Edgar Filing: PG&E Corp

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, 2014 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, 2014:
PG&E Corporation:				471,411,575
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, 2014

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	11
	NOTE 3:		Regulatory Assets, Liabilities, and Balancing Accounts	15
	NOTE 4:		Debt	16
	NOTE 5:		Equity	17
	NOTE 6:		Earnings Per Share	17
	NOTE 7:		Derivatives	18
	NOTE 8:		Fair Value Measurements	20
	NOTE 9:		Resolution of Remaining Chapter 11 Disputed Claims	26
	NOTE 10:		Commitments and Contingencies	27

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Overview			32
	Results of Operations			34
	Liquidity and Financial Resources			37
	Natural Gas Matters			41
	Regulatory Matters			44
	Environmental Matters			46
	Contractual Commitments			46
	Off-Balance Sheet Arrangements			46
	Risk Management Activities			47
	Critical Accounting Policies			47
	Cautionary Language Regarding Forward-Looking Statements			48

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			49
ITEM 4.	CONTROLS AND PROCEDURES			49

PART II.	OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS			50
ITEM 1A.	RISK FACTORS			52
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS			53
ITEM 5.	OTHER INFORMATION			53
ITEM 6.	EXHIBITS			54

SIGNATURES				55

GLOSSARY

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

2013 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, 2013
AFUDC	allowance for funds used during construction
ALJ	administrative law judge
CAISO	California Independent System Operator
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
EPA	Environmental Protection Agency
EPS	earnings per common share
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
ORA	Office of Ratepayer Advocates
PSEP	pipeline safety enhancement plan
SEC	U.S. Securities and Exchange Commission
SED	Safety and Enforcement Division of the CPUC, formerly known as the Consumer Protection and Safety Division or the CPSD
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)	2014			2013			2014			2013
Operating Revenues
Electric	$	3,233		$	3,059		$	6,234		$	5,858
Natural gas		719			717			1,609			1,590
Total operating revenues		3,952			3,776			7,843			7,448
Operating Expenses
Cost of electricity		1,349			1,189			2,559			2,172
Cost of natural gas		200			179			560			525
Operating and maintenance		1,328			1,256			2,627			2,594
Depreciation, amortization, and decommissioning		557			516			1,095			1,019
Total operating expenses		3,434			3,140			6,841			6,310
Operating Income		518			636			1,002			1,138
Interest income		2			2			5			4
Interest expense		(188	)		(177	)		(373	)		(353	)
Other income, net		43			24			62			52
Income Before Income Taxes		375			485			696			841
Income tax provision		104			153			195			267
Net Income		271			332			501			574
Preferred stock dividend requirement of subsidiary		4			4			7			7
Income Available for Common Shareholders	$	267		$	328		$	494		$	567
Weighted Average Common Shares Outstanding, Basic		467			442			463			438
Weighted Average Common Shares Outstanding, Diluted		469			443			465			439
Net Earnings Per Common Share, Basic	$	0.57		$	0.74		$	1.07		$	1.29
Net Earnings Per Common Share, Diluted	$	0.57		$	0.74		$	1.06		$	1.29
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 June 30,					Six Months Ended June 30,
(in millions)	2014			2013		2014			2013
Net Income	$	271		$	332	$	501		$	574
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $0, $3, $0 and $6, at respective dates)		-			4		-			8
Net change in investments
(net of taxes of $7, $11, $3, $15 at respective dates)		(11	)		16		(6	)		22
Total other comprehensive income (loss)		(11	)		20		(6	)		30
Comprehensive Income		260			352		495			604
Preferred stock dividend requirement of subsidiary		4			4		7			7
Comprehensive Income Attributable to Common Shareholders	$	256		$	348	$	488		$	597

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)	2014			2013
ASSETS
Current Assets
Cash and cash equivalents	$	132		$	296
Restricted cash		299			301
Accounts receivable:
Customers (net of allowance for doubtful accounts of $68 and $80
at respective dates)		1,009			1,091
Accrued unbilled revenue		870			766
Regulatory balancing accounts		1,745			1,124
Other		304			312
Regulatory assets		404			448
Inventories:
Gas stored underground and fuel oil		141			137
Materials and supplies		320			317
Income taxes receivable		613			574
Other		360			611
Total current assets		6,197			5,977
Property, Plant, and Equipment
Electric		43,990			42,881
Gas		15,040			14,379
Construction work in progress		1,981			1,834
Other		2			2
Total property, plant, and equipment		61,013			59,096
Accumulated depreciation		(18,530	)		(17,844	)
Net property, plant, and equipment		42,483			41,252
Other Noncurrent Assets
Regulatory assets		4,821			4,913
Nuclear decommissioning trusts		2,428			2,342
Income taxes receivable		88			85
Other		1,008			1,036
Total other noncurrent assets		8,345			8,376
TOTAL ASSETS	$	57,025		$	55,605

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)	2014		2013
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	1,452	$	1,174
Long-term debt, classified as current		-		889
Accounts payable:
Trade creditors		1,161		1,293
Disputed claims and customer refunds		86		154
Regulatory balancing accounts		1,069		1,008
Other		472		471
Interest payable		865		892
Other		1,544		1,612
Total current liabilities		6,649		7,493
Noncurrent Liabilities
Long-term debt		13,966		12,717
Regulatory liabilities		5,966		5,660
Pension and other postretirement benefits		1,578		1,601
Asset retirement obligations		3,561		3,539
Deferred income taxes		7,874		7,823
Other		2,151		2,178
Total noncurrent liabilities		35,096		33,518
Commitments and Contingencies (Note 10)
Equity
Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares,
470,950,685 and 456,670,424 shares outstanding at respective dates		10,176		9,550
Reinvested earnings		4,808		4,742
Accumulated other comprehensive income		44		50
Total shareholders' equity		15,028		14,342
Noncontrolling Interest - Preferred Stock of Subsidiary		252		252
Total equity		15,280		14,594
TOTAL LIABILITIES AND EQUITY	$	57,025	$	55,605

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)	2014			2013
Cash Flows from Operating Activities
Net income	$	501		$	574
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		1,095			1,019
Allowance for equity funds used during construction		(46	)		(52	)
Deferred income taxes and tax credits, net		51			346
Other		139			157
Effect of changes in operating assets and liabilities:
Accounts receivable		(30	)		(22	)
Inventories		(7	)		(31	)
Accounts payable		(101	)		28
Income taxes receivable/payable		(39	)		(143	)
Other current assets and liabilities		94			(367	)
Regulatory assets, liabilities, and balancing accounts, net		(311	)		(192	)
Other noncurrent assets and liabilities		(66	)		142
Net cash provided by operating activities		1,280			1,459
Cash Flows from Investing Activities
Capital expenditures		(2,320	)		(2,521	)
Decrease in restricted cash		2			25
Proceeds from sales and maturities of nuclear decommissioning
trust investments		877			795
Purchases of nuclear decommissioning trust investments		(873	)		(786	)
Other		21			16
Net cash used in investing activities		(2,293	)		(2,471	)
Cash Flows from Financing Activities
Borrowings (repayments) under revolving credit facilities		(260	)		140
Net issuances of commercial paper, net of discount of $1 at respective dates		237			321
Proceeds from issuance of short-term debt, net of issuance costs		300			-
Proceeds from issuance of long-term debt, net of premium, discount, and issuance
costs of $14 and $8 at respective dates		1,236			742
Repayments of long-term debt		(889	)		(461	)
Common stock issued		589			562
Common stock dividends paid		(408	)		(386	)
Other		44			(26	)
Net cash provided by financing activities		849			892
Net change in cash and cash equivalents		(164	)		(120	)
Cash and cash equivalents at January 1		296			401
Cash and cash equivalents at June 30	$	132		$	281
Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(318	)	$	(312	)
Income taxes, net		(1	)		(65	)

Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	215	$	202
Capital expenditures financed through accounts payable		224		253
Noncash common stock issuances		10		11
Terminated capital leases		68		-

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)	2014			2013			2014			2013
Operating Revenues
Electric	$	3,232		$	3,057		$	6,232		$	5,855
Natural gas		719			718			1,609			1,591
Total operating revenues		3,951			3,775			7,841			7,446
Operating Expenses
Cost of electricity		1,349			1,189			2,559			2,172
Cost of natural gas		200			179			560			525
Operating and maintenance		1,321			1,256			2,618			2,592
Depreciation, amortization, and decommissioning		556			516			1,094			1,019
Total operating expenses		3,426			3,140			6,831			6,308
Operating Income		525			635			1,010			1,138
Interest income		3			3			5			4
Interest expense		(185	)		(171	)		(364	)		(341	)
Other income, net		17			22			37			46
Income Before Income Taxes		360			489			688			847
Income tax provision		110			160			210			281
Net Income		250			329			478			566
Preferred stock dividend requirement		4			4			7			7
Income Available for Common Stock	$	246		$	325		$	471		$	559

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2014			2013			2014			2013
Net Income		$	250		$	329		$	478		$	566
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $0, $3, $0 and $6 at respective dates)			-			4			-			9
Total other comprehensive income			-			4			-			9
Comprehensive Income		$	250		$	333		$	478		$	575

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)	2014			2013
ASSETS
Current Assets
Cash and cash equivalents	$	70		$	65
Restricted cash		299			301
Accounts receivable:
Customers (net of allowance for doubtful accounts of $68 and $80
at respective dates)		1,009			1,091
Accrued unbilled revenue		870			766
Regulatory balancing accounts		1,745			1,124
Other		306			313
Regulatory assets		404			448
Inventories:
Gas stored underground and fuel oil		141			137
Materials and supplies		320			317
Income taxes receivable		598			563
Other		208			523
Total current assets		5,970			5,648
Property, Plant, and Equipment
Electric		43,990			42,881
Gas		15,040			14,379
Construction work in progress		1,981			1,834
Total property, plant, and equipment		61,011			59,094
Accumulated depreciation		(18,529	)		(17,843	)
Net property, plant, and equipment		42,482			41,251
Other Noncurrent Assets
Regulatory assets		4,821			4,913
Nuclear decommissioning trusts		2,428			2,342
Income taxes receivable		83			81
Other		824			814
Total other noncurrent assets		8,156			8,150
TOTAL ASSETS	$	56,608		$	55,049

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)	2014		2013
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	1,340	$	914
Long-term debt, classified as current		-		539
Accounts payable:
Trade creditors		1,161		1,293
Disputed claims and customer refunds		86		154
Regulatory balancing accounts		1,069		1,008
Other		462		432
Interest payable		862		887
Other		1,285		1,382
Total current liabilities		6,265		6,609
Noncurrent Liabilities
Long-term debt		13,616		12,717
Regulatory liabilities		5,966		5,660
Pension and other postretirement benefits		1,505		1,530
Asset retirement obligations		3,561		3,539
Deferred income taxes		8,060		8,042
Other		2,106		2,111
Total noncurrent liabilities		34,814		33,599
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		6,396		5,821
Reinvested earnings		7,540		7,427
Accumulated other comprehensive income		13		13
Total shareholders' equity		15,529		14,841
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	56,608	$	55,049

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Six Months Ended June 30,
(in millions)	2014			2013
Cash Flows from Operating Activities
Net income	$	478		$	566
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		1,094			1,019
Allowance for equity funds used during construction		(46	)		(52	)
Deferred income taxes and tax credits, net		18			337
Other		108			126
Effect of changes in operating assets and liabilities:
Accounts receivable		(31	)		(24	)
Inventories		(7	)		(31	)
Accounts payable		(72	)		68
Income taxes receivable/payable		(35	)		(162	)
Other current assets and liabilities		141			(317	)
Regulatory assets, liabilities, and balancing accounts, net		(311	)		(192	)
Other noncurrent assets and liabilities		(76	)		126
Net cash provided by operating activities		1,261			1,464
Cash Flows from Investing Activities
Capital expenditures		(2,320	)		(2,521	)
Decrease in restricted cash		2			25
Proceeds from sales and maturities of nuclear decommissioning
trust investments		877			795
Purchases of nuclear decommissioning trust investments		(873	)		(786	)
Other		17			8
Net cash used in investing activities		(2,297	)		(2,479	)
Cash Flows from Financing Activities
Net issuances of commercial paper, net of discount of $1 at respective dates		125			321
Proceeds from issuance of short-term debt, net of issuance costs		300			-
Proceeds from issuance of long-term debt, net of premium, discount, and issuance
costs of $11 and $8 at respective dates		889			742
Repayments of long-term debt		(539	)		(461	)
Preferred stock dividends paid		(7	)		(7	)
Common stock dividends paid		(358	)		(358	)
Equity contribution		580			665
Other		51			(20	)
Net cash provided by financing activities		1,041			882
Net change in cash and cash equivalents		5			(133	)
Cash and cash equivalents at January 1		65			194
Cash and cash equivalents at June 30	$	70		$	61
Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(307	)	$	(300	)
Income taxes, net		(1	)		(86	)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	224		$	253
Terminated capital leases		68			-
See accompanying Notes to the Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

PG&E Corporation is a holding company whose primary operating subsidiary is 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.

