23
Interest cost		312			329			37			42
Expected return on plan assets		(325	)		(299	)		(40	)		(39	)
Amortization of transition obligation		-			-			-			12
Amortization of prior service cost		10			10			11			12
Amortization of unrecognized loss		55			63			3			3
Net periodic benefit cost		282			300			37			53
Less: transfer to regulatory account (1)		(113	)		(150	)		-			-
Total	$	169		$	150		$	37		$	53

(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.

Variable Interest Entities

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 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. To determine whether the Utility was the primary beneficiary of any of these VIEs at June 30, 2013, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial exposure is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at June 30, 2013, it did not consolidate any of them.

PG&E Corporation affiliates have entered into four tax equity agreements to fund residential and commercial retail solar energy installations with two privately held companies that are considered VIEs. Under these agreements, PG&E Corporation has made cumulative lease payments and investment contributions of $363 million to these companies in exchange for the right to receive benefits from local rebates, federal grants, and a share of the customer payments made to these companies. At June 30, 2013 and December 31, 2012, the carrying amount of PG&E Corporation’s investment in these agreements was $143 million and $166 million, respectively. PG&E Corporation determined that it does not have control over the companies’ significant economic activities, such as the design of the companies, vendor selection, construction, and the ongoing operations of the companies. PG&E Corporation has no material remaining commitment to fund these agreements. Since PG&E Corporation was not the primary beneficiary of any of these VIEs at June 30, 2013, it did not consolidate any of them.

Adoption of New Accounting Pronouncements

Disclosures about Offsetting Assets and Liabilities

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

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

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

The changes, net of income tax, in PG&E Corporation’s other comprehensive income for the three and six months ended June 30, 2013 consist of the following:

		Pension and
		Other
		Postretirement			Other
		Benefit Plans			Investments			Total
(in millions, net of income tax)	Three Months Ended June 30, 2013
Beginning balance		$	(101	)		$	10		$	(91	)
Other comprehensive income before reclassifications			(19	)			16			(3	)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (1)			6				-			6
Amortization of actuarial gains (1)			17				-			17
Net current period other comprehensive income			4				16			20
Ending balance		$	(97	)		$	26		$	(71	)

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

		Pension and
		Other
		Postretirement			Other
		Benefit Plans			Investments			Total
(in millions, net of income tax)	Six Months Ended June 30, 2013
Beginning balance		$	(105	)		$	4		$	(101	)
Other comprehensive income before reclassifications			(38	)			22			(16	)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (1)			12				-			12
Amortization of actuarial gains (1)			34				-			34
Net current period other comprehensive income			8				22			30
Ending balance		$	(97	)		$	26		$	(71	)

There was no material difference between PG&E Corporation and the Utility for the information disclosed above, with the exception of other investments which are held by PG&E Corporation.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Long-Term Regulatory Assets

Long-term regulatory assets are composed of the following:

	Balance at
(in millions)	June 30, 2013		December 31, 2012
Pension benefits	$	3,324	$	3,275
Deferred income taxes		1,700		1,627
Utility retained generation		527		552
Environmental compliance costs		604		604
Price risk management		163		210
Electromechanical meters		165		194
Unamortized loss, net of gain, on reacquired debt		146		141
Other		157		206
Total long-term regulatory assets	$	6,786	$	6,809

Regulatory Liabilities

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

	Balance at
	June 30,		December 31,
(in millions)	2013		2012
Cost of removal obligations	$	3,763	$	3,625
Recoveries in excess of asset retirement obligations		633		620
Public purpose programs		571		590
Other		259		253
Total long-term regulatory liabilities	$	5,226	$	5,088

Regulatory Balancing Accounts

The Utility’s recovery of a significant portion of revenue requirements and costs is decoupled from the volume of sales. The Utility records (1) differences between actual customer billings and the Utility’s authorized revenue requirement, and (2) differences between incurred costs and customer billings. To the extent these differences are probable of recovery or refund, the Utility records a regulatory balancing account receivable or payable. Regulatory balancing accounts receivable and payable will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected.

Current Regulatory Balancing Accounts, Net

	Receivable (Payable)
	Balance at
	June 30,		December 31,
(in millions)	2013		2012
Distribution revenue adjustment mechanism	$	407	$	219
Utility generation		267		117
Hazardous substance		75		56
Public purpose programs		(151)		(83)
Gas fixed cost		25		44
Energy recovery bonds		(181)		(43)
Energy procurement		13		77
U.S. Department of Energy Settlement		(279)		(250)
GHG allowance auction proceeds (1)		(199)		-
Other		226		165
Total regulatory balancing accounts, net	$	203	$	302

(1) The CARB has adopted regulations that established a state-wide, “cap-and-trade” program (effective January 1, 2013) that sets a gradually declining limit on the amount of GHGs that may be emitted each year. This balancing account is used to record proceeds collected by the Utility for GHG emission allowances associated with the cap-and-trade program. These amounts will be refunded to customers in future periods.

NOTE 4: DEBT

Senior Notes

In June 2013, the Utility issued $375 million principal amount of 3.25% Senior Notes due June 15, 2023 and $375 million principal amount of 4.60% Senior Notes due June 15, 2043. The proceeds were used to repurchase $461 million principal amount, net of $21 million of premiums and accrued interest, of the Utility’s $1.0 billion outstanding 4.80% Senior Notes due March 1, 2014, to repay a portion of outstanding commercial paper, and for general corporate purposes.

Revolving Credit Facilities

In April 2013, PG&E Corporation and the Utility amended and restated their revolving credit facilities to extend their termination dates from May 31, 2016 to April 1, 2018. These agreements contain substantially similar terms as their original 2011 credit agreements.

At June 30, 2013, PG&E Corporation had $260 million of cash borrowings and no letters of credit outstanding under its $300 million revolving credit facility.

At June 30, 2013, the Utility had no cash borrowings and $91 million of letters of credit outstanding under its $3.0 billion revolving credit facility.

Pollution Control Bonds

At June 30, 2013, the interest rates on the $614 million principal amount of pollution control bonds Series 1996 C, E, F, and 1997 B and the related loan agreements ranged from 0.04% to 0.06%. At June 30, 2013, the interest rates on the $309 million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements ranged from 0.01% to 0.05%.

Commercial Paper Program

At June 30, 2013, the Utility had $692 million of commercial paper outstanding under its revolving credit facility.

NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the six months ended June 30, 2013 were as follows:


	PG&E Corporation			Utility
	Total			Total
(in millions)	Equity			Shareholders' Equity
Balance at December 31, 2012	$	13,326		$	13,460
Comprehensive income		604			575
Common stock issued		573			-
Share-based compensation expense		31			(1	)
Common stock dividends declared		(405	)		(358	)
Preferred stock dividend requirement		-			(7	)
Preferred stock dividend requirement of subsidiary		(7	)		-
Equity contributions		-			665
Balance at June 30, 2013	$	14,122		$	14,334

In May 2013, PG&E Corporation entered into a new Equity Distribution Agreement providing for the sale of PG&E Corporation common stock having an aggregate gross sales price of up to $400 million. As of June 30, 2013, PG&E Corporation common stock having an aggregate gross sales price of $50 million had been sold under this equity distribution agreement.

During the six months ended June 30, 2013, PG&E Corporation issued 14 million shares of its common stock for aggregate net cash proceeds of $562 million in the following transactions:

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

·	4 million shares were issued for cash proceeds of $149 million under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans; and

·	3 million shares were sold for cash proceeds of $113 million, net of commissions paid of $1 million, under the equity distribution agreements.

During the six months ended June 30, 2013, PG&E Corporation contributed equity of $665 million to the Utility to maintain the Utility’s CPUC-authorized capital structure, which consists of 52% common equity and 48% debt and preferred stock.

NOTE 6: EARNINGS PER SHARE

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in millions, except per share amounts)	2013		2012		2013		2012
Income available for common shareholders	$	328	$	235	$	567	$	468
Weighted average common shares outstanding, basic		442		423		438		419
Add incremental shares from assumed conversions:
Employee share-based compensation		1		2		1		2
Weighted average common share outstanding, diluted		443		425		439		421
Total earnings per common share, diluted	$	0.74	$	0.55	$	1.29	$	1.11

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

NOTE 7: DERIVATIVES

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

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

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

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

Presentation of Derivative Instruments in the Financial Statements

In the Condensed Consolidated Balance Sheets, derivatives are presented on a net basis by counterparty where the right and the intention to offset exists under a master netting agreement. All derivatives that are subject to a master netting arrangement have been netted. The net balances include outstanding cash collateral associated with derivative positions.

At June 30, 2013, PG&E Corporation’s and the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
	Gross											Total
(in millions)	Balance				Netting				Cash Collateral			Balance
Current assets – other		$	31			$	(11	)		$	28		$	48
Other noncurrent assets – other			71				(5	)			-			66
Current liabilities – other			(188	)			11				133			(44	)
Noncurrent liabilities – other			(168	)			5				40			(123	)
Total commodity risk		$	(254	)		$	-			$	201		$	(53	)

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

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

Gains and losses associated with price risk management activities were recorded as follows:

	Commodity Risk
	Three Months Ended								Six Months Ended
	June 30,								June 30,
(in millions)	2013				2012				2013				2012
Unrealized gain/(loss) - regulatory assets and liabilities (1)		$	(23	)		$	219			$	75			$	165
Realized loss - cost of electricity (2)			(31	)			(125	)			(79	)			(275	)
Realized loss - cost of natural gas (2)			(4	)			(5	)			(12	)			(27	)
Total commodity risk		$	(58	)		$	89			$	(16	)		$	(137	)

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

Volume of Derivative Activity

At June 30, 2013, the volumes of PG&E Corporation’s and the Utility’s outstanding derivatives were as follows:

		Contract Volume (1)
				1 Year or		3 Years or
				Greater but		Greater but
		Less Than 1		Less Than 3		Less Than 5		5 Years or
Underlying Product	Instruments	Year		Years		Years		Greater (2)
Natural Gas (3)	Forwards and
(MMBtus (4) )	Swaps		290,542,776		86,670,000		6,900,000		-
	Options		209,492,494		136,515,176		4,950,000		-
Electricity	Forwards and
(Megawatt-hours)	Swaps		3,088,879		2,782,480		2,008,046		2,077,424
	Options		55,051		239,233		239,015		64,456
	Congestion
	Revenue Rights		55,926,491		74,483,974		68,123,543		14,274,162

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

(2) Derivatives in this category expire between 2018 and 2022.

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

(4) Million British Thermal Units.

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

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

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

(2) Derivatives in this category expire between 2018 and 2022.

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

(4) Million British Thermal Units.

The majority of the Utility’s derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. At June 30, 2013, the Utility’s credit rating was investment grade. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some of its net liability derivative positions.

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

	Balance at
	June 30,			December 31,
(in millions)	2013			2012
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(116	)	$	(266	)
Related derivatives in an asset position		4			59
Collateral posting in the normal course of business related to
these derivatives		96			103
Net position of derivative contracts/additional collateral
posting requirements (1)	$	(16	)	$	(104	)

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

credit risk-related contingencies.

