GLOSSARY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

NOTE 4: DEBT

NOTE 5: EQUITY

NOTE 6: EARNINGS PER SHARE

NOTE 7: DERIVATIVES

NOTE 8: FAIR VALUE MEASUREMENTS

NOTE 9: CONTINGENCIES AND COMMITMENTS

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

OVERVIEW

LIQUIDITY AND FINANCIAL RESOURCES

ENFORCEMENT AND LITIGATION MATTERS

RATEMAKING PROCEEDINGS

LEGISLATIVE AND REGULATORY INITIATIVES

ENVIRONMENTAL MATTERS

CONTRACTUAL COMMITMENTS

RISK MANAGEMENT ACTIVITIES

CRITICAL ACCOUNTING POLICIES

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4. CONTROLS AND PROCEDURES

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

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

ITEM 5. OTHER INFORMATION

ITEM 6. EXHIBITS

SIGNATURES

GLOSSARY

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

2014 Form 10-K	PG&E Corporation's and Pacific Gas and Electric Company's combined Annual Report on Form 10-K for the year ended December 31, 2014
AFUDC	allowance for funds used during construction
ASU	Accounting Standards Update issued by the FASB (see below)
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
DTSC	California Department of Toxic Substances Control
EPS	earnings per common share
EV	electric vehicle
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	U.S. Generally Accepted Accounting Principles
GRC	general rate case
GT&S	gas transmission and storage
IRS	Internal Revenue Service
NRC	Nuclear Regulatory Commission
NTSB	National Transportation Safety Board
ORA	Office of Ratepayer Advocates
PSEP	pipeline safety enhancement plan
Regional Board	California Regional Water Control Board, Lahontan Region
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
SB	State Senate Bill
TO	transmission owner
TURN	The Utility Reform Network
Utility	Pacific Gas and Electric Company
VIE(s)	variable interest entity(ies)

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in millions, except per share amounts)	2015		2014		2015		2014
Operating Revenues
Electric	$	3,868	$	4,012	$	10,344	$	10,246
Natural gas		682		927		2,322		2,536
Total operating revenues		4,550		4,939		12,666		12,782
Operating Expenses
Cost of electricity		1,681		1,782		3,958		4,341
Cost of natural gas		50		134		442		694
Operating and maintenance		1,621		1,287		5,028		3,914
Depreciation, amortization, and decommissioning		653		671		1,935		1,766
Total operating expenses		4,005		3,874		11,363		10,715
Operating Income		545		1,065		1,303		2,067
Interest income		2		2		6		7
Interest expense		(194)		(174)		(575)		(547)
Other income, net		24		36		100		98
Income Before Income Taxes		377		929		834		1,625
Income tax provision		67		115		84		310
Net Income		310		814		750		1,315
Preferred stock dividend requirement of subsidiary		3		3		10		10
Income Available for Common Shareholders	$	307	$	811	$	740	$	1,305
Weighted Average Common Shares Outstanding, Basic		486		472		481		466
Weighted Average Common Shares Outstanding, Diluted		489		474		484		468
Net Earnings Per Common Share, Basic	$	0.63	$	1.72	$	1.54	$	2.80
Net Earnings Per Common Share, Diluted	$	0.63	$	1.71	$	1.53	$	2.79
Dividends Declared Per Common Share	$	0.46	$	0.46	$	1.37	$	1.37

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in millions)	2015		2014		2015		2014
Net Income	$	310	$	814	$	750	$	1,315
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $0, $0, $0 and $0, at respective dates)		-		-		-		-
Net change in investments
(net of taxes of $0, $13, $12 and $16, at respective dates)		-		(18)		(17)		(24)
Total other comprehensive income (loss)		-		(18)		(17)		(24)
Comprehensive Income		310		796		733		1,291
Preferred stock dividend requirement of subsidiary		3		3		10		10
Comprehensive Income Attributable to
Common Shareholders	$	307	$	793	$	723	$	1,281