This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its subsidiaries. All intercompany balances and transactions have been eliminated. The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility unless described otherwise. PG&E Corporation and the Utility operate in one segment.

The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of PG&E Corporation and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2013 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in the 2013 Annual Report. This quarterly report should be read in conjunction with the 2013 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 2013 Annual Report.

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 a primary beneficiary and is required to consolidate 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, 2014, 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 obligation 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, 2014, 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 four separate privately held funds that are considered VIEs. Under these agreements, PG&E Corporation has made cumulative lease payments and investment contributions of $363 million to these companies since 2010 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, 2014 and December 31, 2013, the carrying amount of PG&E Corporation’s investment in these VIEs was $87 million and $98 million, respectively. PG&E Corporation does not have decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs, such as the design of the companies, vendor selection, construction, and the ongoing operations of the companies. Since PG&E Corporation was not the primary beneficiary of any of these VIEs at June 30, 2014, it did not consolidate any of them. On July 2, 2014, PG&E Corporation disposed of its interest in the tax equity agreements. PG&E Corporation has no remaining commitment to fund these agreements.

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, 2014 and 2013 were as follows:

	Pension Benefits						Other Benefits
	Three Months Ended June 30,
(in millions)	2014			2013			2014			2013
Service cost for benefits earned	$	96		$	115		$	11		$	13
Interest cost		173			156			19			18
Expected return on plan assets		(201	)		(163	)		(26	)		(20	)
Amortization of prior service cost		5			5			5			5
Amortization of net actuarial loss		1			28			1			2
Net periodic benefit cost		74			141			10			18
Less: transfer to regulatory account (1)		9			(56	)		-			-
Total	$	83		$	85		$	10		$	18

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

	Pension Benefits						Other Benefits
	Six Months Ended June 30,
(in millions)	2014			2013			2014			2013
Service cost for benefits earned	$	195		$	230		$	22		$	26
Interest cost		346			312			38			37
Expected return on plan assets		(403	)		(325	)		(52	)		(40	)
Amortization of prior service cost		10			10			11			11
Amortization of net actuarial loss		1			55			1			3
Net periodic benefit cost		149			282			20			37
Less: transfer to regulatory account (1)		19			(113	)		-			-
Total	$	168		$	169		$	20		$	37

(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.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) are summarized below:

	Pension			Other			Other
	Benefits			Benefits			Investments			Total
(in millions, net of income tax)	Three Months Ended June 30, 2014
Beginning balance	$	(7	)	$	15		$	47		$	55
Other comprehensive income before reclassifications:
Gain on investments (net of taxes of $0, $0, and $3,
respectively)		-			-			5			5
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of
$2, $2, and $0, respectively) (1)		3			3			-			6
Amortization of net actuarial loss (net of taxes of
$0, $0, and $0, respectively) (1)		1			1			-			2
Transfer to regulatory account (net of taxes of
$2, $2, and $0, respectively) (1)		(4	)		(4	)		-			(8	)
Realized gain on investments (net of taxes of
$0, $0, and $10, respectively)		-			-			(16	)		(16	)
Net current period other comprehensive loss		-			-			(11	)		(11	)
Ending balance	$	(7	)	$	15		$	36		$	44

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

	Pension			Other			Other
	Benefits			Benefits			Investments		Total
(in millions, net of income tax)	Three Months Ended June 30, 2013
Beginning balance	$	(28	)	$	(73	)	$	10	$	(91	)
Other comprehensive income before reclassifications:
Gain on investments (net of taxes of $0, $0, and $11,
respectively)		-			-			16		16
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of
$2, $2, and $0, respectively)		3			3			-		6
Amortization of net actuarial loss (net of taxes of
$12, $1, and $0, respectively)		16			1			-		17
Transfer to regulatory account (net of taxes of
$13, $0, and $0, respectively)		(19	)		-			-		(19	)
Net current period other comprehensive income		-			4			16		20
Ending balance	$	(28	)	$	(69	)	$	26	$	(71	)

	Pension			Other			Other
	Benefits			Benefits			Investments			Total
(in millions, net of income tax)	Six Months Ended June 30, 2014
Beginning balance	$	(7	)	$	15		$	42		$	50
Other comprehensive income before reclassifications:
Gain on investments (net of taxes of $0, $0, and $7,
respectively)		-			-			10			10
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of
$4, $4, and $0, respectively) (1)		6			7			-			13
Amortization of net actuarial loss (net of taxes of
$0, $0, and $0, respectively) (1)		1			1			-			2
Transfer to regulatory account (net of taxes of
$4, $4, and $0, respectively) (1)		(7	)		(8	)		-			(15	)
Realized gain on investments (net of taxes of
$0, $0, and $10, respectively)		-			-			(16	)		(16	)
Net current period other comprehensive loss		-			-			(6	)		(6	)
Ending balance	$	(7	)	$	15		$	36		$	44

	Pension			Other			Other
	Benefits			Benefits			Investments		Total
(in millions, net of income tax)	Six Months Ended June 30, 2013
Beginning balance	$	(28	)	$	(77	)	$	4	$	(101	)
Other comprehensive income before reclassifications:
Gain on investments (net of taxes of $0, $0, and $15,
respectively)		-			-			22		22
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of
$4, $5, and $0, respectively)		6			6			-		12
Amortization of net actuarial loss (net of taxes of
$23, $1, and $0, respectively)		32			2			-		34
Transfer to regulatory account (net of taxes of
$26, $0, and $0, respectively)		(38	)		-			-		(38	)
Net current period other comprehensive income		-			8			22		30
Ending balance	$	(28	)	$	(69	)	$	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.

Accounting Standards Issued But Not Yet Adopted

Revenue Recognition Standard

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers, which amends existing revenue recognition guidance. The accounting standards update will be effective on January 1, 2017. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their consolidated financial statements and related disclosures.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Long-term regulatory assets are composed of the following:

	Balance at
	June 30,		December 31,
(in millions)	2014		2013
Pension benefits	$	1,415	$	1,444
Deferred income taxes		1,932		1,835
Utility retained generation		479		503
Environmental compliance costs		599		628
Price risk management		83		106
Electromechanical meters		103		135
Unamortized loss, net of gain, on reacquired debt		124		135
Other		86		127
Total long-term regulatory assets	$	4,821	$	4,913

Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

	Balance at
	June 30,			December 31,
(in millions)	2014			2013
Cost of removal obligations		$	3,978		$	3,844
Recoveries in excess of asset retirement obligations			754			748
Public purpose programs			677			587
Other			557			481
Total long-term regulatory liabilities		$	5,966		$	5,660

Regulatory Balancing Accounts

The Utility’s recovery of revenue requirements and costs is generally decoupled from the volume of sales. The Utility records (1) differences between the Utility’s authorized revenue requirement and actual customer billings, and (2) differences between incurred costs and customer billings. To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable. Regulatory balancing accounts that the Utility does not expect to collect or refund over the next 12 months are included in other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Condensed Consolidated Balance Sheets.

The Utility sells and delivers electricity and natural gas. The Utility also administers public purpose programs, primarily related to customer energy efficiency programs. The balancing accounts associated with these items 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 receivable and payable are composed of the following:

	Receivable
	Balance at
	June 30,			December 31,
(in millions)	2014			2013
Electric distribution		$	455		$	102
Utility generation			257			57
Gas distribution			154			70
Energy procurement			486			410
Public purpose programs			39			56
Other			354			429
Total regulatory balancing accounts receivable		$	1,745		$	1,124

	Payable
	Balance at
	June 30,			December 31,
(in millions)	2014			2013
Energy procurement		$	298		$	298
Public purpose programs			199			171
Other			572			539
Total regulatory balancing accounts payable		$	1,069		$	1,008

NOTE 4: DEBT

Senior Notes

In February 2014, the Utility issued $450 million principal amount of 3.75% Senior Notes due February 15, 2024 and $450 million principal amount of 4.75% Senior Notes due February 15, 2044. The proceeds were used to repay the 4.80% Senior Notes, in the principal outstanding amount of $539 million, to fund capital expenditures, and for general corporate purposes. In addition, in May 2014, the Utility issued $300 million principal amount of Floating Rate Senior Notes due May 11, 2015. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility's outstanding commercial paper.

Revolving Credit Facilities and Commercial Paper Program

In April 2014, PG&E Corporation and the Utility each extended the termination dates of their existing revolving credit facilities by one year from April 1, 2018 to April 1, 2019. PG&E Corporation and the Utility can issue commercial paper up to the maximum amounts of $300 million and $1.75 billion, respectively. PG&E Corporation and the Utility treat the amount of outstanding commercial paper as a reduction to the amount available under their respective revolving credit facilities.

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings at June 30, 2014:

						Letters of
	Termination	Facility				Credit						Commercial			Facility
(in millions)	Date	Limit				Outstanding			Borrowings			Paper			Availability
PG&E Corporation	April 2019		$	300	(1)		$	-		$	-		$	112		$	188
Utility	April 2019			3,000	(2)			86		$	-			1,041			1,873
Total revolving
credit facilities			$	3,300			$	86		$	-		$	1,153		$	2,061

(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.

Pollution Control Bonds

At June 30, 2014, 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 0.01% to 0.04%. At June 30, 2014, 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 0.04%.

NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the six months ended June 30, 2014 were as follows:


	PG&E Corporation			Utility
	Total			Total
(in millions)	Equity			Shareholders' Equity
Balance at December 31, 2013	$	14,594		$	14,841
Comprehensive income		495			478
Equity contributions		-			580
Common stock issued		599			-
Share-based compensation		27			(5	)
Common stock dividends declared		(428	)		(358	)
Preferred stock dividend requirement		-			(7	)
Preferred stock dividend requirement of subsidiary		(7	)		-
Balance at June 30, 2014	$	15,280		$	15,529

In February 2014, 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 $500 million.

PG&E Corporation issued common stock in the following transactions:

·	During the six months ended June 30, 2014, 4 million shares were issued for cash proceeds of $160 million under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans; and

·	During the three and six months ended June 30, 2014, PG&E Corporation sold 5 and 10 million shares under the February 2014 equity distribution agreement for cash proceeds of $206 and $429 million, net of commissions paid of $2 and $4 million, respectively.

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)	2014		2013		2014		2013
Income available for common shareholders	$	267	$	328	$	494	$	567
Weighted average common shares outstanding, basic		467		442		463		438
Add incremental shares from assumed conversions:
Employee share-based compensation		2		1		2		1
Weighted average common share outstanding, diluted		469		443		465		439
Total earnings per common share, diluted	$	0.57	$	0.74	$	1.06	$	1.29

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

NOTE 7: DERIVATIVES

The Utility uses both derivative and non-derivative contracts in managing its customers’ exposure to commodity-related price risk, including forward contracts, swap agreements, 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. The Utility expects to fully recover in rates all costs related to derivatives 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. 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 offsets cash collateral paid or cash collateral received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement where the right of offset and the intention to offset exist.

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 at fair value, but are accounted for under the accrual method of accounting. Therefore, expenses are recognized as incurred.

Volume of Derivative Activity

At June 30, 2014, the volumes of the Utility’s outstanding derivatives were as follows:

Contract Volume (1)

1 Year or

3 Years or

Greater but

Less Than 1

Less Than 3

Less Than 5

5 Years or

Underlying Product

Instruments

Year

Years

Greater (2)

Natural Gas (3)

Forwards and

(MMBtus (4))

Swaps

253,455,503

68,107,500

5,370,000

Options

118,345,529

56,101,311

1,800,000

Electricity

Forwards and

(Megawatt-hours)

Swaps

1,750,584

1,956,498

1,735,012

1,200,183

Congestion

Revenue Rights

60,291,148

86,200,035

50,662,422

25,365,949

(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 2019 and 2023.