NOTE 8: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, trust assets, price risk management instruments, and other investments 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 and other investments are held by PG&E Corporation and not the Utility):

	Fair Value Measurements
	At June 30, 2013
(in millions)	Level 1		Level 2		Level 3		Netting (1)			Total
Assets:
Money market investments	$	222	$	-	$	-	$	-		$	222
Nuclear decommissioning trusts
Money market investments		32		-		-		-			32
U.S. equity securities		956		10		-		-			966
Non-U.S. equity securities		391		-		-		-			391
U.S. government and agency securities		759		135		-		-			894
Municipal securities		-		31		-		-			31
Other fixed-income securities		-		166		-		-			166
Total nuclear decommissioning trusts (2)		2,138		342		-		-			2,480
Price risk management instruments
(Note 7)
Electricity		-		26		72		15			113
Gas		1		3		-		(3	)		1
Total price risk management instruments		1		29		72		12			114
Rabbi trusts
Fixed-income securities		-		29		-		-			29
Life insurance contracts		-		71		-		-			71
Total rabbi trusts		-		100		-		-			100
Long-term disability trust
Money market investments		3		-		-		-			3
U.S. equity securities		-		13		-		-			13
Non-U.S. equity securities		-		12		-		-			12
Fixed-income securities		-		123		-		-			123
Total long-term disability trust		3		148		-		-			151
Other investments		56		-		-		-			56
Total assets	$	2,420	$	619	$	72	$	12		$	3,123
Liabilities:
Price risk management instruments
(Note 7)
Electricity	$	85	$	112	$	148	$	(183	)	$	162
Gas		6		5		-		(6	)		5
Total liabilities	$	91	$	117	$	148	$	(189	)	$	167

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

(2) Excludes $266 million at June 30, 2013 primarily related to deferred taxes on appreciation of investment value.

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

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

(2) Excludes $240 million at December 31, 2012 primarily related to deferred taxes on appreciation of investment value.

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. All investments that are valued using a net asset value per share can be redeemed quarterly with notice not to exceed 90 days.

Money Market Investments

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

Trust Assets

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

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

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

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

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

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

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

Other Investments

Other investments in common stock are valued based on unadjusted prices for the investments and are actively traded on public exchanges. These investments are therefore considered Level 1 assets.

Transfers between Levels

PG&E Corporation and the Utility recognize transfers between levels in the fair value hierarchy as of the end of the reporting period. There were no transfers between levels for the three and six months ended June 30, 2013.

Level 3 Measurements and Sensitivity Analysis

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

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

	Fair Value at
(in millions)	June 30, 2013
Fair Value Measurement	Assets			Liabilities			Valuation Technique	Unobservable Input	Range (1)
Congestion revenue rights		$	72		$	14	Market approach	CRR auction prices		$	(10.54) - 7.93
Power purchase agreements		$	-		$	134	Discounted cash flow	Forward prices		$	10.16 - 56.80

(1) Represents price per megawatt-hour

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

(1) Represents price per megawatt-hour

Level 3 Reconciliation

The following tables present the reconciliation for Level 3 price risk management instruments for the three and six months ended June 30, 2013 and 2012:

	Price Risk Management Instruments
(in millions)	2013			2012
Liability balance as of April 1	$	(75	)	$	(99	)
Realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)		(1	)		19
Liability balance as of June 30	$	(76	)	$	(80	)

(1) The costs related to price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.

	Price Risk Management Instruments
(in millions)	2013			2012
Liability balance as of January 1	$	(79	)	$	(74	)
Realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)		3			(6	)
Liability balance as of June 30	$	(76	)	$	(80	)

Financial Instruments

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

The fair values of cash, restricted cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at June 30, 2013 and December 31, 2012, as they are short-term in nature or have interest rates that reset daily.

·	The fair values of the Utility’s fixed-rate senior notes and fixed-rate pollution control bonds and PG&E Corporation’s fixed-rate senior notes were based on quoted market prices at June 30, 2013 and December 31, 2012.

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

	June 30, 2013						December 31, 2012
(in millions)	Carrying Amount			Level 2 Fair Value			Carrying Amount			Level 2 Fair Value
Debt (Note 4)
PG&E Corporation		$	350		$	363		$	349		$	371
Utility			11,933			13,076			11,645			13,946

Available for Sale Investments

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

			Total		Total
	Amortized		Unrealized		Unrealized			Total Fair
(in millions)	Cost		Gains		Losses			Value
As of June 30, 2013
Nuclear decommissioning trusts
Money market investments	$	32	$	-	$	-		$	32
Equity securities
U.S.		262		704		-			966
Non-U.S.		205		188		(2	)		391
Debt securities
U.S. government and agency securities		831		67		(4	)		894
Municipal securities		29		2		-			31
Other fixed-income securities		166		2		(2	)		166
Total nuclear decommissioning trusts (1)		1,525		963		(8	)		2,480
Other investments		13		43		-			56
Total	$	1,538	$	1,006	$	(8	)	$	2,536
As of December 31, 2012
Nuclear decommissioning trusts
Money market investments	$	21	$	-	$	-		$	21
Equity securities
U.S.		331		618		-			949
Non-U.S.		199		181		(1	)		379
Debt securities
U.S. government and agency securities		723		97		-			820
Municipal securities		56		4		(1	)		59
Other fixed-income securities		168		5		-			173
Total (1)	$	1,498	$	905	$	(2	)	$	2,401

(1) Excludes $266 million and $240 million at June 30, 2013 and December 31, 2012, respectively, primarily related to deferred taxes on appreciation of investment value.

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

	As of
(in millions)	June 30, 2013
Less than 1 year	$	28
1–5 years		503
5–10 years		221
More than 10 years		339
Total maturities of debt securities	$	1,091

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

	Three Months Ended								Six Months Ended
	June 30,								June 30,
	2013				2012				2013			2012
(in millions)
Proceeds from sales and maturities of nuclear decommissioning
trust investments		$	432			$	315		$	795			$	666
Gross realized gains on sales of securities held as available-for-sale			25				7			37				14
Gross realized losses on sales of securities held as available-for-sale			(5	)			(5	)		(6	)			(8	)

NOTE 9: RESOLUTION OF REMAINING CHAPTER 11 DISPUTED CLAIMS

Various electricity suppliers filed claims in the Utility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001. These claims, which the Utility disputes, are being addressed in various FERC and judicial proceedings in which the State of California, the Utility, and other electricity purchasers are seeking refunds from electricity suppliers, including governmental entities, for overcharges incurred in the CAISO and the California Power Exchange wholesale electricity markets during this period.

While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers. The Utility entered into a number of settlement agreements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. These settlement agreements provide that the amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. The Utility is uncertain when and how the remaining disputed claims will be resolved.

Any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers through resolution of the remaining disputed claims, either through settlement or through the conclusion of the various FERC and judicial proceedings, are refunded to customers through rates in future periods.

At June 30, 2013, and December 31, 2012, the remaining net disputed claims liability consisted of $156 million and $157 million, respectively, of remaining net disputed claims (classified on the Condensed Consolidated Balance Sheets within accounts payable – disputed claims and customer refunds) and $698 million and $685 million, respectively, of accrued interest (classified on the Condensed Consolidated Balance Sheets within interest payable).

At June 30, 2013 and December 31, 2012, the Utility held $291 million, respectively, in escrow, including earned interest, for payment of the remaining net disputed claims liability. These amounts are included within restricted cash on the Condensed Consolidated Balance Sheets.

NOTE 10: COMMITMENTS AND CONTINGENCIES

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

Commitments

In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments. The Utility disclosed its commitments at December 31, 2012 in Note 15 of the Notes to the Consolidated Financial Statements in the 2012 Annual Report. During the six months ended June 30, 2013, the Utility entered into seven renewable energy power purchase agreements, resulting in a total commitment of $1.1 billion over the next five to twenty-five years. These agreements have been approved by the CPUC and have completed major milestones with respect to construction.

Contingencies

Legal and Regulatory Contingencies

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits. In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations. PG&E Corporation and the Utility record a provision for a loss contingency when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs.

Accruals for legal and regulatory contingencies (excluding amounts related to natural gas matters below) totaled $31 million at June 30, 2013 and $34 million at December 31, 2012. These amounts are included in current liabilities – other in the Condensed Consolidated Balance Sheets. Except as discussed below, PG&E Corporation and the Utility do not believe that losses associated with legal and regulatory contingencies would have a material impact on their financial condition, results of operations, or cash flows.

Natural Gas Matters

On September 9, 2010, a natural gas transmission pipeline owned and operated by the Utility ruptured in San Bruno, California. The ensuing explosion and fire resulted in the deaths of eight people, numerous personal injuries, and extensive property damage. Following the San Bruno accident, various regulatory proceedings, investigations, and lawsuits were commenced. The NTSB, an independent review panel appointed by the CPUC, and the SED completed investigations with respect to the San Bruno accident, placing the blame primarily on the Utility. As part of a rulemaking proceeding to consider the adoption of new natural gas safety regulations, the CPUC ordered all natural gas operators in California to submit proposed plans to modernize and upgrade their natural gas transmission systems as well as associated cost forecast and ratemaking proposals.

CPUC Gas Safety Rulemaking Proceeding

On December 28, 2012, the CPUC issued a decision that approved most of the Utility’s proposed pipeline safety enhancement plan, but disallowed the Utility’s request for rate recovery of a significant portion of costs the Utility forecasted it would incur over the first phase of the plan through 2014. The CPUC decision limited the Utility’s recovery of capital costs to $1.0 billion of the total $1.4 billion requested and limited recovery of expenses to $165 million of the total $751 million requested. Disallowed costs are charged to net income in the period incurred. The CPUC stated that the Utility’s recovery of the amounts authorized in its decision are subject to refund, noting the possibility that further ratemaking adjustments may be made in the pending CPUC investigations discussed below. In addition, the Utility is required to file an update to its plan on or before October 29, 2013 regarding the results of its pipeline records search and validation work, which may result in further adjustments to the Utility’s authorized revenue requirements.

Pending CPUC Investigations and Enforcement Matters

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

On July 16, 2013, the SED filed an amended reply brief in these proceedings to recommend that the CPUC impose what the SED characterized as a penalty of $2.25 billion on the Utility, allocated as follows: (1) $300 million as a fine to the State General Fund, (2) $435 million for a portion of PSEP costs that were previously disallowed by the CPUC and funded by shareholders, and (3) $1.515 billion to perform PSEP work that was previously approved by the CPUC, implement operational remedies, and for future PSEP costs. The SED’s recommendation superseded the SED’s prior briefs of May 6, 2013 and June 5, 2013 in which it recommended that the entirety of the penalty be in the form of shareholder-funded safety investments in the Utility’s natural gas transmission and distribution system and none should be paid as a fine to the State General Fund.

Briefs also were filed during the second quarter of 2013 by the City of San Bruno, TURN, the CPUC’s DRA, and the City and County of San Francisco. All parties recommend total penalties of at least $2.25 billion, including fines payable to the State General Fund of differing amounts. The City of San Bruno also recommended that the Utility provide $150 million for a Peninsula Emergency Response Consortium, spend $100 million ($5 million per year for 20 years) to fund an independent advocacy trust (the California Pipeline Safety Trust), and provide funding for an independent monitor to oversee the implementation of the recommended remedial operational measures. TURN also recommended that the Utility bear expenses of $50 million to implement remedial measures and to pay for an independent monitor.