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Balance At
	September 30,		December 31,
(in millions)	2015		2014
ASSETS
Current Assets
Cash and cash equivalents	$	154	$	151
Restricted cash		287		298
Accounts receivable:
Customers (net of allowance for doubtful accounts of $57 and $66
at respective dates)		1,194		960
Accrued unbilled revenue		907		776
Regulatory balancing accounts		1,857		2,266
Other		303		377
Regulatory assets		475		444
Inventories:
Gas stored underground and fuel oil		149		172
Materials and supplies		322		304
Income taxes receivable		156		198
Other		327		443
Total current assets		6,131		6,389
Property, Plant, and Equipment
Electric		47,141		45,162
Gas		16,419		15,678
Construction work in progress		2,259		2,220
Other		2		2
Total property, plant, and equipment		65,821		63,062
Accumulated depreciation		(20,174)		(19,121)
Net property, plant, and equipment		45,647		43,941
Other Noncurrent Assets
Regulatory assets		6,584		6,322
Nuclear decommissioning trusts		2,417		2,421
Income taxes receivable		97		91
Other		1,113		963
Total other noncurrent assets		10,211		9,797
TOTAL ASSETS	$	61,989	$	60,127

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	September 30,		December 31,
(in millions, except share amounts)	2015		2014
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	881	$	633
Accounts payable:
Trade creditors		1,286		1,244
Regulatory balancing accounts		803		1,090
Other		435		476
Disputed claims and customer refunds		452		434
Interest payable		140		197
Other		2,111		1,846
Total current liabilities		6,108		5,920
Noncurrent Liabilities
Long-term debt		15,545		15,050
Regulatory liabilities		6,294		6,290
Pension and other postretirement benefits		2,523		2,561
Asset retirement obligations		3,620		3,575
Deferred income taxes		8,773		8,513
Other		2,306		2,218
Total noncurrent liabilities		39,061		38,207
Commitments and Contingencies (Note 9)
Equity
Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares;
490,177,833 and 475,913,404 shares outstanding at respective dates		11,183		10,421
Reinvested earnings		5,391		5,316
Accumulated other comprehensive income (loss)		(6)		11
Total shareholders' equity		16,568		15,748
Noncontrolling Interest - Preferred Stock of Subsidiary		252		252
Total equity		16,820		16,000
TOTAL LIABILITIES AND EQUITY	$	61,989	$	60,127

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Nine Months Ended September 30,
(in millions)	2015		2014
Cash Flows from Operating Activities
Net income	$	750	$	1,315
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		1,935		1,766
Allowance for equity funds used during construction		(80)		(72)
Deferred income taxes and tax credits, net		260		209
Disallowed capital expenditures		270		-
Other		247		258
Effect of changes in operating assets and liabilities:
Accounts receivable		(322)		(177)
Inventories		5		(43)
Accounts payable		95		(57)
Income taxes receivable/payable		42		397
Other current assets and liabilities		(87)		358
Regulatory assets, liabilities, and balancing accounts, net		78		(994)
Other noncurrent assets and liabilities		(251)		(3)
Net cash provided by operating activities		2,942		2,957
Cash Flows from Investing Activities
Capital expenditures		(3,662)		(3,564)
Decrease in restricted cash		11		2
Proceeds from sales and maturities of nuclear decommissioning
trust investments		1,023		1,059
Purchases of nuclear decommissioning trust investments		(1,124)		(1,065)
Other		18		107
Net cash used in investing activities		(3,734)		(3,461)
Cash Flows from Financing Activities
Repayments under revolving credit facilities		-		(260)
Net issuances (repayments) of commercial paper, net of discount of $2
and $1 at respective dates		545		(789)
Proceeds from issuance of short-term debt, net of issuance costs		-		300
Short-term debt matured		(300)		-
Proceeds from issuance of long-term debt, net of premium, discount,
and issuance costs of $14 and $6 at respective dates		486		1,819
Repayments of long-term debt		-		(889)
Common stock issued		689		743
Common stock dividends paid		(638)		(617)
Other		13		40
Net cash provided by financing activities		795		347
Net change in cash and cash equivalents		3		(157)
Cash and cash equivalents at January 1		151		296
Cash and cash equivalents at September 30	$	154	$	139

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(569)	$	(516)
Income taxes, net		-		409
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	223	$	216
Capital expenditures financed through accounts payable		245		232
Noncash common stock issuances		15		16
Terminated capital leases		-		71