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

(4) Million British Thermal Units.

At December 31, 2013, the volumes of the Utility’s outstanding derivatives were as follows:

Contract Volume (1)

1 Year or

3 Years or

Greater but

Less Than 1

Less Than 3

Less Than 5

5 Years or

Underlying Product

Instruments

Year

Years

Greater (2)

Natural Gas (3)

Forwards and

(MMBtus (4))

Swaps

243,213,288

79,735,000

8,892,500

Options

169,123,208

87,689,708

3,450,000

Electricity

Forwards and

(Megawatt-hours)

Swaps

2,537,023

2,009,505

2,008,046

1,534,695

Congestion

Revenue Rights

73,510,440

83,747,782

63,718,517

29,945,852

(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 2019 and 2022.

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

(4) Million British Thermal Units.

Presentation of Derivative Instruments in the Financial Statements

Derivatives that are subject to a master netting agreement where the right and the intent to offset assets and liabilities exists, are presented on a net basis in the Condensed Consolidated Balance Sheets. The net balances include outstanding cash collateral associated with derivative positions.

At June 30, 2014, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
	Gross Derivative											Total Derivative
(in millions)	Balance				Netting				Cash Collateral			Balance
Current assets – other		$	61			$	(6	)		$	8		$	63
Other noncurrent assets – other			88				(2	)			-			86
Current liabilities – other			(70	)			6				18			(46	)
Noncurrent liabilities – other			(85	)			2				-			(83	)
Net commodity risk		$	(6	)		$	-			$	26		$	20

At December 31, 2013, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
	Gross Derivative											Total Derivative
(in millions)	Balance				Netting				Cash Collateral			Balance
Current assets – other		$	42			$	(10	)		$	16		$	48
Other noncurrent assets – other			99				(4	)			-			95
Current liabilities – other			(122	)			10				69			(43	)
Noncurrent liabilities – other			(110	)			4				2			(104	)
Net commodity risk		$	(91	)		$	-			$	87		$	(4	)

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)	2014				2013				2014				2013
Unrealized gain (loss) - regulatory assets and liabilities (1)		$	27			$	(23	)		$	85			$	75
Realized loss - cost of electricity (2)			(8	)			(31	)			(26	)			(79	)
Realized loss - cost of natural gas (2)			(3	)			(4	)			(3	)			(12	)
Net commodity risk		$	16			$	(58	)		$	56			$	(16	)

(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, 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.

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, 2014, 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)	2014			2013
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(36	)	$	(79	)
Related derivatives in an asset position		2			4
Collateral posting in the normal course of business related to
these derivatives		21			65
Net position of derivative contracts/additional collateral
posting requirements (1)	$	(13	)	$	(10	)

(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. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure 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, 2014
(in millions)	Level 1		Level 2		Level 3		Netting (1)			Total
Assets:
Money market investments	$	63	$	-	$	-	$	-		$	63
Nuclear decommissioning trusts
Money market investments		19		-		-		-			19
U.S. equity securities		1,128		12		-		-			1,140
Non-U.S. equity securities		457		2		-		-			459
U.S. government and agency securities		732		173		-		-			905
Municipal securities		-		55		-		-			55
Other fixed-income securities		-		172		-		-			172
Total nuclear decommissioning trusts (2)		2,336		414		-		-			2,750
Price risk management instruments
(Note 7)
Electricity		5		31		105		1			142
Gas		-		8		-		(1	)		7
Total price risk management instruments		5		39		105		-			149
Rabbi trusts
Fixed-income securities		-		41		-		-			41
Life insurance contracts		-		72		-		-			72
Total rabbi trusts		-		113		-		-			113
Long-term disability trust
Money market investments		5		-		-		-			5
U.S. equity securities		-		12		-		-			12
Non-U.S. equity securities		-		11		-		-			11
Fixed-income securities		-		114		-		-			114
Total long-term disability trust		5		137		-		-			142
Other investments		71		-		-		-			71
Total assets	$	2,480	$	703	$	105	$	-		$	3,288
Liabilities:
Price risk management instruments
(Note 7)
Electricity	$	6	$	29	$	116	$	(25	)	$	126
Gas		-		4		-		(1	)		3
Total liabilities	$	6	$	33	$	116	$	(26	)	$	129

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

(2) Represents amount before deducting $322 million, primarily related to deferred taxes on appreciation of investment value.

	Fair Value Measurements
	At December 31, 2013
(in millions)	Level 1		Level 2		Level 3		Netting (1)			Total
Assets:
Money market investments	$	226	$	-	$	-	$	-		$	226
Nuclear decommissioning trusts
Money market investments		38		-		-		-			38
U.S. equity securities		1,046		11		-		-			1,057
Non-U.S. equity securities		457		-		-		-			457
U.S. government and agency securities		760		156		-		-			916
Municipal securities		-		25		-		-			25
Other fixed-income securities		-		162		-		-			162
Total nuclear decommissioning trusts (2)		2,301		354		-		-			2,655
Price risk management instruments
(Note 7)
Electricity		2		27		107		3			139
Gas		-		5		-		(1	)		4
Total price risk management instruments		2		32		107		2			143
Rabbi trusts
Fixed-income securities		-		39		-		-			39
Life insurance contracts		-		70		-		-			70
Total rabbi trusts		-		109		-		-			109
Long-term disability trust
Money market investments		9		-		-		-			9
U.S. equity securities		-		14		-		-			14
Non-U.S. equity securities		-		12		-		-			12
Fixed-income securities		-		122		-		-			122
Total long-term disability trust		9		148		-		-			157
Other investments		84		-		-		-			84
Total assets	$	2,622	$	643	$	107	$	2		$	3,374
Liabilities:
Price risk management instruments
(Note 7)
Electricity	$	19	$	72	$	137	$	(84	)	$	144
Gas		1		3		-		(1	)		3
Total liabilities	$	20	$	75	$	137	$	(85	)	$	147

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

(2) Represents amount before deducting $313 million, 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, primarily consisting of equity securities, that are valued using a net asset value per share can be redeemed quarterly with notice not to exceed 90 days. Equity investments valued at net asset value per share utilize investment strategies aimed at matching the performance of indexed funds. Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the six months ended June 30, 2014 and 2013.

Trust Assets

Nuclear decommissioning trust assets and other trust assets 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 that are valued based on quoted prices in active markets and are classified as Level 1. Equity securities also include commingled funds that are composed of equity securities traded publicly on exchanges across multiple industry sectors in the U.S. and other regions of the world. Investments in these funds are classified as Level 2 because price quotes 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 using 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. Exchange-traded options are valued using observable market data and market-corroborated data and 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. Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. CRRs are classified as Level 3 and are valued based on CRR auction prices, including historical prices. 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.

Level 3 Measurements and Sensitivity Analysis

The Utility’s market and credit risk management function, which reports to the Chief Risk Officer of the Utility, is responsible for determining the fair value of the Utility’s price risk management derivatives. The Utility’s finance and risk management functions 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.

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. 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, 2014
Fair Value Measurement	Assets			Liabilities			Valuation Technique	Unobservable Input	Range (1)
Congestion revenue rights		$	105		$	35	Market approach	CRR auction prices		$	(17.62) - 12.04
Power purchase agreements		$	-		$	81	Discounted cash flow	Forward prices		$	24.77 - 59.09

(1) Represents price per megawatt-hour

	Fair Value at
(in millions)	December 31, 2013
Fair Value Measurement	Assets			Liabilities			Valuation Technique	Unobservable Input	Range (1)
Congestion revenue rights		$	107		$	32	Market approach	CRR auction prices		$	(6.47) - 12.04
Power purchase agreements		$	-		$	105	Discounted cash flow	Forward prices		$	23.43 - 51.75

(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, 2014 and 2013:

	Price Risk Management Instruments
(in millions)	2014			2013
Liability balance as of April 1	$	(22	)	$	(75	)
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		11			(1	)
Liability balance as of June 30	$	(11	)	$	(76	)

(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)	2014			2013
Liability balance as of January 1	$	(30	)	$	(79	)
Realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)		19			3
Liability balance as of June 30	$	(11	)	$	(76	)

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, 2014 and December 31, 2013, 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, 2014 and December 31, 2013.

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

	At June 30, 2014						At December 31, 2013
(in millions)	Carrying Amount			Level 2 Fair Value			Carrying Amount			Level 2 Fair Value
PG&E Corporation		$	349		$	354		$	350		$	354
Utility			12,694			14,402			12,334			13,444

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, 2014
Nuclear decommissioning trusts
Money market investments	$	19	$	-	$	-		$	19
Equity securities
U.S.		266		874		-			1,140
Non-U.S.		253		207		(1	)		459
Debt securities
U.S. government and agency securities		847		60		(2	)		905
Municipal securities		52		3		-			55
Other fixed-income securities		171		2		(1	)		172
Total nuclear decommissioning trusts (1)		1,608		1,146		(4	)		2,750
Other investments		9		62		-			71
Total	$	1,617	$	1,208	$	(4	)	$	2,821
As of December 31, 2013
Nuclear decommissioning trusts
Money market investments	$	38	$	-	$	-		$	38
Equity securities
U.S.		246		811		-			1,057
Non-U.S.		215		242		-			457
Debt securities
U.S. government and agency securities		870		51		(5	)		916
Municipal securities		24		2		(1	)		25
Other fixed-income securities		163		1		(2	)		162
Total nuclear decommissioning trusts (1)		1,556		1,107		(8	)		2,655
Other investments		13		71		-			84
Total	$	1,569	$	1,178	$	(8	)	$	2,739

(1) Represents amounts before deducting $322 million and $313 million at June 30, 2014 and December 31, 2013, 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, 2014
Less than 1 year	$	16
1–5 years		502
5–10 years		248
More than 10 years		366
Total maturities of debt securities	$	1,132

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

	Three Months Ended								Six Months Ended
	June 30,								June 30,
	2014				2013				2014			2013
(in millions)
Proceeds from sales and maturities of nuclear decommissioning
trust investments		$	347			$	432		$	877			$	795
Gross realized gains on securities held as available-for-sale			28				25			84				37
Gross realized losses on securities held as available-for-sale			(2	)			(5	)		(3	)			(6	)

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.

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, 2014 and December 31, 2013, the remaining disputed claims liability (classified on the Condensed Consolidated Balance Sheets within accounts payable – disputed claims and customer refunds) including accrued interest (classified on the Condensed Consolidated Balance Sheets within interest payable) consisted of $766 million and $864 million, respectively.

At June 30, 2014 and December 31, 2013 the Utility held $291 million 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.

In July 2014, a settlement agreement between the Utility and an electric supplier became effective, resolving a portion of the Utility’s disputed claims. The settlement will result in refunds to customers of $312 million and will be returned through rates in future periods. The Utility is uncertain when and how the remaining disputed claims will be resolved.

NOTE 10: COMMITMENTS AND CONTINGENCIES

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to natural gas matters and environmental remediation. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities.

Natural Gas Matters

Pending CPUC Investigations

As described in the 2013 Annual Report, there are three CPUC investigative enforcement proceedings pending against the Utility related to its natural gas operations and the San Bruno accident on September 9, 2010. The ALJs who are presiding over the investigations are expected to issue one or more decisions to address the violations that they have determined the Utility committed and to impose penalties. It is uncertain when these decisions will be issued. The SED has 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 payable to the State General Fund and $1.95 billion of non-recoverable costs. Other parties, including the City of San Bruno, TURN, the CPUC’s ORA, and the City and County of San Francisco, have recommended total penalties of at least $2.25 billion, including fines payable to the State General Fund of differing amounts.

Based on the CPUC’s rules, after the ALJs issue their decisions, the Utility and other parties would have 30 days to file an appeal. Parties would have 15 days to respond to appeals. In addition, within 30 days after the decisions are issued, a CPUC commissioner could request that the CPUC review the decisions. If appeals are filed or a CPUC commissioner requests a review, it is uncertain when the final outcome of these investigations would be determined.