On July 18, 2013, the Utility filed a request to re-open the evidentiary record and extend the procedural schedule in the investigations in order to allow the Utility to present additional evidence to respond to the SED’s latest penalty recommendation. As permitted by the ALJs, the SED and other parties responded to the Utility on July 26, 2013 objecting to the request. Although the ALJs have not yet ruled on the Utility’s request, on July 30, 2013, the ALJs issued a ruling requesting the Utility to provide answers to questions about its financing plans, how it intends to treat fines or disallowed costs for regulatory accounting and tax purposes, and the impact on rates. The Utility’s response is due on August 14, 2013. The ALJs have asked all parties to file comments to address the impact that fines and disallowances would have on the Utility’s ability to raise capital and otherwise remain financially viable, including the tax treatment of amounts disallowed. The parties’ comments are due on September 13, 2013 and reply comments are due on September 23, 2013. The Utility is uncertain when the ALJs will act on the Utility’s request to re-open the record.

After the briefing process has been completed, it is anticipated that the CPUC ALJs will issue one or more presiding officer’s decisions to address the violations that they have determined the Utility committed and to impose penalties. Based on the CPUC’s rules, the presiding officer’s decisions would become the final decisions of the CPUC 30 days after issuance unless the Utility or another party filed an appeal with the CPUC, or a CPUC commissioner requested that the CPUC review the decision, within such time. If an appeal or review request were filed, other parties would have 15 days to provide comments but the CPUC could act before considering any comments.

As discussed above, various parties have recommended that the CPUC impose total penalties on the Utility of at least $2.25 billion, including fines payable to the State General Fund of differing amounts. At June 30, 2013 and December 31, 2012, PG&E Corporation’s and the Utility’s financial statements included an accrual of $200 million for the minimum amount of fines deemed probable that the Utility will pay to the State General Fund. The Utility is unable to make a better estimate due to the many variables that could affect the final outcome of these pending investigations. These variables include how the total number and duration of violations will be determined; how the SED’s and other parties’ recommendations on the amount and form of penalties will be considered; whether and how the financial impact of unrecoverable costs the Utility has incurred, and will continue to incur, to improve the safety and reliability of its pipeline system, will be considered; whether the Utility’s costs to perform any required remedial actions will be considered; and how the CPUC responds to public pressure. Future changes in these estimates or the assumptions on which they are based could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. The CPUC may impose fines on the Utility that are materially higher than the amount accrued and disallow PSEP costs that were previously authorized for recovery. Disallowed costs would be charged to net income in the period incurred. At June 30, 2013, capitalized PSEP costs of approximately $200 million are included in Property, Plant, and Equipment on the Condensed Consolidated Balance Sheets. A final decision on these investigations could be issued before the end of 2013.

Other Potential Enforcement Matters

As of June 30, 2013, the Utility has submitted 55 self-reports with the SED, plus additional follow-up reports, to provide notice about self-identified and self-corrected violations of certain state and federal regulations related to the safety of natural gas facilities and natural gas operating practices. The SED is authorized to issue citations and impose penalties on the Utility associated with these or future reports that the Utility may file. The SED may consider the same factors as the CPUC in exercising its discretion to impose penalties, except that if a penalty is assessed, the SED is required to impose the maximum daily statutory penalty per violation. The SED has scheduled a workshop in early August to elicit feedback from the California gas utilities and other stakeholders on the gas citation program and to consider future changes to the program. PG&E Corporation and the Utility are uncertain whether the SED will issue citations and impose penalties on the Utility based on the self-reports the Utility has already submitted.

In 2012, the Utility also notified the CPUC and the SED that the Utility is undertaking a system-wide effort to survey its transmission pipelines and identify and remove encroachments from pipeline rights-of-way over a multi-year period. PG&E Corporation and the Utility are uncertain whether this matter will result in the imposition of penalties on the Utility.

Criminal Investigation

Since June 2011, the U.S. Department of Justice, the California Attorney General’s Office, and the San Mateo County District Attorney’s Office have been conducting an investigation of the San Bruno accident and have indicated that the Utility is a target of the investigation. The Utility is cooperating with the investigation. PG&E Corporation and the Utility believe that criminal charges, including charges based on claims that the Utility violated the federal Pipeline Safety Act, may be brought against PG&E Corporation or the Utility. It is uncertain whether any criminal charges will be brought against any of PG&E Corporation’s or the Utility’s current or former employees. A criminal charge or finding would further harm the Utility’s reputation. PG&E Corporation and the Utility are unable to estimate the amount or range of reasonably possible losses associated with any civil or criminal penalties that could be imposed and such penalties could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. In addition, the Utility’s business or operations could be negatively affected by any remedial measures imposed on the Utility, such as the appointment of an independent monitor.

Third-Party Claims

Since the San Bruno accident, approximately 160 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, have been filed against PG&E Corporation and the Utility in connection with the accident on behalf of approximately 500 plaintiffs. These lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages. All cases were coordinated and assigned to one judge in the San Mateo County Superior Court. The Utility has entered into settlement agreements to resolve the claims of approximately 150 plaintiffs and other claimants. In the second quarter of 2013, all class action allegations were dismissed by the court.

As reflected in the table below, the Utility has recorded cumulative charges of $455 million for estimated third-party claims, including personal injury, property damage, damage to infrastructure, and other damage claims. At June 30, 2013, the Utility has made cumulative payments of $388 million for settlements. The Utility estimates it is reasonably possible that it may incur as much as an additional $145 million for unresolved claims, for a total possible loss of $600 million since the San Bruno accident. The Utility and most of the plaintiffs with unresolved claims are engaged in settlement discussions with the assistance of mediators. Settlement discussions with some plaintiffs may conclude in the third quarter of 2013. PG&E Corporation and the Utility are unable to estimate the amount or range of reasonably possible losses associated with punitive damages, if any, related to these matters.

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

(in millions)
Balance at January 1, 2010	$	-
Loss accrued		220
Less: Payments		(6	)
Balance at December 31, 2010		214
Additional loss accrued		155
Less: Payments		(92	)
Balance at December 31, 2011		277
Additional loss accrued		80
Less: Payments		(211	)
Balance at December 31, 2012		146
Additional loss accrued		-
Less: Payments		(79	)
Balance at June 30, 2013	$	67

The Utility has liability insurance from various insurers who provide coverage at different policy limits that are triggered in sequential order or “layers.” Generally, as the policy limit for a layer is exhausted the next layer of insurance becomes available. The aggregate amount of insurance coverage for third-party liability attributable to the San Bruno accident is approximately $992 million in excess of a $10 million deductible. Through June 30, 2013, the Utility has recognized cumulative insurance recoveries of $329 million for third-party claims and related legal expenses. (The Utility has incurred cumulative legal expenses of $81 million in addition to the $455 million charge above). Insurance recoveries for the three and six months ended June 30, 2013 were $45 million. These amounts were recorded as a reduction to operating and maintenance expense in PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Income. Although the Utility believes that a significant portion of costs incurred for third-party claims relating to the San Bruno accident will ultimately be recovered through its insurance, it is unable to predict the amount and timing of additional insurance recoveries.

Class Action Complaint

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

PG&E Corporation and the Utility contest the plaintiffs’ allegations. On May 23, 2013, the court granted PG&E Corporation’s and the Utility’s request to dismiss the complaint on the grounds that the CPUC has exclusive jurisdiction to adjudicate the issues raised by the plaintiffs’ allegations. PG&E Corporation and the Utility are unable to estimate the amount or range of reasonably possible losses, if any, that may be incurred in connection with this matter.

Nuclear Insurance

The Utility is a member of NEIL, which is a mutual insurer owned by utilities with nuclear facilities. NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear event were to occur at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $1.8 billion per non-nuclear incident for Diablo Canyon. Humboldt Bay Unit 3 has up to $131 million of coverage for nuclear and non-nuclear property damages. NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants.

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. The Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon. The balance is provided under a loss-sharing program among utilities owning nuclear reactors. The Price-Anderson Act does not apply to 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. The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $375 million per incident. In addition, the Utility has $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents, covering liabilities in excess of the liability insurance. (See Note 15 of the Notes to the Consolidated Financial Statements of the 2012 Annual Report for additional information on the Utility’s insurance coverage and premiums.)

Environmental Remediation Contingencies

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

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

The following table presents the changes in the environmental remediation liability:

(in millions)
Balance at December 31, 2012	$	910
Additional remediation costs accrued:
Transfer to regulatory account for recovery		85
Amounts not recoverable from customers		31
Less: Payments		(92	)
Balance at June 30, 2013	$	934

The environmental remediation liability is composed of the following:

	Balance at
(in millions)	June 30, 2013		December 31, 2012
Utility-owned natural gas compressor site near Topock, Arizona (1)	$	270	$	239
Utility-owned natural gas compressor site near Hinkley, California (1)		207		226
Former manufactured gas plant sites owned by the Utility or third parties		181		181
Utility-owned generation facilities (other than for fossil fuel-fired), other facilities, and third-party disposal sites		169		158
Fossil fuel-fired generation facilities formerly owned by the Utility		88		87
Decommissioning fossil fuel-fired generation facilities and sites		19		19
Total environmental remediation liability	$	934	$	910

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

At June 30, 2013, the Utility expected to recover $587 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC. One of these mechanisms allows the Utility rate recovery for 90% of its hazardous substance remediation costs for certain approved sites (including the Topock site) without a reasonableness review. The Utility may incur environmental remediation costs that it does not seek to recover in rates, such as the costs associated with the Hinkley site.

Natural Gas Compressor Sites

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

Hinkley Site

The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. The Regional Board has issued several orders directing the Utility to implement interim remedial measures to reduce the mass of the underground plume of hexavalent chromium, monitor and control movement of the plume, and provide replacement water to affected residents. As of June 30, 2013, approximately 350 residential households located near the chromium plume boundary were covered by the Utility’s whole house water replacement program and the majority have opted to accept the Utility’s offer to purchase their properties. On July 17, 2013, the Regional Board certified a final environmental impact report evaluating the Utility’s proposed remedial methods to contain and remediate the chromium plume and the potential environmental impacts. The Regional Board is expected to develop preliminary cleanup standards later this year and issue final cleanup standards in 2014.

The Utility’s environmental remediation liability at June 30, 2013 reflects the Utility’s best estimate of probable future costs associated with its final remediation plan and whole house water program. Future costs will depend on many factors, including the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the required time period by which those standards must be met, the extent of the chromium plume boundary, and adoption of a final drinking water standard currently under development by the State of California. As more information becomes known regarding these factors, the Utility’s cost estimates and the assumptions on which they are based regarding the amount of liability incurred may be subject to further changes. Future changes in estimates or assumptions may have a material impact on PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows.

Topock Site

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

The Utility’s environmental remediation liability at June 30, 2013 reflects its best estimate of probable future costs associated with these developments. Future costs will depend on many factors, including the extent of work to be performed to implement the final groundwater remedy and the Utility’s required time frame for remediation. As more information becomes known regarding these factors, the Utility’s cost estimates and the assumptions on which they are based regarding the amount of liability incurred may be subject to further changes. Future changes in estimates or assumptions could have a material impact on PG&E Corporation’s and the Utility’s future financial condition and cash flows.

Reasonably Possible Environmental Contingencies

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, the Utility’s undiscounted future costs could increase to as much as $1.7 billion (including amounts related to the Hinkley and Topock sites described above) if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on PG&E Corporation’s and the Utility’s results of operations during the period in which they are recorded.