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in millions)	2015		2014		2015		2014
Operating Revenues
Electric	$	3,868	$	4,012	$	10,344	$	10,244
Natural gas		682		927		2,322		2,536
Total operating revenues		4,550		4,939		12,666		12,780
Operating Expenses
Cost of electricity		1,681		1,782		3,958		4,341
Cost of natural gas		50		134		442		694
Operating and maintenance		1,622		1,293		5,028		3,911
Depreciation, amortization, and decommissioning		653		671		1,935		1,765
Total operating expenses		4,006		3,880		11,363		10,711
Operating Income		544		1,059		1,303		2,069
Interest income		2		1		6		6
Interest expense		(191)		(171)		(567)		(535)
Other income, net		22		19		68		56
Income Before Income Taxes		377		908		810		1,596
Income tax provision		72		115		95		325
Net Income		305		793		715		1,271
Preferred stock dividend requirement		3		3		10		10
Income Available for Common Stock	$	302	$	790	$	705	$	1,261

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

	(Unaudited)
	Three Months Ended					Nine Months Ended
	September 30,					September 30,
(in millions)	2015		2014			2015	2014
Net Income	$	305	$	793	$	715	$	1,271
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $0, $0, $0 and $0, at respective dates )		-		-		-		-
Total other comprehensive income (loss)		-		-		-		-
Comprehensive Income	$	305	$	793	$	715	$	1,271

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

	(Unaudited)
	Balance At
	September 30,		December 31,
(in millions)	2015		2014
ASSETS
Current Assets
Cash and cash equivalents	$	62	$	55
Restricted cash		287		298
Accounts receivable:
Customers (net of allowance for doubtful accounts of $57 and $66
at respective dates)		1,194		960
Accrued unbilled revenue		907		776
Regulatory balancing accounts		1,857		2,266
Other		300		375
Regulatory assets		475		444
Inventories:
Gas stored underground and fuel oil		149		172
Materials and supplies		322		304
Income taxes receivable		154		168
Other		327		409
Total current assets		6,034		6,227
Property, Plant, and Equipment
Electric		47,141		45,162
Gas		16,419		15,678
Construction work in progress		2,259		2,220
Total property, plant, and equipment		65,819		63,060
Accumulated depreciation		(20,173)		(19,120)
Net property, plant, and equipment		45,646		43,940
Other Noncurrent Assets
Regulatory assets		6,584		6,322
Nuclear decommissioning trusts		2,417		2,421
Income taxes receivable		97		91
Other		1,006		864
Total other noncurrent assets		10,104		9,698
TOTAL ASSETS	$	61,784	$	59,865

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	September 30,		December 31,
(in millions, except share amounts)	2015		2014
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	881	$	633
Accounts payable:
Trade creditors		1,286		1,243
Regulatory balancing accounts		803		1,090
Other		455		444
Disputed claims and customer refunds		452		434
Interest payable		139		195
Other		1,932		1,604
Total current liabilities		5,948		5,643
Noncurrent Liabilities
Long-term debt		15,195		14,700
Regulatory liabilities		6,294		6,290
Pension and other postretirement benefits		2,435		2,477
Asset retirement obligations		3,620		3,575
Deferred income taxes		9,018		8,773
Other		2,264		2,178
Total noncurrent liabilities		38,826		37,993
Commitments and Contingencies (Note 9)
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		7,127		6,514
Reinvested earnings		8,298		8,130
Accumulated other comprehensive income		5		5
Total shareholders' equity		17,010		16,229
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	61,784	$	59,865

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

	(Unaudited)
	Nine Months Ended September 30,
(in millions)	2015		2014
Cash Flows from Operating Activities
Net income	$	715	$	1,271
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		1,935		1,765
Allowance for equity funds used during construction		(80)		(72)
Deferred income taxes and tax credits, net		245		173
Disallowed capital expenditures		270		-
Other		200		212
Effect of changes in operating assets and liabilities:
Accounts receivable		(321)		(174)
Inventories		5		(43)
Accounts payable		148		(3)
Income taxes receivable/payable		14		407
Other current assets and liabilities		(45)		366
Regulatory assets, liabilities, and balancing accounts, net		78		(994)
Other noncurrent assets and liabilities		(232)		6
Net cash provided by operating activities		2,932		2,914
Cash Flows from Investing Activities
Capital expenditures		(3,662)		(3,564)
Decrease in restricted cash		11		2
Proceeds from sales and maturities of nuclear decommissioning
trust investments		1,023		1,059
Purchases of nuclear decommissioning trust investments		(1,124)		(1,065)
Other		18		22
Net cash used in investing activities		(3,734)		(3,546)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $2 and $1
at respective dates		545		(789)
Proceeds from issuance of short-term debt, net of issuance costs		-		300
Short-term debt matured		(300)		-
Proceeds from issuance of long-term debt, net of premium, discount,
and issuance costs of $14 and $3 at respective dates		486		1,472
Repayments of long-term debt		-		(539)
Preferred stock dividends paid		(10)		(10)
Common stock dividends paid		(537)		(537)
Equity contribution from PG&E Corporation		605		705
Other		20		50
Net cash provided by financing activities		809		652
Net change in cash and cash equivalents		7		20
Cash and cash equivalents at January 1		55		65
Cash and cash equivalents at September 30	$	62	$	85