At June 30, 2014, the Condensed Consolidated Balance Sheets included an accrual of $200 million in other current liabilities for the minimum amount of fines deemed probable that the Utility will be required to 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, including: how the total number and duration of violations will be determined; how the various penalty recommendations will be considered; how the financial and tax 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 will respond to public pressure. Future changes in these estimates or the assumptions on which they are based could have a material impact on future 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 may disallow future costs, or costs that were previously authorized for recovery, including PSEP costs. Disallowed capital investments would be charged to net income in the period in which the CPUC orders such a disallowance. See “Pipeline Safety Enhancement Plan” below. Future disallowed expense and capital costs would be charged to net income in the period incurred.

Criminal Indictment

On July 30, 2014, the U.S. Attorney’s Office for the Northern District of California filed a 28-count superseding criminal indictment against the Utility in federal district court replacing the indictment that had been filed on April 1, 2014. The superseding indictment alleges 27 felony counts (increased from 12 counts alleged in the original indictment) charging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record keeping, pipeline integrity management, and identification of pipeline threats. The superseding indictment also includes one felony count charging that the Utility obstructed the NTSB’s investigation of the San Bruno accident in violation of a federal statute prohibiting obstruction of a federal agency’s proceedings. The maximum statutory fine for each felony count is $500,000, for total fines of $14 million. The superseding indictment also alleges a maximum alternative fine under the Alternative Fines Act which states, in part: “If any person derives pecuniary gain from the offense, or if the offense results in pecuniary loss to a person other than the defendant, the defendant may be fined not more than the greater of twice the gross gain or twice the gross loss, unless imposition of a fine under this subsection would unduly complicate or prolong the sentencing process.” Based on the superseding indictment’s allegations that the Utility derived gross gains of approximately $281 million and that victims suffered losses of approximately $565 million, the maximum alternate fine would be approximately $1.13 billion. The Utility continues to believe that criminal charges are not merited and that it did not knowingly and willfully violate minimum safety standards under the Natural Gas Pipeline Safety Act or obstruct the NTSB’s investigation, as alleged in the superseding indictment. PG&E Corporation and the Utility have not accrued any charges for criminal fines in their condensed consolidated financial statements as such amounts are not probable. The Utility will appear in court at a status conference that is scheduled to be held on August 18, 2014.

Other Enforcement Matters

PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows also may be affected by the outcome of the following matters. They are unable to reasonably estimate the amount or range of future charges that could be incurred in connection with these matters given the wide discretion the CPUC and the SED have in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines.

Gas Safety Citation Program. The SED has authority to issue citations and impose fines on California gas corporations, such as the Utility, for violations of certain state and federal regulations that relate to the safety of natural gas facilities and operating practices. The California gas corporations are required to inform the SED of any self-identified or self-corrected violations of these regulations. The SED has discretion to impose fines or take other enforcement action to address a violation, based on the totality of the circumstances. The SED can consider various factors in determining whether to impose fines and the amount of fines, including the severity of the safety risk associated with each violation, the number and duration of the violations, whether the violation was self-reported, and whether corrective actions were taken. The SED has imposed fines ranging from $50,000 to $16.8 million in connection with several of the Utility’s self-reports.

At June 30, 2014, the Utility has submitted about 65 self-reports (plus some follow-up reports) that the SED has not yet addressed. In addition, in July 2014, the Utility reported that it discovered that, contrary to its procedures, employees who perform work to fuse plastic pipes together had completed only part of their requisite re-qualification. The Utility believes that this issue does not constitute a safety concern as every plastic pipe installed in the field is tested on site and under pressure before being put into service. The Utility suspended non-emergency plastic fusion work until employees who perform this work undergo proper re-qualifications.

The Utility believes it is probable that the SED will impose fines or take other enforcement action with respect to some of the Utility’s self-reports in the future. In addition, the SED has been conducting numerous compliance audits of the Utility’s operating practices and has informed the Utility that the SED’s audit findings include several allegations of noncompliant practices. It is reasonably possible that the SED will impose fines with respect to its audit findings. The Utility has been taking corrective actions in response to these matters.

Natural Gas Transmission Pipeline Rights-of-Way. In 2012, the Utility notified the CPUC and the SED that the Utility planned to complete a system-wide survey of its transmission pipelines in an effort to identify encroachments (such as building structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way. The Utility also submitted a proposed compliance plan that set forth the scope and timing of remedial work to remove identified encroachments over a multi-year period and to pay penalties if the proposed milestones were not met. In March 2014, the Utility informed the SED that the survey has been completed and that remediation work, including removal of the encroachments, is expected to continue for several years. The SED has not addressed the Utility’s proposed compliance plan, and it is reasonably possible that the SED will impose fines on the Utility or take other enforcement action in the future based on the Utility’s failure to continuously survey its system and remove encroachments.

Other Matters. On March 3, 2014, a vacant house in Carmel, California was severely damaged due to a natural gas explosion while the Utility’s employees were performing work to upgrade the main natural gas distribution pipeline in the area. There were no injuries or fatalities. A third-party engineering firm hired by the Utility determined that the root cause of the incident was “inadequate verification of system status and configuration when performing work on a live line.” The Utility is implementing the recommendations made by the consultant. The CPUC, the U.S. Attorney’s Office, and local Carmel officials are continuing to investigate the incident. It is reasonably possible that fines could be imposed on the Utility, or that other enforcement actions could be taken, in connection with this matter.

Pipeline Safety Enhancement Plan

On July 25, 2014, the Utility, together with the CPUC’s ORA and TURN, requested that the CPUC approve a settlement agreement to resolve the Utility’s PSEP Update application (submitted in October 2013). The settlement agreement proposes that the CPUC approve total PSEP-related revenue requirements (2012-2014) that reflect a $23 million reduction to expense funding, as compared to the Utility’s request. For the three months ended June 30, 2014, the Utility recorded a charge against operating revenue to reflect the cumulative impact of this reduction. The settlement agreement does not propose any reductions to total PSEP capital costs of $766 million requested by the Utility in the PSEP Update application. The Utility previously has recorded cumulative charges of $549 million for PSEP-related capital costs that are expected to exceed the amount to be recovered. At June 30, 2014, approximately $400 million of PSEP-related capital costs is recorded in property, plant, and equipment on the Condensed Consolidated Balance Sheets. The Utility would be required to record charges in future periods to the extent PSEP-related capital costs are higher than currently expected and to the extent the CPUC authorizes total capital costs that are lower than $766 million. The parties have requested the CPUC’s approval of the settlement agreement by December 1, 2014. The Utility’s ability to recover PSEP-related costs also could be affected by the final decisions to be issued in the CPUC’s pending investigations discussed above.

Class Action Complaint

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

Legal and Regulatory Contingencies

Accruals for other legal and regulatory contingencies (excluding amounts related to natural gas matters above) totaled $35 million at June 30, 2014 and $43 million at December 31, 2013. These amounts are included in other current liabilities in the Condensed Consolidated Balance Sheets. The resolution of these matters is not expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows.

Environmental Remediation Contingencies

The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is composed of the following:

	Balance at
(in millions)	June 30, 2014		December 31, 2013
Topock natural gas compressor station (1)	$	269	$	264
Hinkley natural gas compressor station (1)		170		190
Former manufactured gas plant sites owned by the Utility or third parties		183		184
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites		157		160
Fossil fuel-fired generation facilities and sites		99		102
Total environmental remediation liability	$	878	$	900

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

At June 30, 2014 the Utility expected to recover $582 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 Station 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 stations. One of these stations is located near Hinkley, California and is referred to below as the “Hinkley site.” Another station is located near Needles, California and is referred to below as the “Topock site.” 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. In 2013, the Regional Board certified a final environmental report evaluating the Utility’s proposed remedial methods to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The Regional Board is expected to issue final project permits for in-situ remediation in late 2014 and the final cleanup and abatement order in late 2014 or early 2015. As final permits and orders are issued, the Utility expects to obtain additional clarity on the total costs associated with the final remedy and related activities. The Utility has implemented interim remediation measures to reduce the mass of the chromium plume, monitor and control movement of the plume, and provide replacement water to affected residents under its whole house water replacement program (as described in the 2013 Annual Report). The State of California has established a final drinking water standard for hexavalent chromium that became effective on July 1, 2014. The Utility is evaluating the new standard but does not believe any related changes to its interim measures will have a material impact on its environmental remediation liability.

The Utility’s environmental remediation liability at June 30, 2014 reflects the Utility’s best estimate of probable future costs associated with its final remediation plan and interim remediation measures. 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, and the nature and extent of the chromium contamination. Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition, results of operations, and cash flows.

Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California Department of Toxic Substances Control and the U.S. Department of the Interior. The Utility expects to submit its 90% remedial design plan in late 2014 and its final remedial design plan in early 2015, which would seek approval to begin construction of an in-situ groundwater treatment system that will convert hexavalent chromium into a non-toxic and non-soluble form of chromium. The Utility has implemented interim remediation measures, including a system of extraction wells and a treatment plant designed to prevent movement of the chromium plume toward the Colorado River. The Utility’s environmental remediation liability at June 30, 2014 reflects its best estimate of probable future costs associated with its final remediation plan. 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. Future changes in cost estimates and the assumptions on which they are based may have a material impact on 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. 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 results of operations during the period in which they are recorded.

Tax Matters

In June 2014, the Joint Committee on Taxation of the U.S. Congress approved the IRS closing agreement for the 2008 and 2010 audit years. The IRS is currently reviewing several matters pertaining to the 2011 and 2012 tax returns. The most significant of these matters relates to the repairs accounting method changes.

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 during 2014. 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 related to the 2011 and 2012 tax returns. As of June 30, 2014, it is reasonably possible that unrecognized tax benefits will decrease by approximately $370 million within the next 12 months, and most of this decrease would not impact net income.

There were no other significant developments to tax matters during the six months ended June 30, 2014. (Refer to Note 8 of the Notes to the Consolidated Financial Statements in the 2013 Annual Report.)

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 $2.6 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 $13.6 billion. The Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon. The balance of the $13.6 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. In addition, Congress could impose additional revenue-raising measures to pay claims. 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 14 of the Notes to the Consolidated Financial Statements of the 2013 Annual Report for additional information.)

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, 2013 in Note 14 of the Notes to the Consolidated Financial Statements in the 2013 Annual Report. During the six months ended June 30, 2014, several purchase power agreements the Utility entered into with renewable energy facilities were approved by the CPUC and completed major milestones with respect to construction, resulting in a total commitment amount of $1.7 billion over the next 25 years.

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

RESULTS OF OPERATIONS

OVERVIEW

The Utility is regulated primarily by the CPUC and the FERC. 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 interstate natural gas transportation contracts. The NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. The Utility also is subject to the jurisdiction of other federal, state, and local governmental agencies.

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. It should also be read in conjunction with the 2013 Annual Report.

Summary of Changes in Net Income and Earnings per Share

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 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 - 2013	$	328		$	0.74		$	567		$	1.29
Natural gas matters (1)		(40	)		(0.08	)		(27	)		(0.06	)
Growth in rate base earnings (2)		6			0.01			11			0.02
Timing of 2014 GRC expense recovery (3)		(21	)		(0.04	)		(41	)		(0.08	)
Increase in shares outstanding (4)		-			(0.04	)		-			(0.07	)
Other		(6	)		(0.02	)		(16	)		(0.04	)
Income Available for Common Shareholders - 2014	$	267		$	0.57		$	494		$	1.06

(1) Represents the increase in net costs related to natural gas matters during the three and six months ended June 30, 2014 as compared to the same periods in 2013. These amounts are not recoverable through rates. See “Operating and Maintenance” below.

(2) Represents the impact of the increase in rate base as authorized in various rate cases during the three and six months ended June 30, 2014 as compared to the same periods in 2013.

(3) Represents additional capital-related expenses during the three and six months ended June 30, 2014 as compared to the same periods in 2013, with no corresponding increase in revenue. The CPUC has not yet issued a final decision on the Utility’s 2014 GRC request to increase revenues beginning on January 1, 2014. Upon receipt of a final decision, the Utility has been authorized to collect any final adopted increase in revenue requirements from January 1, 2014.