Tax Matters

The IRS has withheld several matters pertaining to the 2008, 2010, and 2011 tax returns for further review. The most significant of these matters relates to the repairs accounting method changes made by the Utility with the filing of the 2008 and 2011 tax returns. Additionally, the IRS has been working with the utility industry to provide guidance concerning the deductibility of repairs. PG&E Corporation and the Utility expect the IRS to issue guidance with respect to repairs made in the natural gas transmission and distribution businesses by the end of 2013. PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months depending on the guidance to be issued by the IRS and the resolution of the IRS audits. As of June 30, 2013, PG&E Corporation and the Utility were unable to estimate the amount of the future change in unrecognized tax benefits.

There were no other significant developments to tax matters during the six months ended June 30, 2013 . (Refer to Note 9 of the Notes to the Consolidated Financial Statements in the 2012 Annual Report.)

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

RESULTS OF OPERATIONS

OVERVIEW

PG&E Corporation, incorporated in California in 1995, is a holding company that conducts its business through Pacific Gas and Electric Company, a public utility operating in northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers.

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

Most of the revenues that the Utility is authorized to collect through rates are set by the CPUC in the GRC, which occurs generally every three years. The Utility’s revenue requirements for other portions of its operations, such as electric transmission, natural gas transportation and storage services, electricity and natural gas purchases, are authorized in other regulatory proceedings overseen by the CPUC or the FERC. The Utility’s revenue requirements are generally set at a level to allow the Utility to recover its forecasted operating expenses, to recover depreciation, tax, and interest expenses associated with forecasted capital expenditures, and to provide the Utility with an opportunity to earn its authorized ROE. The Utility also collects revenue requirements to recover certain costs that the CPUC has authorized the Utility to pass through to customers, such as electricity procurement costs. From time to time, the Utility also files separate applications with the CPUC requesting authority to recover costs for other projects. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows are affected by the extent to which the Utility is able to timely recover its actual costs through rates and earn its authorized ROE.

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s separate Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in this quarterly report. In addition, this quarterly report should be read in conjunction with the 2012 Annual Report.

Key Factors Affecting Results of Operations, Financial Condition, and Cash Flows

PG&E Corporation and the Utility believe that their results of operations, financial condition, and cash flows will continue to be materially affected by costs the Utility will incur to improve the safety and reliability of its natural gas operations, as well as by costs related to the ongoing investigations and civil lawsuits that commenced following the San Bruno accident in September 2010. Several other factors have had, or are expected to have, a material impact on PG&E Corporation’s and the Utility’s future results of operations, financial condition, and cash flows.

The Pending Investigations and Civil Litigation Related to Natural Gas Operations and the San Bruno Accident. Three CPUC investigations are pending against the Utility related to its natural gas operations and the San Bruno accident. On July 16, 2013, the SED filed an amended brief to recommend that the CPUC impose what the SED characterizes as a penalty of $2.25 billion on the Utility, consisting of a $300 million fine payable to the State General Fund and $1.950 billion of non-recoverable costs to perform work under the Utility’s pipeline safety enhancement plan and to implement the operational remedies. Under the SED’s revised recommendation, the Utility estimates that its total past and future non-recoverable costs and fines related to natural gas transmission operations would be in excess of $4 billion. Several other parties have also submitted penalty recommendations. (See “Natural Gas Matters” below.) PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows also may be materially affected by civil or criminal penalties or other remedies that may be imposed in connection with the ongoing criminal investigation of the San Bruno accident by federal, state, and local authorities. (See “Criminal Investigation” below.) It is reasonably possible that the Utility may incur as much as an additional $145 million for unresolved third-party claims related to the San Bruno accident for a cumulative possible loss of $600 million, before insurance recoveries. The Utility and most of the plaintiffs with unresolved claims are engaged in settlement discussions and mediation efforts. (See “Third-Party Claims” below.)

The Amount and Timing of the Utility’s Financing Needs . PG&E Corporation contributes equity to the Utility as needed by the Utility to maintain its CPUC-authorized capital structure. The Utility has incurred significant expenses that are not recoverable through rates, which has increased the Utility’s equity needs. For the six months ended June 30, 2013, PG&E Corporation made equity contributions to the Utility of $665 million. Additional equity issued by PG&E Corporation to fund the Utility’s future equity needs that arise due to the outcome of the pending investigations and unrecoverable costs incurred by the Utility is expected to have a material dilutive effect on PG&E Corporation’s EPS. The Utility’s financing needs also will be affected by other factors described in “Liquidity and Financial Resources” below. PG&E Corporation’s and the Utility’s ability to access the capital markets and the terms and rates of future financings could be affected by changes in their respective credit ratings, the outcome of natural gas matters, general economic and market conditions, and other factors.

The Timing and Outcome of Ratemaking Proceedings . In the 2014 GRC, the Utility is seeking an increase in its 2014 revenue requirements of $1.207 billion over the comparable revenues for 2013 that were previously authorized, as well as attrition increases for 2015 and 2016. The DRA has recommended that the CPUC approve a 2014 revenue requirement that is lower than 2013. The CPUC is scheduled to issue a decision in the 2014 GRC in late 2013. (See “2014 General Rate Case” below.) The FERC is also considering proposed changes in the Utility’s electric transmission rates in two pending TO rate cases, including the Utility’s most recent application filed on July 24, 2013. (See “Electric Transmission Owner Rate Cases” below.) Finally, the Utility plans to file an application with the CPUC in late 2013 to initiate the Utility’s 2015 GT&S rate case. (See “Gas Transmission and Storage Rate Case” below.) The outcome of these ratemaking proceedings can be affected by many factors, including general economic conditions, the level of customer rates, regulatory policies, and political considerations.

The Ability of the Utility to Control Operating Costs and Capital Expenditures. Authorized revenues are primarily set based on forecasts and assumptions about the amount of operating costs and capital expenditures the Utility will incur in future periods. PG&E Corporation’s and the Utility’s net income is negatively affected when the authorized revenues are not sufficient for the Utility to recover the costs it actually incurs to provide utility services. In 2012, the Utility incurred expenses to improve the safety and reliability of its operations that were approximately $255 million higher than the level of revenue requirements authorized in its 2011 GRC and GT&S rate case. The Utility forecasts that it will incur approximately $250 million in 2013 that it will not recover in rates, as well as capital expenditures that exceed the current authorized levels, to make additional improvements. Differences between the amount or timing of the Utility’s actual costs and forecasted or authorized amounts may also affect the Utility’s ability to earn its authorized ROE.

Summary of Changes in Earnings for 2013

The following table is a summary reconciliation of the key changes, after-tax, in PG&E Corporation’s income available for common shareholders and EPS for the three and six months ended June 30, 2013 compared to the prior year (see “Results of Operations” below for additional information):

	Three Months						Six Months
	Ended June 30,						Ended June 30,
				EPS						EPS
(in millions, except per share amounts)	Earnings			(Diluted)			Earnings			(Diluted)
Income Available for Common Shareholders - June 30, 2012	$	235		$	0.55		$	468		$	1.11
Natural gas matters (1)		91			0.22			151			0.37
Growth in rate base earnings		22			0.05			43			0.10
Environmental-related costs		(3	)		(0.01	)		39			0.09
Reduction in authorized cost of capital		(43	)		(0.09	)		(87	)		(0.19	)
Timing of incremental work		(1	)		-			(14	)		(0.03	)
Gas transmission revenues		(3	)		(0.01	)		(6	)		(0.02	)
Impact of capital spending over authorized		(5	)		(0.01	)		(5	)		(0.01	)
Nuclear refueling outage		27			0.06			-			-
Increase in shares outstanding (2)		-			(0.03	)		-			(0.07	)
Other		8			0.01			(22	)		(0.06	)
Income Available for Common Shareholders - June 30, 2013	$	328		$	0.74		$	567		$	1.29

(1)

The Utility incurred lower charges related to natural gas matters for the three and six months ended June 30, 2013, as compared to the same periods in 2012, resulting primarily from the absence of charges for third-party claims and contributions; PSEP expenses authorized for recovery in 2013; and lower legal and other expenses. See “Operating and Maintenance” below for additional information.

(2)

Represents the impact of a higher number of shares outstanding at June 30, 2013, compared to the number of shares outstanding at June 30, 2012. PG&E Corporation issues shares to fund its equity contributions to the Utility to maintain the Utility’s capital structure and fund operations, including expenses related to natural gas matters. This has no dollar impact on earnings.

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This quarterly report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions which are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management's knowledge of facts as of the date of this report.

These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines, associated with various investigations; estimated losses and insurance recoveries associated with the civil litigation arising from the San Bruno accident; forecasts of costs the Utility will incur to make safety and reliability improvements, including costs to perform work under the pipeline safety enhancement plan, that the Utility will not recover through rates; forecasts of capital expenditures; estimates and assumptions used in critical accounting policies, including those relating to regulatory assets and liabilities, environmental remediation, litigation, third-party claims, and other liabilities; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “may,” “should,” “would,” “could,” “potential” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

when and how the pending investigations and enforcement matters related to the Utility’s natural gas system operating practices and the San Bruno accident are concluded, including the ultimate amount of fines the Utility will be required to pay the State General Fund, the cost of any remedial actions the Utility may be ordered to perform, and the extent to which the Utility’s past and future unrecovered and unrecoverable costs to perform work associated with its natural gas system are considered in reaching the final outcome;

·	the ultimate amount of third-party liability incurred in connection with the San Bruno accident; the timing and amount of related insurance recoveries; and the ultimate amount of punitive damages, if any, the Utility may incur related to third-party claims;

·	the outcome of the pending criminal investigation related to the San Bruno accident, including the ultimate amount of civil or criminal fines or penalties, if any, that may be imposed, and the impact of remedial measures such as the appointment of an independent monitor;

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

·	the ultimate amount of costs the Utility incurs in the future that are not recovered through rates, including costs to perform incremental work to improve the safety and reliability of electric and natural gas operations;

·	the outcome of future investigations or proceedings that may be commenced by the CPUC or other regulatory authorities relating to the Utility’s compliance with laws, rules, regulations, or orders applicable to the operation, inspection, and maintenance of its electric and gas facilities;

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

the amount and timing of additional common stock issuances by PG&E Corporation, the proceeds of which are contributed as equity to maintain the Utility’s authorized capital structure as the Utility incurs charges and costs, including costs and fines associated with natural gas matters, that are not recoverable through rates or insurance;

the impact of environmental remediation laws, regulations, and orders; the ultimate amount of costs incurred to discharge the Utility’s known and unknown remediation obligations; the extent to which the Utility is able to recover environmental compliance and remediation costs in rates or from other sources; and the ultimate amount of environmental remediation costs the Utility incurs but does not recover, such as the remediation costs associated with the Utility’s natural gas compressor station site located near Hinkley, California;

the impact of new legislation or NRC regulations, recommendations, policies, decisions, or orders relating to the operations, seismic design, security, safety, relicensing, or decommissioning of nuclear facilities, including the Utility’s Diablo Canyon nuclear power plant, or relating to the storage of spent nuclear fuel, cooling water intake, or other issues; and whether the Utility obtains renewed operating licenses for the two nuclear operating units at Diablo Canyon;

the impact of weather-related conditions or events (such as storms, tornadoes, floods, drought, solar or electromagnetic events, and wildland and other fires), natural disasters (such as earthquakes, tsunamis, and pandemics), and other events (such as explosions, fires, accidents, mechanical breakdowns, equipment failures, human errors, and labor disruptions), as well as acts of terrorism, war, or vandalism, including cyber-attacks, that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies; and subject the Utility to third-party liability for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory penalties on the Utility;