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(561)	$	(500)
Income taxes, net		-		408
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	245	$	232
Terminated capital leases		-		71

See accompanying Notes to the Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

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.

On April 9, 2015, the CPUC approved final decisions in the three investigations that had been brought against the Utility relating to (1) the Utility’s safety record-keeping for its natural gas transmission system, (2) the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density, and (3) the Utility’s pipeline installation, integrity management, record-keeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010. A decision was issued in each investigative proceeding to determine the violations that the Utility committed. The CPUC also approved a fourth decision (the “Penalty Decision”) which imposes penalties on the Utility totaling $1.6 billion comprised of: (1) a $300 million fine paid to the State General Fund, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund future pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million. The Penalty Decision requires that at least $689 million of the $850 million be allocated to capital expenditures and that the Utility be precluded from including these capital costs in rate base. The remainder will be allocated to safety-related expenses. (See Note 9 below.)

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 other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility. 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, 2014 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in the 2014 Form 10-K. This quarterly report should be read in conjunction with the 2014 Form 10-K.

The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant 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 2014 Form 10-K.

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 September 30, 2015, 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 September 30, 2015, it did not consolidate any of them.

Pension and Other Postretirement Benefits

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below.

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2015 and 2014 were as follows:

	Pension Benefits				Other Benefits
	Three Months Ended September 30,
(in millions)	2015		2014		2015		2014
Service cost for benefits earned	$	123	$	92	$	14	$	12
Interest cost		168		175		18		19
Expected return on plan assets		(219)		(202)		(28)		(25)
Amortization of prior service cost		4		5		4		6
Amortization of net actuarial loss		1		1		1		1
Net periodic benefit cost		77		71		9		13
Regulatory account transfer (1)		8		13		-		-
Total	$	85	$	84	$	9	$	13

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

	Pension Benefits				Other Benefits
	Nine Months Ended September 30,
(in millions)	2015		2014		2015		2014
Service cost for benefits earned	$	360	$	287	$	41	$	34
Interest cost		505		521		54		57
Expected return on plan assets		(655)		(605)		(84)		(77)
Amortization of prior service cost		11		15		14		17
Amortization of net actuarial loss		7		2		3		2
Net periodic benefit cost		228		220		28		33
Regulatory account transfer (1)		26		31		-		-
Total	$	254	$	251	$	28	$	33

(1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, 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
	Benefits		Benefits		Total
(in millions, net of income tax)	Three Months Ended September 30, 2015
Beginning balance	$	(21)	$	15	$	(6)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost
(net of taxes of $1 and $2, respectively)		3		2		5
Amortization of net actuarial loss
(net of taxes of $0 and $0, respectively)		1		1		2
Regulatory account transfer
(net of taxes of $3 and $3, respectively)		(4)		(3)		(7)
Net current period other comprehensive loss		-		-		-
Ending balance	$	(21)	$	15	$	(6)

(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 September 30, 2014
Beginning balance	$	(7)	$	15	$	36	$	44
Other comprehensive income before reclassifications:
Change in investments
(net of taxes of $0, $0, and $3, respectively)		-		-		(4)		(4)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $2, $3, and $0, respectively) (1)		3		3		-		6
Regulatory account transfer
(net of taxes of $3, $4, and $0, respectively) (1)		(3)		(3)		-		(6)
Change in investments
(net of taxes of $0, $0, and $10, respectively)		-		-		(14)		(14)
Net current period other comprehensive loss		-		-		(18)		(18)
Ending balance	$	(7)	$	15	$	18	$	26