(4) Represents the impact of a higher number of weighted average shares of common stock outstanding during the three and six months ended June 30, 2014 as compared to the same periods in 2013. PG&E Corporation issues shares to fund its equity contributions to the Utility to maintain the Utility’s capital structure and fund operations, including unrecovered expenses related to natural gas matters.

Key Factors Affecting Financial Results

PG&E Corporation and the Utility believe that their future results of operations, financial condition, and cash flows will be materially affected by the following factors :

·	The Timing and Outcome of Ratemaking Proceedings. The majority of the Utility’s revenue requirements for the next several years will be determined by the outcomes of the 2014 GRC and the 2015 GT&S rate case. A proposed decision was recently issued in the Utility’s GRC that recommended an increase in 2014 revenue requirements of $453 million, or 6.8% over currently authorized amounts, compared to the Utility’s requested increase of $1,160 million. The proposed decision also recommended attrition increases of $322 million for 2015 and $371 million for 2016. Upon receipt of a final decision, the Utility has been authorized to collect any final adopted increase in revenue requirements from January 1, 2014. (See “2014 General Rate Case” below.) In the GT&S rate case, the Utility is seeking an increase in its 2015 revenue requirements of $555 million over the comparable authorized revenues for 2014, as well as attrition increases for 2016 and 2017. After the CPUC issues a final decision, the Utility’s authorized revenue requirements will be adjusted as of January 1, 2015. (See “2015 Gas Transmission and Storage Rate Case” below.) In addition, the Utility has two transmission owner rate cases pending at the FERC. (See “FERC Transmission Owner Rate Cases” below.) The positions taken by the intervening parties in these proceedings are often contentious and the outcome 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. 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. (See “Results of Operations – Utility Revenues and Costs That Impact Earnings” below.) During the last GRC and GT&S rate case periods, the Utility incurred costs to improve the safety and reliability of its electric and natural gas operations that materially exceeded annual authorized revenues. PG&E Corporation’s and the Utility’s future results of operations, financial condition, and cash flows could be materially affected if the Utility’s actual costs differ from the amounts assumed or authorized in the final 2014 GRC and 2015 GT&S rate case decisions. (See “Regulatory Matters” below.) The Utility also forecasts that in 2014 it will incur unrecovered pipeline-related expenses ranging from $350 million to $450 million, including costs to perform continuing work under the Utility’s PSEP and other gas transmission safety work, as well as legal and other expenses. The Utility also could record charges in 2014 for PSEP capital if the Utility’s cost forecasts increase. (See “Pipeline Safety Enhancement Plan” below.) Differences between the amount or timing of the Utility’s actual costs and forecasted or authorized amounts may affect the Utility’s ability to earn its authorized ROE.

·	The Outcome of Pending Investigations and Enforcement Matters. Three CPUC investigations are still pending against the Utility related to its natural gas operations and the San Bruno accident. It is uncertain when the outcome of these investigations will be determined. Under the SED’s penalty recommendation, the Utility estimates that its total unrecovered costs and fines related to natural gas transmission operations would be about $4.5 billion. (See “Pending CPUC Investigations” below.) The U.S. Attorney’s Office has filed a superseding criminal indictment against the Utility alleging that it violated the Pipeline Safety Act and illegally obstructed the NTSB’s investigation of the San Bruno accident that occurred on September 9, 2010. Based on the superseding indictment’s allegation that the Utility derived gross gains of approximately $281 million, and that victims suffered losses of approximately $565 million, the maximum alternative fine would be approximately $1.13 billion. (See “Criminal Indictment” and “Item 1.A. Risk Factors” below.) In addition, fines may be imposed, or other regulatory or governmental enforcement action could be taken, with respect to the natural gas matters described under “Other Enforcement Matters” below.

·	The Amount and Timing of the Utility’s Financing Needs. PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure. For the six months ended June 30, 2014, PG&E Corporation issued common stock of $589 million and made equity contributions to the Utility of $580 million. PG&E Corporation forecasts that it will continue issuing a material amount of equity in 2014, primarily to support the Utility’s capital expenditures and to fund unrecovered costs. Depending on the outcome of the pending investigations and other enforcement matters described above, PG&E Corporation may be required to issue additional common stock to fund its equity contributions as the Utility pays fines and incurs additional unrecovered pipeline-related costs. These additional issuances could have a material dilutive effect on PG&E Corporation’s EPS. PG&E Corporation’s and the Utility’s ability to access the capital markets and the terms and rates of future financings could be affected by changes in their respective credit ratings, the outcome of the matters discussed under “Natural Gas Matters” below, general economic and market conditions, and other factors.

For more information about the factors and risks that could affect future results of operations, financial condition, and cash flows, or that could cause future results to differ from historical results, see the section entitled “Risk Factors” in the 2013 Annual Report and “Item 1A. Risk Factors” below. In addition, 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. See the section entitled “Cautionary Language Regarding Forward-Looking Statements” below for a list of some of the factors that may cause actual results to differ materially. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results and do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

RESULTS OF OPERATIONS

PG&E Corporation

The consolidated results of operations consist primarily of balances related to the Utility, which are discussed below. The following table provides a summary of net income for the three and six months ended June 30, 2014 and 2013:

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2014			2013			2014			2013
Consolidated Total		$	267		$	328		$	494		$	567
PG&E Corporation			21			3			23			8
Utility		$	246		$	325		$	471		$	559

PG&E Corporation’s net income consists primarily of interest expense on long-term debt, other income from investments, and income taxes. Results for 2014 include a gain on investments of approximately $20 million, with no similar activity in 2013.

Utility

The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2014 and 2013. The tables separately identify the revenues and costs that impacted earnings from those that did not impact earnings. In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs) and the corresponding amount of revenues collected to recover those pass-through costs, do not impact earnings. In addition, expenses that have been specifically authorized, such as the payment of pension costs, and the corresponding revenues the Utility is authorized to collect to recover such costs, do not impact earnings.

Revenues that impact earnings are primarily those that have been authorized by the CPUC and the FERC to recover the Utility’s costs to own and operate its assets and to provide the Utility an opportunity to earn its authorized rate of return on rate base. Expenses that impact earnings are primarily those that the Utility incurs to own and operate its assets.

	Three Months Ended June 30, 2014							Three Months Ended June 30, 2013
	Revenues/Costs:							Revenues/Costs:
(in millions)	That Impacted Earnings		That Did Not Impact Earnings		Total Utility			That Impacted Earnings		That Did Not Impact Earnings		Total Utility
Electric operating revenues	$	1,632	$	1,600	$	3,232		$	1,611	$	1,446	$	3,057
Natural gas operating revenues		454		265		719			431		287		718
Total operating revenues		2,086		1,865		3,951			2,042		1,733		3,775
Cost of electricity		-		1,349		1,349			-		1,189		1,189
Cost of natural gas		-		200		200			-		179		179
Operating and maintenance		1,005		316		1,321			891		365		1,256
Depreciation, amortization, and decommissioning		556		-		556			516		-		516
Total operating expenses		1,561		1,865		3,426			1,407		1,733		3,140
Operating income		525		-		525			635		-		635
Interest income (1)						3							3
Interest expense (1)						(185	)						(171	)
Other income, net (1)						17							22
Income before income taxes						360							489
Income tax provision (1)						110							160
Net income						250							329
Preferred stock dividend requirement (1)						4							4
Income Available for Common Stock					$	246						$	325

(1) These items impacted earnings for the three months ended June 30, 2014 and 2013.

	Six Months Ended June 30, 2014							Six Months Ended June 30, 2013
	Revenues/Costs:							Revenues/Costs:
(in millions)	That Impacted Earnings		That Did Not Impact Earnings		Total Utility			That Impacted Earnings		That Did Not Impact Earnings		Total Utility
Electric operating revenues	$	3,217	$	3,015	$	6,232		$	3,198	$	2,657	$	5,855
Natural gas operating revenues		925		684		1,609			870		721		1,591
Total operating revenues		4,142		3,699		7,841			4,068		3,378		7,446
Cost of electricity		-		2,559		2,559			-		2,172		2,172
Cost of natural gas		-		560		560			-		525		525
Operating and maintenance		2,038		580		2,618			1,911		681		2,592
Depreciation, amortization, and decommissioning		1,094		-		1,094			1,019		-		1,019
Total operating expenses		3,132		3,699		6,831			2,930		3,378		6,308
Operating income		1,010		-		1,010			1,138		-		1,138
Interest income (1)						5							4
Interest expense (1)						(364	)						(341	)
Other income, net (1)						37							46
Income before income taxes						688							847
Income tax provision (1)						210							281
Net income						478							566
Preferred stock dividend requirement (1)						7							7
Income Available for Common Stock					$	471						$	559

(1) These items impacted earnings for the six months ended June 30, 2014 and 2013.

Utility Revenues and Costs that Impact Earnings

The following discussion presents the Utility’s operating results for the three and six months ended June 30, 2014 and 2013, focusing on revenues and expenses that had an impact on earnings for these periods.

Operating Revenues

The Utility’s electric and natural gas operating revenues that impacted earnings increased by $44 million, or 2%, and by $74 million, or 2%, in the three and six months ended June 30, 2014, respectively, compared to the same periods in 2013, primarily due to increases in revenues authorized by the FERC in the electric transmission rate case and revenues the CPUC authorized the Utility to collect for recovery of certain PSEP-related costs, as well as other higher gas transmission revenues resulting from additional demand for gas-fired generation (see "Cost of Electricity" below). The increase for both periods was partially offset by $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, with no similar activity in 2014.

In June 2014, a proposed decision was issued in the Utility’s 2014 GRC that recommends an increase in revenue requirements of $453 million, or 6.8%, over currently authorized amounts. Upon receipt of a final decision, the Utility has been authorized to collect any final adopted increase in revenue requirements from January 1, 2014. The Utility has not recorded any revenues associated with the GRC proposed decision in the three and six months ended June 30, 2014. See “Regulatory Matters” below.

Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings increased by $114 million, or 13%, and by $127 million, or 7%, in the three and six months ended June 30, 2014, respectively, compared to the same periods in 2013. The increases are primarily due to higher unrecovered costs of $68 million and $46 million, respectively, incurred in connection with natural gas matters (see table below). The remaining increases consisted of benefit-related expenses and other expenses.

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)	2014		2013			2014		2013
Pipeline-related expenses (1)	$	97	$	74		$	137	$	136
Insurance recoveries		-		(45	)		-		(45	)
Total natural gas matters	$	97	$	29		$	137	$	91

(1) Includes $58 million for work performed under the PSEP and $64 million for other gas safety-related work for the six months ended June 30, 2014. See “Natural Gas Matters” below.

There were no additional charges recorded in the three and six months ended June 30, 2014 and 2013, respectively, related to natural gas matters for disallowed capital, fines, or third-party claims. As described in “Key Factors Affecting Financial Results” above, the Utility forecasts that its total unrecoverable pipeline-related expenses in 2014 will range from $350 million to $450 million. See “Natural Gas Matters” below.

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning expenses increased by $40 million, or 8%, and by $75 million, or 7%, in the three and six months ended June 30, 2014, respectively, compared to the same periods in 2013, primarily due to the impact of capital additions.

Interest Income, Interest Expense, and Other Income, Net

There were no material changes to interest income, interest expense, and other income, net for the periods presented.

Income Tax Provision

The Utility’s income tax provision decreased by $50 million, or 31%, and by $71 million, or 25%, in the three and six months ended June 30, 2014 compared to the same periods in 2013. The effective tax rates were 31% and 33% in the three and six months ended June 30, 2014 and 2013, respectively. The decrease in effective tax rates for both periods was primarily due to higher deductible software development costs in 2014.

Utility Revenues and Costs that do not Impact Earnings

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 volume of power purchased by the Utility is driven by customer demand, the availability of the Utility’s own generation facilities, and the cost effectiveness of each source of electricity. Additionally, the cost of electricity is impacted by the higher cost of procuring renewable energy as the Utility increases the amount of its renewable energy deliveries to comply with California legislative and regulatory requirements, and by costs associated with complying with California’s GHG laws.