·	the impact of environmental laws and regulations aimed at the reduction of carbon dioxide and GHGs, and whether the Utility is able to continue recovering associated compliance costs, including the cost of emission allowances and offsets, that the Utility incurs under cap-and-trade regulations;

changes in customer demand for electricity and natural gas resulting from unanticipated population growth or decline in the Utility’s service area, general and regional economic and financial market conditions, the extent of municipalization of the Utility’s electric distribution facilities, changing levels of “direct access” customers who procure electricity from alternative energy providers, changing levels of customers who purchase electricity from governmental bodies that act as “community choice aggregators,” and the development of alternative energy technologies including self-generation and distributed generation technologies;

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

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

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

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

·	changes in credit ratings which could result in increased borrowing costs, especially if PG&E Corporation or the Utility were to lose its investment grade credit ratings;

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

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

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

For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows, see “Risk Factors” in the 2012 Annual Report and “Item 1.A. Risk Factors” below. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

RESULTS OF OPERATIONS

The table below details certain items from the accompanying Condensed Consolidated Statements of Income for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in millions)	2013			2012			2013			2012
Utility
Electric operating revenues	$	3,057		$	2,930		$	5,855		$	5,701
Natural gas operating revenues		718			662			1,591			1,531
Total operating revenues		3,775			3,592			7,446			7,232
Cost of electricity		1,189			962			2,172			1,821
Cost of natural gas		179			132			525			475
Operating and maintenance		1,256			1,425			2,592			2,791
Depreciation, amortization, and decommissioning		516			606			1,019			1,190
Total operating expenses		3,140			3,125			6,308			6,277
Operating income		635			467			1,138			955
Interest income		3			2			4			3
Interest expense		(171	)		(171	)		(341	)		(339	)
Other income, net		22			22			46			45
Income before income taxes		489			320			847			664
Income tax provision		160			93			281			206
Net income		329			227			566			458
Preferred stock dividend requirement		4			4			7			7
Income Available for Common Stock	$	325		$	223		$	559		$	451
PG&E Corporation (1)
Operating revenues	$	3,776		$	3,593		$	7,448		$	7,234
Operating expenses		3,140			3,126			6,310			6,280
Operating income		636			467			1,138			954
Interest income		2			3			4			4
Interest expense		(177	)		(176	)		(353	)		(350	)
Other income, net		24			32			52			58
Income before income taxes		485			326			841			666
Income tax provision		153			87			267			191
Net income		332			239			574			475
Preferred stock dividend requirement of subsidiary		4			4			7			7
Income Available for Common Shareholders	$	328		$	235		$	567		$	468

(1) Amounts for PG&E Corporation differ from comparable amounts for the Utility due primarily to PG&E Corporation's interest expense on long-term debt, other income from investments, and income taxes.

The following presents the Utility’s operating results for the three and six months ended June 30, 2013 and 2012.

Electric Operating Revenues

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in millions)	2013			2012			2013			2012
Revenues excluding passed-through costs		$	1,611		$	1,579		$	3,198		$	3,141
Revenues for recovery of passed-through costs			1,446			1,351			2,657			2,560
Total electric operating revenues		$	3,057		$	2,930		$	5,855		$	5,701

The Utility’s total electric operating revenues increased by $127 million, or 4%, and by $154 million, or 3%, in the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012.

Electric operating revenues, excluding revenues intended to recover costs that are passed through to customers, increased by $32 million and $57 million, in the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012. Revenues increased by $51 million and $100 million for the three and six month periods, respectively, as authorized in the 2011 GRC, and were partially offset by a decrease in revenues of $42 million and $84 million, respectively, as authorized in the 2013 Cost of Capital proceeding. The increase for both periods also reflects $25 million of revenue authorized by the CPUC in 2013 for recovery of the Utility’s incremental costs of responding to storms and wildfires from 2009 to 2011.

Revenues intended to recover costs that are passed through to customers and do not impact net income increased by $95 million and $97 million for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012. The change in the three and six month periods was attributable to an increase in the cost of electricity of $227 million and $351 million, respectively (see “Cost of Electricity” below), offset by the absence of revenue of $123 million and $239 million, respectively, related to the energy recovery bonds that matured in late 2012.

The Utility’s future electric operating revenues are expected to be impacted by revenues authorized in future rate cases. (See “Regulatory Matters” below.) Future electric operating revenues will also be impacted by the cost of electricity and other revenues intended to recover costs that are passed through to customers.

Cost of Electricity

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

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

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2013		2012		2013		2012
Cost of purchased power	$	1,120	$	907	$	2,030	$	1,682
Fuel used in own generation facilities		69		55		142		139
Total cost of electricity	$	1,189	$	962	$	2,172	$	1,821
Average cost of purchased power per kWh (1)	$	0.088	$	0.072	$	0.086	$	0.074
Total purchased power (in millions of kWh)		12,788		12,529		23,674		22,819

(1) Kilowatt-hour

The Utility’s total cost of electricity increased by $227 million, or 24%, and by $351 million, or 19%, in the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012, primarily due to higher costs to purchase renewable energy and increased spot prices for electric and natural gas. The volume of power the Utility purchases is driven by customer demand, the availability of the Utility’s own generation facilities, and the cost effectiveness of each source of electricity.

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

Natural Gas Operating Revenues

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

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in millions)	2013			2012			2013			2012
Revenues excluding passed-through costs		$	431		$	445		$	870		$	880
Revenues for recovery of passed-through costs			287			217			721			651
Total natural gas operating revenues		$	718		$	662		$	1,591		$	1,531

The Utility’s natural gas operating revenues increased by $56 million, or 8%, and by $60 million, or 4% in the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012.

Natural gas operating revenues, excluding revenues intended to recover costs that are passed through to customers, slightly decreased in the three and six months ended June 30, 2013, as compared to the same periods in 2012, primarily due to an increase in base revenues as authorized in the 2011 GT&S rate case and 2011 GRC that was offset by a decrease in revenues authorized in the 2013 Cost of Capital proceeding.

Revenues intended to recover costs that are passed through to customers and do not impact net income increased by $70 million in the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012. The increase in both periods is primarily due to the higher cost of natural gas of $47 million and $50 million, respectively. (See “Cost of Natural Gas” below.) The increase for both periods also included $29 million and $36 million, respectively, of revenues authorized by the CPUC (subject to refund) under the Utility’s pipeline safety enhancement plan, with no similar revenues in the prior year (see “Natural Gas Matters” below).

The Utility’s future natural gas operating revenues are expected to be impacted by the CPUC decision in the Utility’s 2014 GRC and the 2015 GT&S rate case. (See “Regulatory Matters” below.) Future gas operating revenues will also be impacted by the cost of natural gas, natural gas throughput volume, and other factors.

Cost of Natural Gas

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

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

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2013		2012		2013		2012
Cost of natural gas sold	$	137	$	85	$	437	$	379
Transportation cost of natural gas sold		42		47		88		96
Total cost of natural gas	$	179	$	132	$	525	$	475
Average cost per Mcf (1) of natural gas sold	$	3.43	$	1.70	$	3.08	$	2.54
Total natural gas sold (in millions of Mcf)		40		50		142		149

(1) One thousand cubic feet

The Utility’s total cost of natural gas increased by $47 million, or 36%, and by $50 million, or 11%, in the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012, primarily due to a higher average market price of natural gas in the second quarter of 2013.

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

Operating and Maintenance

Operating and maintenance expenses consist mainly of the Utility’s costs to operate and maintain its electricity and natural gas facilities, customer billing and service expenses, the cost of public purpose programs, and administrative and general expenses. The Utility’s ability to earn its authorized rate of return depends in part on its ability to manage its expenses and to achieve operational and cost efficiencies.

The Utility’s operating and maintenance expenses decreased by $169 million, or 12%, from $1,425 million in the three months ended June 30, 2012 to $1,256 million in the three months ended June 30, 2013. The decrease was primarily due to $154 million of lower net costs associated with natural gas matters that are not recoverable through rates (see table below). The decrease also reflects $46 million of costs associated with a refueling outage at Diablo Canyon in 2012, with no similar activity in the three months ended June 30, 2013. Operating and maintenance expense for 2013 also included an increase of $29 million of PSEP-related expenses that were authorized for recovery, subject to refund. (See “Natural Gas Matters” below.)

The Utility’s operating and maintenance expenses decreased by $199 million, or 7%, from $2,791 million in the six months ended June 30, 2012 to $2,592 million in the six months ended June 30, 2013. The total decrease was primarily due to $255 million of lower net costs associated with natural gas matters that are not recoverable through rates (see table below) and a $61 million decrease in environmental remediation costs associated with a charge to income in 2012 for the Hinkley natural gas compressor site. These costs were partially offset by an increase of approximately $65 million related to labor and benefit-related costs, timing of work to improve the safety and reliability of the Utility’s electric and natural gas operations, and other expenses. Operating and maintenance expense for 2013 also included an increase of $36 million of PSEP-related expenses that were authorized for recovery, subject to refund. (See “Natural Gas Matters” below.)

The following table provides a summary of the Utility’s costs associated with natural gas matters that are not recoverable through rates:

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2013			2012			2013			2012
Pipeline-related expenses (1) (2)	$	74		$	128		$	136		$	232
Third-party claims		-			80			-			80
Insurance recoveries		(45	)		(25	)		(45	)		(36	)
Contribution to City of San Bruno		-			-			-			70
Total natural gas matters	$	29		$	183		$	91		$	346

(1) For the three and six months ended June 30, 2013, unrecoverable pipeline-related expenses included $22 million and $47 million, respectively, for work performed under the Utility’s pipeline safety enhancement plan.

(2) The decrease in unrecoverable pipeline-related expenses reflects amounts that were authorized for recovery in the CPUC’s December 2012 decision (as described above) as well as lower legal and other expenses in 2013.

The Utility forecasts that the total unrecoverable pipeline-related expenses in 2013 will range from $400 million to $500 million. These amounts include costs to validate safe operating pressures, conduct strength testing, and perform other work associated with safety improvements to the Utility’s natural gas pipeline system; costs related to the Utility’s multi-year effort to identify and remove encroachments (e.g. building structures and vegetation overgrowth) from transmission pipeline rights-of-way, to improve the integrity of transmission pipelines and to perform other gas-related work, and legal and other expenses. For the three and six months ended June 30, 2013, the Utility did not record any charges related to penalties or third-party claims.

Under the SED’s latest penalty recommendation, the Utility estimates that its total past and future non-recoverable costs and fines related to natural gas transmission operations would be in excess of $4 billion. (See “Natural Gas Matters” below.) Future operating and maintenance expense will also continue to be affected by any additional charges for third-party claims arising from the San Bruno accident that are not recoverable through insurance, charges for civil or criminal penalties, or punitive damages, if any, that may be imposed on the Utility. The Utility may incur costs to implement any remedial actions the CPUC may order the Utility to perform. (See “Natural Gas Matters” below.)

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation and amortization expense consists of depreciation and amortization on plant and regulatory assets, and decommissioning expenses associated with fossil fuel-fired generation facilities and nuclear power facilities. The Utility’s depreciation, amortization, and decommissioning expenses decreased by $90 million, or 15%, and by $171 million, or 14%, in the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012. The decrease in the three and six months ended June 30, 2013 is primarily due to the absence of amortization expense of $118 million and $227 million, respectively, for the energy recovery bonds regulatory asset which fully amortized in 2012. The decreases in both periods were partially offset by the impact of capital additions.