	Pension		Other		Other
	Benefits		Benefits		Investments		Total
(in millions, net of income tax)	Nine Months Ended September 30, 2015
Beginning balance	$	(21)	$	15	$	17	$	11
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $4, $6, and $0, respectively) (1)		7		8		-		15
Amortization of net actuarial loss
(net of taxes of $3, $1, and $0, respectively) (1)		4		2		-		6
Regulatory account transfer
(net of taxes of $7, $7, and $0, respectively) (1)		(11)		(10)		-		(21)
Change in investments
(net of taxes of $0, $0, and $12, respectively)		-		-		(17)		(17)
Net current period other comprehensive loss		-		-		(17)		(17)
Ending balance	$	(21)	$	15	$	-	$	(6)

	Pension		Other		Other
	Benefits		Benefits		Investments		Total
(in millions, net of income tax)	Nine Months Ended September 30, 2014
Beginning balance	$	(7)	$	15	$	42	$	50
Other comprehensive income before reclassifications:
Change in investments
(net of taxes of $0, $0, and $4, respectively)		-		-		6		6
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $6, $7, and $0, respectively) (1)		9		10		-		19
Amortization of net actuarial loss
(net of taxes of $1, $1, and $0, respectively) (1)		1		1		-		2
Regulatory account transfer
(net of taxes of $7, $8, and $0, respectively) (1)		(10)		(11)		-		(21)
Change in investments
(net of taxes of $0, $0, and $20, respectively)		-		-		(30)		(30)
Net current period other comprehensive loss		-		-		(24)		(24)
Ending balance	$	(7)	$	15	$	18	$	26

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

Fair Value Measurement

In May 2015, the FASB issued ASU No. 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which standardizes reporting practices related to the fair value hierarchy for all investments for which fair value is measured using the net asset value per share. The ASU will be effective for fiscal years beginning after December 15, 2015. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their disclosures and will adopt this standard starting in the first quarter of 2016.

Accounting for Fees Paid in a Cloud Computing Arrangement

In April 2015, the FASB issued ASU No. 2015-05, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement, which adds guidance to help entities evaluate the accounting treatment for cloud computing arrangements. The ASU will be effective on January 1, 2016. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their consolidated financial statements and related disclosures and will adopt this standard starting in the first quarter of 2016.

Presentation of Debt Issuance Costs

In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which amends existing presentation of debt issuance costs. PG&E Corporation and the Utility currently disclose debt issuance costs in current assets – other and noncurrent assets – other. The amendments in this ASU, effective on January 1, 2016, require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. PG&E Corporation and the Utility do not expect this reclassification to have a material impact on their consolidated financial statements. PG&E Corporation and the Utility will adopt this standard starting in the first quarter of 2016.

Revenue Recognition Standard

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which amends existing revenue recognition guidance. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date, deferring the effective date of this amendment for public companies by one year to January 1, 2018, with early adoption permitted as of the original effective date of 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
	September 30,		December 31,
(in millions)	2015		2014
Pension benefits	$	2,304	$	2,347
Deferred income taxes		2,771		2,390
Environmental compliance costs		705		717
Utility retained generation		423		456
Price risk management		143		127
Unamortized loss, net of gain, on reacquired debt		98		113
Electromechanical meters		18		70
Other		122		102
Total long-term regulatory assets	$	6,584	$	6,322

Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

	Balance at
	September 30,		December 31,
(in millions)	2015		2014
Cost of removal obligations	$	4,509	$	4,211
Recoveries in excess of asset retirement obligations		610		754
Public purpose programs		701		701
Other		474		624
Total long-term regulatory liabilities	$	6,294	$	6,290

Regulatory Balancing Accounts

The Utility’s recovery of revenue requirements and costs is generally decoupled from the volume of sales. The Utility tracks (1) differences between the Utility’s authorized revenue requirement and 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 expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Condensed Consolidated Balance Sheets. Balancing accounts 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
	September 30,		December 31,
(in millions)	2015		2014
Electric distribution	$	265	$	344
Utility generation		24		261
Gas distribution		718		566
Energy procurement		390		608
Public purpose programs		136		109
Other		324		378
Total regulatory balancing accounts receivable	$	1,857	$	2,266

	Payable
	Balance at
	September 30,		December 31,
(in millions)	2015		2014
Energy procurement	$	181	$	188
Public purpose programs		173		154
Other		449		748
Total regulatory balancing accounts payable	$	803	$	1,090

NOTE 4: DEBT

Revolving Credit Facilities and Commercial Paper Program

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at September 30, 2015:

					Letters of
	Termination	Facility			Credit		Commercial		Facility
(in millions)	Date	Limit			Outstanding		Paper		Availability
PG&E Corporation	April 2020	$	300	(1)	$	-	$	-	$	300
Utility	April 2020		3,000	(2)		34		881		2,085
Total revolving
credit facilities		$	3,300		$	34	$	881	$	2,385

(1)Includes a $50 million sublimit for letters of credit and a $100 million commitment for “swingline” loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days.