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2014		2013		2014		2013
Cost of purchased power	$	1,287	$	1,120	$	2,399	$	2,030
Fuel used in own generation facilities		62		69		160		142
Total cost of electricity	$	1,349	$	1,189	$	2,559	$	2,172
Average cost of purchased power per kWh (1)	$	0.097	$	0.088	$	0.093	$	0.086
Total purchased power (in millions of kWh)		13,320		12,788		25,788		23,674

(1) Kilowatt-hour

The Utility’s cost of electricity for 2014 is expected to continue to be higher due to the low levels of hydroelectric generation caused by the drought in California and higher market prices for natural gas used to fuel conventional generation resources. The Utility expects that it will be able to continue to recover the increasing cost of electricity through rates. If the Utility’s forecasted aggregate over-collections or under-collections of its electricity procurement costs exceed five percent of its prior year electricity procurement revenues, the CPUC may authorize an adjustment to retail electricity generation rates before the next annual update, which is January 1, 2015.

Cost of 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 impacted by the market price of natural gas, changes in the cost of storage and transportation, changes in customer demand, and by costs associated with complying with California’s GHG laws.

	Three Months Ended June 30,				Six Months Ended June 30,
(in millions)	2014		2013		2014		2013
Cost of natural gas sold	$	165	$	137	$	489	$	437
Transportation cost of natural gas sold		35		42		71		88
Total cost of natural gas	$	200	$	179	$	560	$	525
Average cost per Mcf (1) of natural gas sold	$	4.34	$	3.43	$	4.22	$	3.08
Total natural gas sold (in millions of Mcf)		38		40		116		142

(1) One thousand cubic feet

Operating and Maintenance Expenses

The Utility’s operating expenses also include certain recoverable costs that the Utility incurs as part of its operations such as public purpose programs, pension, and other recurring expenses. If the Utility were to spend over authorized amounts, these expenses could have an impact to earnings.

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 Utility generally utilizes equity contributions from PG&E Corporation and long-term senior unsecured debt issuances to maintain its CPUC-authorized capital structure consisting of 52% equity and 48% debt and preferred stock. 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’s future equity needs will continue to be affected by costs that are not recoverable through rates, including costs related to natural gas matters, and will also be affected by various other factors described in “Operating Activities” below. The Utility’s equity needs would also increase to the extent it is required to pay fines or penalties in connection with the CPUC’s pending investigations and other enforcement matters related to its natural gas operations. (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 ability to fund operations, make scheduled principal and interest payments, fund equity contributions to the Utility, and pay dividends, primarily depends on the level of cash distributions received from the Utility and PG&E Corporation’s access to the capital and credit markets. PG&E Corporation’s equity contributions to the Utility are funded primarily through common stock issuances. These contributions have been dilutive to PG&E Corporation’s EPS to the extent that the equity contributions are used by the Utility to restore equity that has been depleted by unrecoverable costs and charges. Future issuances of common stock by PG&E Corporation to fund equity contributions could have a material dilutive effect on EPS depending upon the ultimate outcomes of the CPUC’s pending investigations, the criminal proceeding and other enforcement matters, as well as the extent to which the Utility incurs costs that are not recoverable through rates.

2014 Financings

PG&E Corporation

In February 2014, PG&E Corporation issued $350 million principal amount of 2.40% Senior Notes due March 1, 2019. The proceeds were used to repay the 5.75% Senior Notes, in the principal outstanding amount of $350 million. PG&E Corporation also entered into a new equity distribution agreement in February 2014 providing for the sale of its common stock having an aggregate gross sales price of up to $500 million.

PG&E Corporation issued common stock in the following transactions:


·	During the six months ended June 30, 2014, 4 million shares were issued for cash proceeds of $160 million under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans; and
·	During the three and six months ended June 30, 2014, PG&E Corporation sold 5 and 10 million shares under the February 2014 equity distribution agreement for cash proceeds of $206 and $429 million, net of commissions paid of $2 and $4 million, respectively.

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, 2014, PG&E Corporation made equity contributions to the Utility of $580 million. On July 30, 2014, PG&E Corporation made an equity contribution to the Utility of $125 million. PG&E Corporation forecasts that it will need to continue to issue additional common stock to fund the Utility’s equity needs.

Utility

Revolving Credit Facilities and Commercial Paper Program

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings at June 30, 2014:

						Letters of
	Termination	Facility				Credit						Commercial			Facility
(in millions)	Date	Limit				Outstanding			Borrowings			Paper			Availability
PG&E Corporation	April 2019		$	300	(1)		$	-		$	-		$	112		$	188
Utility	April 2019			3,000	(2)			86			-			1,041			1,873
Total revolving
credit facilities			$	3,300			$	86		$	-		$	1,153		$	2,061

(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.

For the six months ended June 30, 2014, the average outstanding borrowings under PG&E Corporation’s revolving credit facility were $54 million and the maximum outstanding balance was $260 million. In February 2014, PG&E Corporation repaid the full outstanding borrowings of $260 million and initiated borrowing under its commercial paper program established in January 2014. For the six months ended June 30, 2014, PG&E Corporation’s average outstanding commercial paper balance was $138 million and the maximum outstanding balance during the period was $260 million.

For the six months ended June 30, 2014, the Utility’s average outstanding commercial paper balance was $957 million and the maximum outstanding balance during the period was $1.4 billion. The Utility has not borrowed under its credit facility during 2014.

At June 30, 2014, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

Dividends

In June 2014, the Board of Directors of PG&E Corporation declared quarterly dividends of $0.455 per share, totaling $215 million, of which approximately $210 million was paid on July 15, 2014 to shareholders of record on June 30, 2014.

In June 2014, the Board of Directors of the Utility declared a common stock dividend of $179 million that was paid to PG&E Corporation on June 19, 2014.

In June 2014, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on August 15, 2014, to shareholders of record on July 31, 2014.

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, 2014 and 2013 were as follows:

	Six Months Ended June 30,
(in millions)	2014			2013
Net income	$	478		$	566
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, amortization, and decommissioning		1,094			1,019
Allowance for equity funds used during construction		(46	)		(52	)
Deferred income taxes and tax credits, net		18			337
Other		108			126
Net effect of changes in operating assets and liabilities		(391	)		(532	)
Net cash provided by operating activities	$	1,261		$	1,464

During the six months ended June 30, 2014, net cash provided by operating activities decreased by $203 million compared to the same period in 2013. This decrease consisted of various fluctuations in cash flows including higher purchased power costs and natural gas costs during 2014 as compared to 2013.

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


·	the timing and outcome of ratemaking proceedings, including the 2014 GRC and 2015 GT&S rate cases;

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

·	the timing and amount of insurance recoveries related to third-party claims (see “Natural Gas Matters” below);

·	the timing and amount of fines or penalties that may be imposed, as well as any costs associated with remedial actions the Utility may be required to implement (see “Natural Gas Matters” below);

·	the timing and amount of costs the Utility incurs, but does not recover, to improve the safety and reliability of its natural gas system (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 provide safe and reliable electricity and natural gas services to its customers. 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, 2014 and 2013 were as follows:

	Six Months Ended June 30,
(in millions)	2014			2013
Capital expenditures	$	(2,320	)	$	(2,521	)
Decrease in restricted cash		2			25
Proceeds from sales and maturities of nuclear decommissioning trust investments		877			795
Purchases of nuclear decommissioning trust investments		(873	)		(786	)
Other		17			8
Net cash used in investing activities	$	(2,297	)	$	(2,479	)

Net cash used in investing activities decreased by $182 million during the six months ended June 30, 2014 compared to the same period in 2013 primarily due to lower capital expenditures.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility estimates that it will incur between $5 billion and $6 billion in capital expenditures for 2014, including PSEP-related expenditures.

Financing Activities

The Utility’s cash flows from financing activities for the six months ended June 30, 2014 and 2013 were as follows:

	Six Months Ended June 30,
(in millions)	2014			2013
Net issuances of commercial paper, net of discount of $1 at respective dates	$	125		$	321
Proceeds from issuance of short-term debt, net of issuance costs		300			-
Proceeds from issuance of long-term debt, net of premium, discount, and issuance
costs of $11 and $8 at respective dates		889			742
Repayments of long-term debt		(539	)		(461	)
Preferred stock dividends paid		(7	)		(7	)
Common stock dividends paid		(358	)		(358	)
Equity contribution		580			665
Other		51			(20	)
Net cash provided by financing activities	$	1,041		$	882

During the six months ended June 30, 2014, net cash provided by financing activities increased by $159 million compared to the same period in 2013. 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 debt issuances and equity contributions from PG&E Corporation to maintain its CPUC-authorized capital structure, and relies on commercial paper and other short-term debt to fund temporary financing needs.

NATURAL GAS MATTERS

Since the San Bruno accident occurred on September 9, 2010, PG&E Corporation and the Utility have incurred total cumulative charges of approximately $2.6 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, 2013			June 30, 2014		June 30, 2014
Pipeline-related expenses (1)	$	1,410		$	137	$	1,547
Disallowed capital (2)		549			-		549
Accrued fines (3)		239			-		239
Third-party liability claims (4)		565			-		565
Insurance recoveries (4)		(354	)		-		(354	)
Contribution to City of San Bruno		70			-		70
Total natural gas matters	$	2,479		$	137	$	2,616

(1)	Cumulative costs through June 30, 2014 included PSEP expenses of approximately $794 million and other gas safety-related work of $411 million. The Utility forecasts that it will incur total unrecovered pipeline-related expenses ranging from $350 million to $450 million in 2014.

(2)	See “Pipeline Safety Enhancement Plan” below.

(3)	See “Pending CPUC Investigations” below.

(4)	See “Third-Party Liability Claims” below.

Pending CPUC Investigations

As described in the 2013 Annual Report, there are three CPUC investigative enforcement proceedings pending against the Utility related to its natural gas operations and the San Bruno accident. The ALJs who are presiding over the investigations are expected to issue one or more decisions to address the violations that they have determined the Utility committed and to impose penalties. It is uncertain when these decisions will be issued. In July 2013, the SED recommended that the CPUC impose what the SED characterizes as a penalty of $2.25 billion on the Utility, allocated as follows: (1) $300 million as a fine payable to the State General Fund, (2) $435 million for a portion of costs related to the Utility’s PSEP that were previously disallowed by the CPUC and funded by shareholders, and (3) $1.5 billion to perform PSEP work that was previously approved by the CPUC, implement operational remedies, and for future costs. Other parties, including the City of San Bruno, TURN, the CPUC’s ORA, and the City and County of San Francisco, have recommended total penalties of at least $2.25 billion, including fines payable to the State General Fund of differing amounts.

Aside from any penalty resulting from the CPUC’s investigations, the Utility estimates that its total unrecovered costs for gas pipeline safety-related work incurred or committed over the next several years will be approximately $2.7 billion, including cumulative charges reflected in the table above for unrecovered PSEP expenses and capital costs and other gas safety-related work (see “pipeline-related expenses” and “disallowed capital”). If the SED’s penalty recommendation is adopted by the CPUC, the Utility estimates that its total unrecovered costs related to natural gas transmission operations would be about $4.5 billion, including: (1) the approximately $2.7 billion discussed in the preceding sentence; (2) a fine of $300 million; and (3) $1.5 billion to perform incremental shareholder-funded gas safety work.

On July 28, 2014, the City of San Bruno filed a motion alleging that the Utility violated CPUC rules that prohibit certain communications between “an interested person,” such as the Utility, and a “decision maker,” such as a Commissioner, regarding adjudicatory proceedings, such as the pending investigations. The City of San Bruno requested that the CPUC issue an “order to show cause” why the Utility should not be penalized for the alleged violations. The City of San Bruno also filed a motion seeking the recusal of the President of the CPUC from serving as an assigned Commissioner in the investigatory proceedings and from voting on the final decisions. Responses to the motions are due on August 12, 2014.

Criminal Indictment

Other Enforcement Matters

Gas Safety Citation Program. The SED has authority to issue citations and impose fines on California gas corporations, such as the Utility, for violations of certain state and federal regulations that relate to the safety of natural gas facilities and operating practices. The California gas corporations are required to inform the SED of any self-identified or self-corrected violations of these regulations. (California law also requires the CPUC to adopt a safety enforcement program for California electric corporations. See “Regulatory Matters” below.) The SED has discretion to impose fines or take other enforcement action to address a violation, based on the totality of the circumstances. The SED can consider various factors in determining whether to impose fines and the amount of fines, including the severity of the safety risk associated with each violation, the number and duration of the violations, whether the violation was self-reported, and whether corrective actions were taken. The SED has imposed fines ranging from $50,000 to $16.8 million in connection with several of the Utility’s self-reports.