The Utility’s depreciation expense for future periods is expected to be affected as a result of changes in capital expenditures and the implementation of new depreciation rates as authorized by the CPUC in the future 2014 GRC and 2015 GT&S rate case. Future TO rate cases authorized by the FERC will also have an impact on depreciation rates.

Interest Income, Interest Expense and Other Income, Net

There were no material changes to interest income, interest expense and other income, net for the three and six months ended June 30, 2013, as compared to the same periods in 2012.

Income Tax Provision

The Utility’s income tax provision increased by $67 million, or 72%, and $75 million, or 36%, in the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012. The effective tax rates for the three months ended June 30, 2013 and 2012 were 33% and 29%, respectively. The effective tax rates for the six months ended June 30, 2013 and 2012 were 33% and 31%, respectively. The effective tax rates increased for both periods during 2013 due to the effect of regulatory treatment of fixed asset timing differences (which reverse over time) related to the cost of removal of fixed assets and decommissioning costs.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

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

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

The Utility’s future equity needs will continue to be affected by costs that are not recoverable through rates, including costs related to natural gas matters. The Utility’s equity needs would also increase to the extent it is required to pay fines or penalties in connection with the pending investigations. (See “Natural Gas Matters” below.) Further, given the Utility’s significant ongoing capital expenditures, the Utility will continue to need equity contributions from PG&E Corporation to maintain its authorized capital structure.

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

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

2013 Financings

Utility

In June 2013, the Utility issued $ 375 million principal amount of 3.25% Senior Notes due June 15, 2023 and $ 375 million principal amount of 4.60% Senior Notes due June 15, 2043 . The proceeds were used to repurchase $461 million principal amount, net of $21 million of premiums and accrued interest, of the Utility’s $1.0 billion outstanding 4.80% Senior Notes due March 1, 2014, to repay a portion of outstanding commercial paper, and for general corporate purposes.

PG&E Corporation

In May 2013 , PG&E Corporation entered into a new Equity Distribution Agreement providing for the sale of PG&E Corporation common stock having an aggregate gross sales price of up to $ 400 million. As of June 30, 2013 , PG&E Corporation common stock having an aggregate gross sales price of $50 million had been sold under this equity distribution agreement.

During the six months ended June 30, 2013 , PG&E Corporation issued 14 million shares of its common stock for aggregate net cash proceeds of $ 562 million in the following transactions:

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

·	4 million shares that were issued for cash proceeds of $149 million under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans; and

·	3 million shares were sold for cash proceeds of $113 million, net of commissions paid of $1 million, under the equity distribution agreements.

The proceeds from these sales were used for general corporate purposes, including the infusion of equity into the Utility. For the six months ended June 30, 2013, PG&E Corporation made equity contributions to the Utility of $665 million. PG&E Corporation forecasts that it will need to continue to issue additional common stock to fund the Utility’s equity needs.

Revolving Credit Facilities and Commercial Paper Program

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings at June 30, 2013:

					Letters of
	Termination	Facility			Credit				Commercial			Facility
	Date	Limit			Outstanding		Borrowings		Paper			Availability
(in millions)
PG&E Corporation	April 2018	$	300	(1)	$	-	$	260	$	-		$	40
Utility	April 2018		3,000	(2)		91		-		692	(3)		2,217	(3)
Total revolving
credit facilities		$	3,300		$	91	$	260	$	692		$	2,257

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

(2) Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.

(3) The Utility treats the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facility.

For the six months ended June 30, 2013, the average outstanding borrowings under PG&E Corporation’s revolving credit facility were $168 million and the maximum outstanding balance during the period was $260 million. For the six months ended June 30, 2013, the Utility’s average outstanding commercial paper balance was $495 million and the maximum outstanding balance during the period was $1.0 billion. The Utility has not borrowed under its credit facility during 2013.

At June 30, 2013, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

Dividends

In June 2013 , the Board of Directors of PG&E Corporation declared quarterly dividends of $0.455 per share, totaling $202 million, of which $197 million was paid on July 15, 2013 to shareholders of record on July 1, 2013.

In June 2013, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on August 15, 2013, to shareholders of record on July 31, 2013.

Utility

Operating Activities

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

The Utility’s cash flows from operating activities for the six months ended June 30, 2013 and 2012 were as follows:

(in millions)	2013			2012
Net income	$	566		$	458
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, amortization, and decommissioning		1,019			1,190
Allowance for equity funds used during construction		(52	)		(53	)
Deferred income taxes and tax credits, net		337			242
Other		126			108
Net effect of changes in operating assets and liabilities		(532	)		229
Net cash provided by operating activities	$	1,464		$	2,174

During 2013, net cash provided by operating activities decreased by $710 million compared to 2012. This decrease was driven by fluctuations in activities within the normal course of business such as the timing and amount of payments, including tax payments due to audit settlements.

Future cash flow from operating activities will be affected by various factors, including:

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

·	the timing and amount of tax payments, tax refunds, net collateral payments, and interest payments;

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

·	the timing and amount of fines or penalties that may be imposed, as well as any costs associated with remedial actions the CPUC may order the Utility to perform;

·	the anticipated higher operating and maintenance costs associated with the Utility’s natural gas and electric operations (see “Operating and Maintenance” above and “Natural Gas Matters” below); and

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

Investing Activities

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

The Utility’s cash flows from investing activities for the six months ended June 30, 2013 and 2012 were as follows:

(in millions)	2013			2012
Capital expenditures	$	(2,521	)	$	(2,219	)
Decrease (increase) in restricted cash		25			(1	)
Proceeds from sales and maturities of nuclear decommissioning trust investments		795			666
Purchases of nuclear decommissioning trust investments		(786	)		(716	)
Other		8			11
Net cash used in investing activities	$	(2,479	)	$	(2,259	)

Net cash used in investing activities increased by $220 million in 2013 compared to 2012 primarily due to higher capital expenditures.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility forecasts that capital expenditures will total approximately $5.1 billion in 2013, including expenditures related to its pipeline safety enhancement plan. For more information about the types of capital investments made by the Utility, see “Capital Expenditures” in the 2012 Annual Report.

Financing Activities

The Utility’s cash flows from financing activities for the six months ended June 30, 2013 and 2012 were as follows:

(in millions)	2013			2012
Net issuance (repayments) of commercial paper, net of discount of $1 and $2
at respective dates		321			(566	)
Proceeds from issuance of long-term debt, net of premium, discount, and issuance
costs of $8 and $6 at respective dates		742			394
Long-term debt matured or repurchased		(461	)		(50	)
Energy recovery bonds matured		-			(200	)
Preferred stock dividends paid		(7	)		(7	)
Common stock dividends paid		(358	)		(358	)
Equity contribution		665			565
Other		(20	)		48
Net cash provided by (used in) financing activities	$	882		$	(174	)

In 2013, net cash provided by financing activities increased by $1.1 billion compared to the same period in 2012. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date of existing debt instruments. The Utility generally utilizes long-term senior unsecured debt issuances and equity contributions from PG&E Corporation to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.

CONTRACTUAL COMMITMENTS

PG&E Corporation and the Utility enter into contractual commitments in connection with future obligations that relate to financing arrangements (such as long-term debt, preferred stock, and certain forms of regulatory financing), purchases of electricity and natural gas for customers, purchases of transportation capacity, purchases of renewable energy, and purchases of fuel and transportation to support the Utility’s generation activities. (Refer to the 2012 Annual Report and “Liquidity and Financial Resources” above.)

NATURAL GAS MATTERS

PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows, have continued to be negatively affected by costs the Utility has incurred to improve the safety and reliability of the Utility’s natural gas operations, as well as by costs related to the on-going regulatory proceedings, investigations, and civil lawsuits related to the San Bruno accident and the Utility’s natural gas operations. During 2013, the Utility has continued to make progress on efforts to improve the safety of its gas transmission system and to satisfy recommendations made by the NTSB and the CPUC following their investigations into the San Bruno accident. At June 30, 2013, the Utility has officially satisfied seven of the twelve NTSB recommendations. In June 2013, the Utility requested closure on two more recommendations and continues to make progress on the remaining longer-term recommendations.

Since the San Bruno accident, PG&E Corporation and the Utility have incurred total cumulative charges of approximately $1.9 billion related to natural gas matters that are not recoverable through rates, as shown in the following table:


	Cumulative			Six Months Ended			Cumulative
(in millions)	December 31, 2012			June 30, 2013			June 30, 2013
Pipeline-related expenses (1) (2)	$	1,023		$	136		$	1,159
Disallowed capital expenditures (3)		353			-			353
Accrued penalties (4)		217			-			217
Third-party claims (5)		455			-			455
Insurance recoveries (5)		(284	)		(45	)		(329	)
Contribution to City of San Bruno		70			-			70
Total natural gas matters	$	1,834		$	91		$	1,925

(1)	Cumulative costs through December 31, 2012 include PSEP-related expenses of approximately $600 million and other gas safety-related work of $185 million

(2)	The Utility forecasts that total pipeline-related expenses for 2013 will range from $400 million to $500 million.

(3)	In 2012, the Utility recorded a charge for plan-related capital expenditures incurred, corresponding to expenditures that are forecasted to exceed the CPUC’s authorized levels or that were specifically disallowed.

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

(5)	See “Third-Party Claims” below.

The Utility estimates that its total past and future unrecovered costs related to natural gas transmission operations exceeds $2.2 billion, which includes the following components:

·	$1,251 million for disallowed PSEP expenses and capital costs, and;

·	$964 million for other gas safety-related work (including pipeline integrity management and rights-of-way maintenance)

As described below, the SED recommended that the CPUC impose what the SED characterizes as a penalty of $2.25 billion on the Utility, consisting of a $300 million fine and $1.95 billion of non-recoverable costs. After considering $435 million of disallowed costs incurred that would be applied towards the penalty, the Utility estimates that its unrecovered costs for PSEP and other gas safety-related work would increase by $1.5 billion. If the SED’s latest penalty recommendation is adopted by the CPUC, the Utility estimates that its total past and future unrecovered costs and fines related to natural gas transmission operations would be in excess of $4 billion.

CPUC Gas Safety Rulemaking Proceeding

The second phase of the Utility’s pipeline safety enhancement plan beginning in 2015 will focus on pipeline segments in less populated areas, as well as certain pressure testing and pipeline replacement work that the CPUC deferred from the first phase. The Utility expects to address the scope, timing, and cost recovery of continuing work to enhance the safety and reliability of the gas pipeline system in the 2015 GT&S rate case. (See “2015 Gas Transmission and Storage Rate Case” below.)

Pending CPUC Investigations and Enforcement Matters

Other Potential Enforcement Matters

Criminal Investigation

Third-Party Claims

The Utility has recorded cumulative charges of $455 million for estimated third-party claims, including personal injury, property damage, damage to infrastructure, and other damage claims. At June 30, 2013, the Utility has made cumulative payments of $388 million for settlements. The Utility estimates it is reasonably possible that it may incur as much as an additional $145 million for unresolved claims, for a total possible loss of $600 million since the San Bruno accident. The Utility and most of the plaintiffs with unresolved claims are engaged in settlement discussions with the assistance of mediators. Settlement discussions with some plaintiffs may conclude in the third quarter of 2013. PG&E Corporation and the Utility are unable to estimate the amount or range of reasonably possible losses associated with punitive damages, if any, related to these matters.