Pipeline Safety Enhancement Plan

Third-Party Liability Claims

The Utility has recorded cumulative charges of $565 million as its best estimate of probable loss for third-party claims related to the San Bruno accident. The Utility has settled substantially all third-party claims. Since the San Bruno accident, the Utility has made cumulative settlement payments of $532 million through June 30, 2014. In addition, the Utility has incurred cumulative expenses of $88 million for associated legal costs. The Utility has recognized cumulative insurance recoveries of $354 million for third-party claims and associated legal costs. The Utility believes it will recover a significant portion of its remaining costs through insurance, although the amount and timing of additional insurance recoveries are uncertain. The Utility has been engaged in settlement negotiations with its insurers regarding recovery of its remaining claims and costs.

Class Action Complaint

Other Pending Lawsuits and Claims

At June 30, 2014, there were also five purported shareholder derivative lawsuits outstanding against PG&E Corporation and the Utility seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims. The plaintiffs for four of these lawsuits filed a consolidated complaint with the San Mateo County Superior Court. Although the proceedings were stayed, the state court permitted the plaintiffs to amend the consolidated complaint to discuss recent events, including the federal criminal indictment discussed above. The plaintiffs in the consolidated state court lawsuits have requested that the judge lift the stay and allow the litigation to resume and PG&E Corporation, the Utility, and the individual defendants have requested that the judge continue the stay while the criminal proceeding is pending. On July 25, 2014, the judge issued a tentative ruling to lift the stay. At a hearing held on July 28, 2014, the judge stated that he would issue his final ruling on August 1, 2014. PG&E Corporation, the Utility, and the individual defendants have reserved their right to challenge all of the allegations in the amended complaint if the stay is lifted. The purported shareholder derivative lawsuit that was filed in the U.S. District Court for the Northern District of California remains stayed.

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 lawsuits 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. Significant regulatory developments that have occurred since the 2013 Annual Report was filed with the SEC are discussed below.

2014 General Rate Case

In the GRC, the CPUC will determine the revenue requirements that the Utility is authorized to collect through rates from 2014 through 2016 to recover anticipated costs associated with its electric and natural gas distribution operations and electric generation operations. The revenue requirements requested by the Utility were based on the Utility’s detailed expense and capital forecasts developed using operational plans that incorporate risk assessments and mitigation measures to address safety and security issues. The Utility also made various assumptions to develop these forecasts, including assumptions about depreciation methods and rates, cost escalation rates, and flow-through treatment of certain federal tax benefits.

On June 18, 2014, a proposed decision was issued that recommends an increase in 2014 revenue requirements of $453 million, or 6.8% over currently authorized amounts, compared to the $1,160 million, or 17.5%, increase requested by the Utility. The proposed decision recommends a total authorized revenue requirement of $7.1 billion for 2014 compared to the Utility’s $7.8 billion request. The proposed decision recommends attrition increases of $322 million for 2015 and $371 million for 2016, compared to the Utility’s requested attrition increases, as adjusted, of $436 million for 2015 and $486 million for 2016. The following table shows the differences between the Utility’s requested increases in 2014 revenue requirements and the recommended amounts by line of business:


	Proposed		Requested
(in millions)	Decision		by the Utility		Difference
Line of business
Electric distribution	$	127	$	514	$	(387	)
Gas distribution		242		446		(204	)
Electric generation		84		200		(116	)
Total revenue increase	$	453	$	1,160	$	(707	)

Compared to the Utility’s 2014 request, the proposed decision recommends reductions in funding for various safety, reliability, and customer service improvements across various parts of the business. The proposed decision recommends a depreciation rate-related expense increase of approximately $157 million as compared to the $492 million increase supported by the Utility’s depreciation rate study. The Utility’s analysis of the proposed decision also indicates that, if approved, the Utility’s 2014 capital expenditures would be reduced from the $3.9 billion requested to approximately $3.5 billion. The proposed decision recommends authorizing a 2014 weighted average rate base of $20.5 billion as compared to the Utility’s request of $21.0 billion, which reflects a reduction of approximately $400 million to exclude nuclear fuel inventory from rate base.

The proposed decision agrees with the Utility’s request for new two-way balancing accounts to allow the Utility to recover costs associated with gas leak survey and repair, major emergencies, and certain new regulatory requirements related to nuclear operations and hydroelectric relicensing.

In July 2014, several parties, including the Utility, the CPUC’s ORA, and TURN, submitted comments on the proposed decision. The CPUC may issue a final decision at its meeting on August 14, 2014. Upon receipt of a final decision, the Utility has been authorized to collect any final adopted increase in revenue requirements from January 1, 2014. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially affected if the Utility’s actual costs differ from the amounts authorized in the final GRC decision.

2015 Gas Transmission and Storage Rate Case

As disclosed in the 2013 Annual Report, the Utility has requested that the CPUC approve an annual revenue requirement of $1.29 billion for 2015 for the Utility’s anticipated costs of providing natural gas transmission and storage services, with attrition increases of $61 million in 2016 and $168 million in 2017. The CPUC has authorized the Utility’s revenue requirement changes to become effective as of January 1, 2015, even if the final decision is issued after that date. The CPUC’s current procedural schedule contemplates intervenor testimony to be submitted in August 2014, followed by evidentiary hearings to be held in October 2014, and a final decision to be issued in approximately March 2015.

The Utility has not requested authorization to recover approximately $150 million of costs it forecasts it will incur over the three-year period to pressure test pipelines placed into service after 1961 and perform remedial work associated with the Utility’s pipeline corrosion control program. The Utility also has not requested authorization to recover costs it forecasts it will incur through 2017 to identify and remove encroachments from its gas transmission pipeline rights-of-way.

The Utility’s continued use of regulatory accounting under GAAP (which enables it to account for the effects of regulation, including recording regulatory assets and liabilities) for gas transmission and storage service depends on its ability to recover its cost of service. If the Utility were unable to continue using regulatory accounting under GAAP, there would be differences in the timing of expense (or gain) recognition that could materially affect PG&E Corporation’s and the Utility’s future financial results.

FERC Transmission Owner Rate Cases

The Utility has two transmission owner rate cases pending at the FERC. With respect to the rate case that was filed in July 2013, the Utility, the FERC Trial Staff and all active intervening parties reached a settlement that was submitted to the FERC for approval in July 2014. The settlement, if approved, will increase the annual retail revenue requirement from $1,017 million to approximately $1,040 million, effective as of October 1, 2013. The Utility has been collecting revenues at the higher as-filed rates requested in the Utility’s application. In future periods, the Utility will refund to customers the difference between revenues collected at the higher as-filed rates and the rates approved in the settlement. It is uncertain when the FERC will act on the settlement.

On July 30, 2014, the Utility filed an application with the FERC to request authorization of its proposed 2015 retail electric transmission revenue requirement of $1,366 million, a $326 million increase to the revenue requirements, if approved, described in the preceding paragraph. The Utility’s 2015 cost forecasts reflect the continuing need to replace and modernize aging electric transmission infrastructure, to meet the need for increased capacity in the CAISO controlled grid, 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 $975 million in 2014 and $1,125 million in 2015 in various capital projects. The proposed rate base in 2015 is forecast to be $5.12 billion compared to $4.57 billion in 2014. The Utility has requested that the FERC approve a 11.26% ROE. The Utility has requested the FERC to issue an order by September 2014 to accept the application and make the new rates effective on October 1, 2014, subject to refund pending a final decision by the FERC. It is anticipated that the rates will be suspended for five months and made effective on March 1, 2015, subject to refund.

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. The CPUC’s denial of various applications for rehearing that had been filed with respect to its decision was appealed to the California Court of Appeal. In February 2014, the California Court of Appeal issued a ruling that annulled the CPUC's decision after the court determined that the evidence presented did not support a finding of need for the Oakley facility. The Utility is considering its options.

Diablo Canyon Power Plant

The Utility filed an application with the NRC in 2009 to renew the operating licenses for the two operating units at Diablo Canyon. (The current licenses expire in 2024 and 2025.) In May 2011, after an earthquake and resulting 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 while certain advanced seismic studies were completed by the Utility. The Utility is currently assessing the data from recently completed advanced seismic studies along with other available seismic data and expects to provide its final seismic report to the NRC and the CPUC’s Independent Peer Review Panel in the third quarter of 2014. (See the “2013 Annual Report” for additional information.)

Safety Enforcement Programs

On May 21, 2014, the CPUC began a rulemaking proceeding to implement a new electric safety citation program that would authorize CPUC staff to issue citations for safety violations and assess fines. California law enacted in 2013 requires the CPUC to implement a safety enforcement program for gas corporations by July 1, 2014 and for electric corporations by January 1, 2015. The rulemaking noted that the CPUC’s current gas safety enforcement program appears to satisfy the law’s requirements. (See “Natural Gas Matters – Other Enforcement Matters” above about the reports the Utility has filed to notify the CPUC staff of noncompliance with certain gas safety regulations.) As part of the rulemaking proceeding, the CPUC may modify the gas program and determine the timing and process for considering future modifications of the citation programs. The CPUC has indicated that it plans to implement an electric safety citation program before the end of 2014 and that it plans to decide which safety violations electric corporations will be required to self-report. Depending on the number and severity of reported violations, the Utility could be required to pay fines that, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.

Electricity Rate Reform

New state legislation that became effective on January 1, 2014 (AB 327) repealed prior law that restricted the CPUC’s ability to change residential electric rates, granting the CPUC authority to approve fixed charges to be collected from residential customers. In 2012, the CPUC began a rulemaking to examine residential rate design in California that, consistent with AB 327, allows the CPUC to simplify the rate structure and bring rates closer to actual costs. In February 2014, as ordered by the CPUC, the Utility submitted a long-term rate reform plan that proposes a fixed customer charge, gradual flattening of the tiered rate structure, and an optional time-of-use rate. The CPUC is expected to issue a final decision by the summer of 2015.

AB 327 also requires the CPUC to develop a new structure for net energy metering by December 31, 2015 that must be implemented no later than July 1, 2017. California’s net energy metering program currently allows customers installing renewable distributed generation to receive bill credits for power delivered to the grid at their full retail rate. Increasing levels of self-generation of electricity by customers, coupled with net metering, has increased rates and shifted costs to remaining customers. AB 327 gives the CPUC new authority to reduce the cost shift associated with renewable distributed generation under the net energy metering rules. In July 2014, the CPUC began a rulemaking proceeding to develop a successor to the existing net energy metering program to comply with the requirements of AB 327. The CPUC’s preliminary schedule contemplates a scoping memo to be issued in September 2014 and a proposed decision in the fall of 2015.

If the CPUC fails to adjust the Utility’s rate design to bring rates closer to actual costs, or to adequately address the impact of increasing net energy metering and the growth of distributed generation, there will be increasing rate pressure on remaining customers. These increasing rate pressures could, in turn, cause more customers to seek alternative energy providers or sources, further exacerbating the Utility’s risk it will not recover its costs to provide electric service.

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. 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. (See “Risk Factors” in the 2013 Annual Report.)

Natural Gas Compressor Station 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 stations. The Utility is also required to take measures to abate the effects of the contamination on the environment. At June 30, 2014, $170 million and $269 million was accrued in the Condensed Consolidated Balances Sheets for estimated undiscounted remediation costs associated with the Hinkley site and the Topock site, respectively. Costs associated with the Hinkley site are not recovered through rates. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements.)

Clean Air Act

In June 2014, the EPA published draft federal regulations under section 111(d) of the Clean Air Act that are designed to reduce GHG emissions from existing fossil fuel-fired power plants by as much as 30 percent by 2030, compared with 2005 levels. As presently written, once the EPA has finalized regulations, all states will have one year to prepare, adopt, and submit to the EPA an implementation plan addressing how each state will control GHG emissions from existing power plants. The EPA is expected to issue final regulations by June 2015. It is uncertain whether and how these federal regulations would ultimately impact existing California state regulation, which currently requires, among other things, the gradual reduction of state-wide GHG emissions to the 1990 level by 2020. (As disclosed in the 2013 Annual Report, the Utility expects all costs and revenues associated with the state-wide, comprehensive “cap and trade” program to be passed through to customers).