Through June 30, 2013, the Utility has recognized cumulative insurance recoveries of $329 million for third-party claims and related legal expenses. (The Utility has incurred cumulative legal expenses of $81 million in addition to the $455 million charge above). Insurance recoveries for the three and six months ended June 30, 2013 were $45 million. These amounts were recorded as a reduction to operating and maintenance expense in PG&E Corporation’s and the Utility’s Condensed Consolidated Statements of Income. Although the Utility believes that a significant portion of costs incurred for third-party claims relating to the San Bruno accident will ultimately be recovered through its insurance, it is unable to predict the amount and timing of additional insurance recoveries. (See Note 10 to the Condensed Consolidated Financial Statements.)

Class Action Complaint

PG&E Corporation and the Utility contest the plaintiffs’ allegations. On May 23, 2013, the court granted PG&E Corporation’s and the Utility’s request to dismiss the complaint on the grounds that the CPUC has exclusive jurisdiction to adjudicate the issues raised by the plaintiffs’ allegations. PG&E Corporation and the Utility are unable to estimate the amount or range of reasonably possible losses that may be incurred in connection with this matter.

Other Pending Lawsuits and Claims

At June 30, 2013, there were two purported shareholder derivative lawsuits outstanding against PG&E Corporation and the Utility. In October 2010, a derivative lawsuit was filed in San Mateo Superior Court following the San Bruno accident to seek recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims, relating to the Utility’s natural gas business. The proceedings have been stayed until further order of the court. On February 7, 2013, another derivative lawsuit was filed in U.S. District Court for the Northern District of California to seek recovery on behalf of PG&E Corporation for alleged breaches of fiduciary duty by officers and directors, among other claims. By agreement among the parties, this second derivative lawsuit is stayed in its entirety pending resolution of the first filed matter.

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

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

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC and other federal and state regulatory agencies. The resolutions of these and other proceedings may affect PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. Significant regulatory developments that have occurred since the 2012 Annual Report was filed with the SEC are discussed below.

2014 General Rate Case

In the GRC, the CPUC will determine the annual amount of revenue requirements that the Utility is authorized to collect through rates from 2014 through 2016 to recover anticipated costs associated with electric generation operations, and electric and natural gas distribution operations, and to provide the Utility an opportunity to earn its authorized ROE on related capital expenditures. The Utility is seeking an increase in its 2014 revenue requirements of $1,207 million over the comparable revenues for 2013 that were previously authorized by the CPUC. The Utility’s request is based on detailed expense and capital forecasts for 2014. On May 3, 2013, the CPUC’s DRA submitted testimony recommending that the Utility’s 2014 revenue requirements be reduced by $162 million from amounts authorized in 2013, approximately $1,369 million lower than the Utility’s current forecast. The DRA also recommended that the Utility receive attrition increases of $168 million for 2015 and $159 million for 2016, as compared to the Utility’s requests of $475 million and $485 million, respectively.

The following table compares the Utility’s forecasted annual increases for 2014 through 2016 with the DRA’s recommended amounts:

	Increase (Decrease) to Revenue Requirements					Difference Between
(in millions)	Utility's Forecast (1)		DRA's Recommendation			Utility and DRA
2014	$	1,207	$	(162	)	$	(1,369	)
2015 attrition		475		168			(307	)
2016 attrition		485		159			(326	)

(1) Amounts reflect the Utility’s authorized cost of capital for 2013 and other adjustments to amounts requested in the Utility’s November 2012 application as a result of revised calculations.

The DRA’s recommendation reflects reductions across all lines of business represented in the GRC. The DRA also recommended that the CPUC moderate impacts on customer rates by reducing the amount of depreciation recovered through rates throughout the GRC period to approximately $160 million as compared to the $495 million increase supported by the Utility’s depreciation rate study. Finally, the DRA recommended that the Utility's capital expenditures for the lines of business be reduced by $1.0 billion in 2014, as compared to the Utility’s forecast of average annual capital expenditures of $4.0 billion from 2014 to 2016.

On May 17, 2013, 12 other parties, including TURN, submitted their recommendations. TURN’s recommendation reflects reductions across most lines of business represented in the GRC, including significant reductions to the amount of depreciation recovered through rates. Also, the SED submitted the reports of consultants it engaged to evaluate the Utility’s use of safety risk assessment and risk mitigation measures in developing the Utility’s forecast. Overall, the reports found that most of the Utility’s forecasted projects and costs were generally reasonable but criticized the Utility’s level of risk analysis underlying the forecast.

On May 31, 2013, the SED submitted a report prepared by a financial consultant engaged by the SED to review the Utility’s expenditures on its gas distribution system from 1999 to 2010. During that time period, the consultant alleged that the Utility spent less on capital expenditures and operation and maintenance expense than it recovered in rates, by $168 million and $56 million, respectively. The consultant also alleged that from 2003 to 2010 the Utility collected $100 million more in revenues than needed to earn its authorized ROE. The Utility believes the consultant’s methodology was erroneous and utilized incorrect assumptions. In contrast to the SED’s consultant’s findings, the Utility’s financial consultant concluded that over the relevant period, the Utility’s capital expenditures exceeded adopted amounts, the Utility’s operation and maintenance expenses were consistent with authorized amounts, and the Utility’s actual ROE was consistent with the authorized ROE.

On June 28, 2013, the Utility submitted testimony to respond to the parties’ recommendations and to the SED reports. The Utility believes that the recommendations from DRA and TURN to substantially reduce its forecast revenue requirements could undermine the Utility’s efforts to improve customer safety, reliability and service over the next three years. The Utility also believes that the parties have not properly taken into account the substantial capital costs and expenses that the Utility has already incurred to improve the safety and reliability of its operations. In 2012, the Utility incurred expenses that were approximately $255 million higher than the level of revenue requirements authorized in its 2011 GRC and GT&S rate case. The Utility forecasts that it will incur approximately $250 million in 2013 that it will not recover in rates, as well as capital expenditures that exceed the current authorized levels, to make additional improvements. (See “Operating and Maintenance” above.)

The CPUC began evidentiary hearings on July 15, 2013 and they are scheduled to conclude in August 2013. The CPUC’s procedural schedule contemplates a proposed decision to be released by November 19, 2013 and a final CPUC decision to be issued by December 19, 2013.

Electric Transmission Owner Rate Cases

On July 24, 2013, the Utility filed an application with the FERC to request authorization of its proposed 2014 retail electric transmission revenue requirement of $1.072 billion, a $30 million reduction as compared to the currently effective revenue requirement. (The currently effective revenue requirement is being collected through TO rates that became effective, subject to refund, on May 1, 2013.) Although the Utility’s cost forecasts support a projected 2014 retail revenue requirement of $1.197 billion, the Utility has voluntarily reduced its requested 2014 revenue requirement in order to allow proposed rates to become effective on October 1, 2013. The Utility anticipates that its revenues between October 1, 2013 and March 15, 2016 (when rate changes from the next TO rate case application to be filed in 2014 are expected to become effective) will be greater than if it had requested a rate increase which could not take effect until March 1, 2014.

The Utility’s 2014 cost forecasts reflect the continuing need to replace and modernize aging electric transmission infrastructure; to expand its electric transmission system; and to interconnect new electric generation resources to keep pace with projected long-term load growth and to facilitate delivery of renewable energy resources. The Utility also forecasts it will incur increased costs to maintain and improve the reliability of its transmission system in California and to comply with new rules aimed at ensuring the physical and cyber security of the nation’s electric system. The Utility forecasts that it will make investments of $810 million in 2013 and an additional $998 million in 2014 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 proposed rate base in 2014 is forecast to be $4.6 billion compared to $3.8 billion in 2012. The Utility has requested that the FERC approve a 10.9% ROE for 2014. The Utility has requested the FERC to issue an order by September 24, 2013 to accept the application and make the new rates effective on October 1, 2013, subject to refund pending a final decision by the FERC.

The Utility and other parties have been engaged in settlement discussions. Any settlement that may be reached would be subject to the FERC’s approval.

2015 Gas Transmission and Storage Rate Case

In the Utility’s GT&S rate case, the CPUC will determine the amount of revenue requirements the Utility is authorized to collect through rates for its gas transmission and storage services beginning January 1, 2015. The Utility also expects to address the scope, timing, and cost recovery of continuing work to enhance the safety and reliability of the gas pipeline system in the 2015 GT&S rate case. The Utility expects to file its formal application with the CPUC in late 2013 to initiate the proceeding.

Oakley Generation Facility

In December 2012, the CPUC approved an amended purchase and sale agreement between the Utility and a third-party developer that provides for the construction of a 586-megawatt natural gas-fired facility in Oakley, California. The CPUC authorized the Utility to recover the purchase price through rates. On April 18, 2013, the CPUC denied various applications for rehearing that had been filed with respect to the CPUC’s December 2012 decision. The CPUC’s denial of the rehearing applications has been appealed to the California Court of Appeal. The Utility is uncertain when these appeals will be resolved and how their resolution will impact the ultimate development and construction of the Oakley facility.

Diablo Canyon Nuclear Power Plant

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

The CPUC is also considering the Utility’s December 2012 application to recover estimated costs to decommission the Utility’s nuclear facilities at Diablo Canyon and the retired nuclear facility located at the Utility’s Humboldt Bay Generation Station. The Utility files an application with the CPUC every three years requesting approval of the Utility’s estimated decommissioning costs and authorization to recover the estimated costs through rates. As discussed in the 2012 Annual Report, the estimated discounted cost to decommission the Utility’s nuclear power plants increased by $1.4 billion due to higher spent nuclear fuel disposal costs and an increase in the scope of work. The CPUC bifurcated the proceeding so that cost estimates associated with Humboldt Bay are addressed first and all other matters (including those related to Diablo Canyon) are addressed later. The CPUC is scheduled to issue a proposed decision regarding the cost estimates associated with the Humboldt Bay in November 2013.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. (See “Risk Factors” in the 2012 Annual Report.) These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous wastes; the reporting and reduction of carbon dioxide and other GHG emissions; the discharge of pollutants into the air, water, and soil; and the transportation, handling, storage, and disposal of spent nuclear fuel.

Hinkley Site

At June 30, 2013 and December 31, 2012, $207 million and $226 million, respectively, were accrued in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets for estimated undiscounted future remediation costs associated with the Hinkley site. Remediation costs for the Hinkley site are not recovered from customers through rates. Future costs will depend on many factors, including the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the required time period by which those standards must be met, the extent of the chromium plume boundary, and adoption of a final drinking water standard currently under development by the State of California. As more information becomes known regarding these factors, the Utility’s cost estimates and the assumptions on which they are based regarding the amount of liability incurred may be subject to further changes. Future changes in estimates or assumptions may have a material impact on PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows.

GHG Cap-and-Trade

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

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

OFF-BALANCE SHEET ARRANGEMENTS

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed in Note 2 of the Notes to the Condensed Consolidated Financial Statements (PG&E Corporation’s tax equity financing agreements) and Note 15 of the Notes to the Consolidated Financial Statements in the 2012 Annual Report (the Utility’s commodity purchase agreements).

RISK MANAGEMENT ACTIVITIES

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

The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes. The Utility’s risk management activities include the use of energy and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases. These activities are discussed in detail in the 2012 Annual Report. There were no significant developments to the Utility and PG&E Corporation’s risk management activities during the six months ended June 30, 2013.

CRITICAL ACCOUNTING POLICIES

The preparation of the Condensed Consolidated Financial Statements in accordance with U.S. generally accepted accounting principles involved the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. PG&E Corporation and the Utility consider their accounting policies for regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal and regulatory matters, asset retirement obligations, and pension and other postretirement benefits plans to be critical accounting policies due, in part, to these accounting policies’ complexity, relevance and materiality to the financial position and results of operations of PG&E Corporation and the Utility, and requirement to use material judgments and estimates. Actual results may differ substantially from these estimates. These accounting policies and their key characteristics are discussed in detail in the 2012 Annual Report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4. CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of June 30, 2013, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal control over financial reporting that occurred during the quarter ended June 30, 2013 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In addition to the following legal proceedings, PG&E Corporation and the Utility are involved in various legal proceedings in the ordinary course of their business. For more information regarding PG&E Corporation’s and the Utility’s contingencies, see Note 10 of the Notes to the Condensed Consolidated Financial Statements.

Diablo Canyon Nuclear Power Plant

In June 2013, the United States EPA and environmental group Riverkeeper agreed to extend until November 4, 2013 the deadline for the EPA to issue final regulations under Section 316(b) of the federal Clean Water Act requiring that cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, reflect the best technology available to minimize adverse environmental impacts. The EPA’s final regulations could affect future negotiations between the Central Coast Board and the Utility regarding the status of the 2003 settlement agreement. For more information regarding the status of the 2003 settlement agreement between the Central Coast Regional Water Quality Control Board and the Utility, see “Part I, Item 3. Legal Proceedings” in the 2012 Annual Report.

Litigation Related to the San Bruno Accident and Natural Gas Spending

Various lawsuits have been filed in San Mateo County Superior Court against PG&E Corporation and the Utility in connection with the San Bruno accident, including two class action lawsuits. The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages. At June 30, 2013, the Utility has entered into settlement agreements to resolve the claims of approximately 150 plaintiffs. The Utility and most of the remaining plaintiffs are engaged in settlement discussions. Additionally, at June 30, 2013, there were two purported shareholder derivative lawsuits outstanding against PG&E Corporation and the Utility seeking recovery on behalf of PG&E Corporation for alleged breaches of fiduciary duty by officers and directors, among other claims. One of these lawsuits has been coordinated with the other cases in the San Mateo County Superior Court. The judge has ordered that proceedings in the derivative lawsuit be delayed until further order of the court. The other purported shareholder derivative lawsuit, filed in U.S. District Court for the Northern District of California, has been stayed pending the resolution of the first-filed derivative matter. PG&E Corporation and the Utility are uncertain when and how these derivative lawsuits will be resolved.

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

For additional information, see “Part I, Item 3. Legal Proceedings” in the 2012 Annual Report and the discussion entitled “Natural Gas Matters” above in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 10 of the Notes to the Condensed Consolidated Financial Statements.

Pending CPUC Investigations and Enforcement Matters

There are three CPUC investigative enforcement proceedings pending against the Utility related to the Utility’s natural gas operations and the San Bruno accident. Evidentiary hearings and briefing on the issue of alleged violations have been completed in each of these investigations. The CPUC has stated that it is prepared to impose significant penalties on the Utility if the CPUC determines that the Utility violated applicable laws, rules, and orders. On July 16, 2013, the SED filed an amended brief to recommend that the CPUC impose what the SED characterizes as a penalty of $2.25 billion on the Utility, consisting of a $300 million fine payable to the State General Fund and $1.950 billion of non-recoverable costs to perform work under the Utility’s pipeline safety enhancement plan and to implement the operational remedies. Several other parties have also submitted penalty recommendations.

As of June 30, 2013, the Utility has also submitted 55 self-reports with the SED, plus additional follow-up reports, to provide notice about self-identified and self-corrected violations of certain state and federal regulations related to the safety of natural gas facilities and natural gas operating practices. The SED is authorized to issue citations and impose penalties on the Utility associated with these or future reports that the Utility may file. PG&E Corporation and the Utility are uncertain whether the SED will issue citations and impose penalties on the Utility based on the self-reports the Utility has already submitted.

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

For additional information, see “Part I, Item 3. Legal Proceedings” in the 2012 Annual Report and the discussion entitled “Natural Gas Matters – Pending CPUC Investigations and Enforcement Matters” above in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 10 of the Notes to the Condensed Consolidated Financial Statements.

Criminal Investigation

ITEM 1A. RISK FACTORS

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

The ultimate outcome of the pending investigations related to the Utility’s natural gas operations and the San Bruno accident may require the Utility to incur material charges for non-recoverable costs associated with its natural gas operations as well as for civil or criminal fines and penalties. Such charges could negatively affect the availability, amount, and timing of future debt and equity issuances.

As discussed above in the section entitled “Natural Gas Matters − Pending CPUC Investigations and Enforcement Matters,” in Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations, on July 16, 2013, the SED filed an amended brief in the CPUC’s investigative enforcement proceedings to change its previous penalty recommendation. The SED has recommended that the Utility pay a penalty of $2.25 billion, including (1) a $300 million fine to the State General Fund, (2) $435 million for a portion of PSEP costs that were previously disallowed by the CPUC and funded by shareholders, and (3) $1.515 billion to perform PSEP work that was previously approved by the CPUC, implement operational remedies, and for future PSEP costs. Under the SED’s revised recommendation, the Utility estimates that its total past and future non-recoverable costs and fines related to natural gas transmission operations would be in excess of $4 billion. Other parties also have submitted penalty recommendations, including the payment of a fine to the State General Fund of differing amounts. On July 30, 2013, the ALJs issued a ruling requesting the Utility to provide answers to questions about its financing plans, how it intends to treat fines or disallowed costs for regulatory accounting and tax purposes, and the impact on rates. The Utility’s response is due on August 14, 2013. The ALJs have asked all parties to file comments by September 13, 2013 to address the impact that fines and disallowances would have on the Utility’s ability to raise capital and otherwise remain financially viable, including the tax treatment of amounts disallowed.

If the final decision requires the Utility to pay penalties or fines to the State General Fund that are materially higher than the $200 million accrued at June 30, 2013, disallows additional PSEP-related costs that were previously authorized for recovery, or prohibits the Utility from recovering other future pipeline expenses, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows will be materially affected. Future developments in the criminal investigation arising from the San Bruno accident also could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. (See the sections entitled “Criminal Investigation” under the heading “Natural Gas Matters” in Item 2: Management’s Discussion and Analysis of Financial Condition and Results of Operations.)

The Utility’s financing needs would increase if the Utility were required to incur unrecoverable costs and pay fines as a result of the outcome of the investigations. Such financing may become more difficult to obtain, especially if the outcome affected the Utility’s credit ratings. In addition, the equity component of the Utility’s authorized capital structure could decrease materially as the Utility incurs charges to reflect fines and unrecovered costs the Utility may be required to bear. PG&E Corporation primarily has relied on the public sale of its common stock to raise the funds it contributes to meet the Utility’s equity needs. The market price of PG&E Corporation common stock could decline materially depending on the outcome of the investigations and the amount and timing of future share issuances. Declines in the stock price could increase the dilutive effect of future stock issuances and make it more difficult or expensive for PG&E Corporation to complete future equity offerings.

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

During the quarter ended June 30, 2013, PG&E Corporation made equity contributions totaling $295 million to the Utility in order to maintain the 52% common equity component of its CPUC-authorized capital structure. Neither PG&E Corporation nor the Utility made any sales of unregistered equity securities during the quarter ended June 30, 2013.

Issuer Purchases of Equity Securities

During the quarter ended June 30, 2013, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the quarter ended June 30, 2013, 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, 2013 was 2.91. The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the six months ended June 30, 2013 was 2.86. 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 No. 333-172394.

PG&E Corporation’s earnings to fixed charges ratio for the six months ended June 30, 2013 was 2.79. The statement of the foregoing ratio, together with the statement of the computation of the foregoing ratio filed as Exhibit 12.3 hereto, is included herein for the purpose of incorporating such information and Exhibit into PG&E Corporation’s Registration Statement No. 333-172393.

ITEM 6. EXHIBITS

	3.1	Amended Bylaws of PG&E Corporation effective June 19, 2013

	3.2	Amended Bylaws of Pacific Gas and Electric Company effective June 19, 2013

	4.1	Nineteenth Supplemental Indenture dated as of June 14, 2013 relating to the issuance of $375,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due June 15, 2023 and $375,000,000 aggregate principal amount of its 4.60% Senior Notes due June 15, 2043 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 14, 2013 (File No. 1-2348), Exhibit 4.1)

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

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

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

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

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

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

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

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

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB		XBRL Taxonomy Extension Labels Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

*	Management contract or compensatory agreement.

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

SIGNATURES

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

PG&E CORPORATION

KENT M. HARVEY

Kent M. Harvey

Senior Vice President and Chief Financial Officer

(duly authorized officer and principal financial officer)

PACIFIC GAS AND ELECTRIC COMPANY

DINYAR B. MISTRY

Dinyar B. Mistry

Vice President, Chief Financial Officer and Controller

(duly authorized officer and principal financial officer)

Dated: July 31, 2013

EXHIBIT INDEX

	3.1	Amended Bylaws of PG&E Corporation effective June 19, 2013

	3.2	Amended Bylaws of Pacific Gas and Electric Company effective June 19, 2013

	4.1	Nineteenth Supplemental Indenture dated as of June 14, 2013 relating to the issuance of $375,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due June 15, 2023 and $375,000,000 aggregate principal amount of its 4.60% Senior Notes due June 15, 2043 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 14, 2013 (File No. 1-2348), Exhibit 4.1)

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

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

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

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

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

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

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

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

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB		XBRL Taxonomy Extension Labels Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

* Management contract or compensatory agreement.

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

TABLE OF CONTENTS

Part I. Financial Informationprint Item 1. Condensed Consolidated Financial Statementsprint Note 1: Organization and Basis Of Presentationprint Note 2: Significant Accounting Policiesprint Note 3: Regulatory Assets, Liabilities, and Balancing Accountsprint Note 4: Debtprint Note 5: Equityprint Note 6: Earnings Per Shareprint Note 7: Derivativesprint Note 8: Fair Value Measurementsprint Note 9: Resolution Of Remaining Chapter 11 Disputed Claimsprint Note 10: Commitments and Contingenciesprint Item 2. Management S Discussion and Analysis Of Financial Condition andprint Item 3. Quantitative and Qualitative Disclosures About Market Riskprint Item 4. Controls and Proceduresprint Part II. Other Informationprint Item 1. Legal Proceedingsprint Item 1A. Risk Factorsprint Item 2. Unregistered Sales Of Equity Securities and Use Of Proceedsprint Item 5. Other Informationprint Item 6. Exhibitsprint

Customer name	Ticker
Exelon Corporation	EXC
The Williams Companies, Inc.	WMB
WEC Energy Group, Inc.	WEC
Xcel Energy Inc.	XEL

Supplier name	Ticker
Exxon Mobil Corporation	XOM
Waste Management, Inc.	WM
WEC Energy Group, Inc.	WEC
The Southern Company	SO
Rockwell Automation, Inc.	ROK
Parker-Hannifin Corporation	PH
3M Company	MMM
American Electric Power Company, Inc.	AEP

PCG 10-Q Quarter ended June 30, 2013