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 2013 Annual Report and “Liquidity and Financial Resources” above.)

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 14 of the Notes to the Consolidated Financial Statements in the 2013 Annual Report (the Utility’s commodity purchase agreements).

RISK MANAGEMENT ACTIVITIES

PG&E Corporation, mainly through its ownership of the Utility, and 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 and offset credits, 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 2013 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, 2014.

CRITICAL ACCOUNTING POLICIES

The preparation of the Condensed Consolidated Financial Statements in accordance with U.S. GAAP involves 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. These policies are considered critical accounting policies due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ materially from these estimates. These accounting policies and their key characteristics are discussed in detail in the 2013 Annual Report.

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

Revenue Recognition Standard

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

This 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 and proceedings; forecasts of costs the Utility will incur to make safety and reliability improvements, including natural gas transmission costs 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:

·	the timing and outcome of the pending CPUC investigations and enforcement matters related to the Utility’s natural gas system operating practices and the San Bruno accident, including the ultimate amount of fines the Utility will be required to pay to the State General Fund, the ultimate amount of costs the Utility will incur in its natural gas transmission business that it will not recover through rates, including the cost of any remedial actions the Utility may be ordered to perform;

·	the timing and outcome of the federal criminal prosecution of the Utility, including the amount of any criminal fines or penalties imposed;

·	whether the CPUC or a federal judge in the criminal case appoints a monitor to oversee the Utility’s natural gas operations;

·	whether additional investigations are commenced relating to the Utility’s natural gas operating practices or specific incidents;

·	whether PG&E Corporation and the Utility are able to repair the harm to their reputations caused by negative publicity about the San Bruno accident, the CPUC investigations, the criminal prosecution, the Utility’s self-reports of noncompliance with certain natural gas safety regulations, and the ongoing work to remove encroachments from transmission pipeline rights-of-way;

·	the outcomes of ratemaking proceedings, such as the 2014 GRC, the 2015 GT&S rate case, and the transmission owner rate cases and whether the cost and revenue forecasts assumed in such outcomes prove to be accurate;

·	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 that it cannot recover through rates, including costs and fines associated with natural gas matters and the pending investigations;

·	the outcome of future investigations, citations, or other enforcement proceedings, that may be commenced relating to the Utility’s compliance with laws, rules, regulations, or orders applicable to its operations, including the construction, expansion or replacement of its electric and gas facilities; inspection and maintenance practices, customer billing and privacy, and physical and cyber security;

·	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 nuclear industry, including operations, seismic design, security, safety, relicensing, the storage of spent nuclear fuel, decommissioning, cooling water intake, or other issues; and whether the Utility decides to request that the NRC resume processing the Utility’s renewal application for the two Diablo Canyon operating licenses, and if so, whether the NRC grants the renewal;

·	the impact of droughts or other weather-related conditions or events, climate change, natural disasters, acts of terrorism, war, or vandalism (including cyber-attacks), and other events, 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, such as the cost of emission allowances and offsets under cap-and-trade regulations and the cost of renewable energy procurement;

·	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; municipalization of the Utility’s electric or gas 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”; the development of alternative energy technologies including self-generation, storage and distributed generation technologies; and changing levels of “core gas aggregation” customers who procure gas from core transport agents (alternative gas providers);

·	the supply and price of electricity, natural gas, and nuclear fuel; 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 electric generation and energy commodity costs through rates, especially if the integration of renewable generation resources force conventional generation resource providers to curtail production, triggering “take or pay” provisions in the Utility’s power purchase agreements;

·	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 against unauthorized or inadvertent disclosure of information 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 can be recovered through insurance, rates, or from other third parties; including the timing and amount of insurance recoveries related to third party claims arising from the San Bruno accident;

·	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 ultimate outcomes of the matters discussed under “Natural Gas Matters” below affect the Utility’s ability to make distributions to PG&E Corporation, 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, regulations, or their interpretation; 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 2013 Annual Report and “Item 1A. Risk Factors” below. PG&E Corporation and the Utility do not undertake any obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

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, 2014, 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, 2014 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

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 2013 Annual Report.

Criminal Indictment

Pending CPUC Investigations

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. The ALJs who are presiding over the investigations are expected to issue one or more decisions to address the violations that they have determined the Utility committed and to impose penalties. It is uncertain when these decisions will be issued. The SED has 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 payable to the State General Fund and $1.95 billion of non-recoverable costs.

For additional information, see the discussion entitled “Natural Gas Matters – Pending CPUC Investigations” 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. In addition, see “Part I, Item 3. Legal Proceedings” in the 2013 Annual Report and “Part II, Item 1. Legal Proceedings” in PG&E Corporation’s and the Utility’s combined Quarterly Report on Form 10-Q for the quarter ended March 31, 2014.

Litigation Related to the San Bruno Accident and Natural Gas Spending

At June 30, 2014, there were five purported shareholder derivative lawsuits outstanding against PG&E Corporation and the Utility seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims. The plaintiffs for four of these lawsuits filed a consolidated complaint with the San Mateo County Superior Court. Although the proceedings were stayed, the state court permitted the plaintiffs to amend the consolidated complaint to discuss recent events, including the federal criminal indictment discussed above. The plaintiffs in the consolidated state court lawsuits have requested that the judge lift the stay and allow the litigation to resume and PG&E Corporation, the Utility, and the individual defendants have requested that the judge continue the stay while the criminal proceeding is pending. On July 25, 2014, the judge issued a tentative ruling to lift the stay. At a hearing held on July 28, 2014, the judge stated that he would issue his final ruling on August 1, 2014. PG&E Corporation, the Utility, and the individual defendants have reserved their right to challenge all of the allegations in the amended complaint if the stay is lifted. The purported shareholder derivative lawsuit that was filed in the U.S. District Court for the Northern District of California remains stayed.

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 regarding these matters as well as third-party liability claims related to the San Bruno Accident, see 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. In addition, see “Part I, Item 3. Legal Proceedings” in the 2013 Annual Report and “Part II, Item 1. Legal Proceedings” in PG&E Corporation’s and the Utility’s combined Quarterly Report on Form 10-Q for the quarter ended March 31, 2014.

Gas Safety Citation Program

The SED has authority to issue citations and impose fines on California gas corporations, such as the Utility, for violations of certain state and federal regulations that relate to the safety of natural gas facilities and operating practices. The California gas corporations are required to inform the SED of any self-identified or self-corrected violations of these regulations. The SED has discretion to impose fines or take other enforcement action to address a violation, based on the totality of the circumstances. The SED can consider various factors in determining whether to impose fines and the amount of fines, including the severity of the safety risk associated with each violation, the number and duration of the violations, whether the violation was self-reported, and whether corrective actions were taken. The SED has imposed fines ranging from $50,000 to $16.8 million in connection with several of the Utility’s self-reports.

For additional information, see the discussion entitled “Natural Gas Matters – Other 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. In addition, see “Part I, Item 3. Legal Proceedings” in the 2013 Annual Report and “Part II, Item 1. Legal Proceedings” in PG&E Corporation’s and the Utility’s combined Quarterly Report on Form 10-Q for the quarter ended March 31, 2014.

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 2013 Annual Report entitled “Risk Factors,” as supplemented below, and the section of this quarterly report entitled “Cautionary Language Regarding Forward-Looking Statements.”

PG&E Corporation’s and the Utility’s reputations have been significantly affected by the negative publicity about the federal criminal indictment of the Utility for alleged violations of the federal Pipeline Safety Act and for allegedly obstructing the NTSB’s investigation of the San Bruno accident. Their reputations could be further harmed by the eventual outcome of the pending CPUC investigations and if additional enforcement action is taken with respect to other natural gas operating practices or incidents. The outcome of these matters, including the amount of fines and penalties that may be imposed on the Utility and the ultimate amount of unrecoverable costs the Utility incurs in connection with its natural gas operations could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations and cash flows.

The reputations of PG&E Corporation and the Utility have suffered as a result of the extensive media coverage of the federal criminal prosecution of the Utility and allegations that the Utility improperly communicated with the CPUC regarding the substance of the pending CPUC investigations. (See “Natural Gas Matters” above.) Media coverage of future developments in the criminal prosecution and following the issuance of the decisions in the three pending CPUC investigations may cause further reputational harm. In addition, their reputations could suffer further depending on the outcome of the other matters relating to the Utility’s natural gas operations as discussed under “Natural Gas Matters – Other Enforcement Matters” above. While the CPUC investigations remain unresolved and as personnel changes occur at the CPUC, it can become increasingly difficult to estimate how these other matters will be addressed. If events or developments occur that further harm PG&E Corporation’s and the Utility’s reputations, the additional reputational harm could have a negative influence on how these other matters are addressed. Additional reputational harm also could negatively influence the regulatory decision-making process in the Utility’s ratemaking proceedings pending at the CPUC, such as the 2014 GRC and the GT&S rate case.

Continuing negative publicity and uncertainty about the outcome of the CPUC investigations and the criminal proceeding may cause investors to question management’s ability to repair the reputational harm that PG&E Corporation and the Utility have suffered, resulting in an adverse impact on the market price of PG&E Corporation common stock. The issuance of common stock by PG&E Corporation to fund the Utility’s unrecovered costs has materially diluted PG&E Corporation’s EPS. Additional share issuances following a declining stock price would cause further dilution.

In addition to the reputational harm associated with these matters, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially affected by the outcome of these matters. The final decisions to be issued in the CPUC investigations may order the Utility to pay fines that materially exceed the amount previously accrued. The ultimate amount of pipeline-related costs that the Utility incurs but does not recover through rates will be affected by the final decisions in the CPUC investigations, the outcome of pending ratemaking proceedings, the extent to which the scope and timing of planned pipeline work changes, and whether actual costs exceed forecasts. In addition, if the Utility is convicted of the criminal charges in the federal prosecution and the jury finds that the criminal conduct caused a pecuniary gain or loss, a material amount of fines could be imposed on the Utility. Although the maximum statutory fine for each of the 28 counts charged in the superseding indictment is $500,000 (for a total of $14 million), the U.S. Attorney is seeking an alternative fine based on the greater of twice the gross gain the Utility allegedly derived or twice the gross loss allegedly caused. The superseding indictment alleges that the Utility derived gross gains of approximately $281 million and caused gross losses of approximately $565 million. Based on these allegations, the maximum alternative fine would be approximately $1.13 billion.

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

During the quarter ended June 30, 2014, PG&E Corporation made equity contributions totaling $330 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, 2014.

Issuer Purchases of Equity Securities

During the quarter ended June 30, 2014, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the quarter ended June 30, 2014, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

ITEM 5. OTHER INFORMATION

Since May 1, 2014, PG&E Corporation has made equity contributions to the Utility totaling $370 million, including equity contributions of $125 million that were made on July 30, 2014.

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, 2014 was 2.24. The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the six months ended June 30, 2014 was 2.21. 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. 333-193879.

PG&E Corporation’s earnings to fixed charges ratio for the six months ended June 30, 2014 was 2.21. 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. 333-193880.

ITEM 6. EXHIBITS

4.1	Twenty-Second Supplemental Indenture, dated as of May 12, 2014, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due May 11, 2015 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 12, 2014 (File No. 12348), Exhibit 4.1)

*10.1	PG&E Corporation 2014 Long-Term Incentive Plan effective May 12, 2014 (incorporated by reference to PG&E Corporation’s Registration Statement on Form S-8, No. 333-195902, Exhibit 99)

*10.2	PG&E Corporation Officer Severance Policy, as amended effective as of May 12, 2014

*10.3	Form of Restricted Stock Unit Agreement for 2014 grants to directors under the PG&E Corporation 2014 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, 2014

EXHIBIT INDEX

4.1	Twenty-Second Supplemental Indenture, dated as of May 12, 2014, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due May 11, 2015 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 12, 2014 (File No. 12348), Exhibit 4.1)

*10.1	PG&E Corporation 2014 Long-Term Incentive Plan effective May 12, 2014 (incorporated by reference to PG&E Corporation’s Registration Statement on Form S-8, No. 333-195902, Exhibit 99)

*10.2	PG&E Corporation Officer Severance Policy, as amended effective as of May 12, 2014

*10.3	Form of Restricted Stock Unit Agreement for 2014 grants to directors under the PG&E Corporation 2014 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.