(2) Includes a $500 million sublimit for letters of credit and a $75 million commitment for swingline loans.

On April 27, 2015, PG&E Corporation and the Utility amended and restated their respective $300 million and $3.0 billion revolving credit facilities. The amendments and restatements extended the termination dates of the credit facilities from April 1, 2019 to April 27, 2020, reduced the amount of lender commitments to the letter of credit sublimits from $100 million to $50 million for PG&E Corporation’s credit facility and from $1.0 billion to $500 million for the Utility’s credit facility, and reduced the swingline commitment on the Utility’s credit facility from $300 million to $75 million.

In July 2015, the Utility increased the commercial paper program limit from $1.75 billion to $2.5 billion. PG&E Corporation and the Utility can issue commercial paper up to the maximum amounts of $300 million and $2.5 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.

Issuances and Maturities

In June 2015, the Utility issued $400 million principal amount of 3.50% Senior Notes due June 15, 2025 and $100 million of 4.30% Senior Notes due March 15, 2045. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper. In addition, $300 million principal amount of the Utility’s Floating Rate Senior Notes matured in May 2015.

Variable Rate Interest

At September 30, 2015, 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 were 0.01%. At September 30, 2015, the interest rates on the $309 million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements were 0.01%.

NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the nine months ended September 30, 2015were as follows:

	PG&E Corporation		Utility
	Total		Total
(in millions)	Equity		Shareholders' Equity
Balance at December 31, 2014	$	16,000	$	16,229
Comprehensive income		733		715
Equity contributions		-		605
Common stock issued		704		-
Share-based compensation		58		8
Common stock dividends declared		(665)		(537)
Preferred stock dividend requirement		-		(10)
Preferred stock dividend requirement of subsidiary		(10)		-
Balance at September 30, 2015	$	16,820	$	17,010

In February 2015, 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. In the first quarter of 2015, PG&E Corporation sold 1.4 million shares under this agreement for cash proceeds of $74 million, net of commissions paid of $1 million. No additional shares have been sold under the equity distribution agreement.

In August 2015, PG&E Corporation sold 6.8 million shares of its common stock in an underwritten public offeringfor cash proceeds of $352 million, net of fees.

PG&E Corporation also issued common stock under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans. During the nine months ended September 30, 2015, 6.1 million shares were issued for cash proceeds of $263 million under these plans.

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				Nine Months Ended
	September 30,				September 30,
(in millions, except per share amounts)	2015		2014		2015		2014
Income available for common shareholders	$	307	$	811	$	740	$	1,305
Weighted average common shares outstanding, basic		486		472		481		466
Add incremental shares from assumed conversions:
Employee share-based compensation		3		2		3		2
Weighted average common share outstanding, diluted		489		474		484		468
Total earnings per common share, diluted	$	0.63	$	1.71	$	1.53	$	2.79

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

Use of Derivative Instruments

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include forward contracts, swaps, futures, options, and CRRs.

Derivatives are presented in the Utility’s Condensed Consolidated Balance Sheets on a net basis in accordance with master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist.

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. 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 on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.

The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those 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. These items are not reflected in the Condensed Consolidated Balance Sheets at fair value. Eligible derivatives are accounted for under the accrual method of accounting.

Volume of Derivative Activity

The volumes of the Utility’s outstanding derivatives were as follows:

		Contract Volume at
		September 30,	December 31,
Underlying Product	Instruments	2015	2014
Natural Gas (1) (MMBtus (2))	Forwards and Swaps	276,847,153	308,130,101
	Options	134,380,439	164,418,002
Electricity (Megawatt-hours)	Forwards and Swaps	4,884,523	5,346,787
	Congestion Revenue Rights (3)	186,018,832	224,124,341

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

(2) Million British Thermal Units.

(3)CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

Presentation of Derivative Instruments in the Financial Statements

At September 30, 2015, 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	$	63	$	(2)	$	11	$	72
Other noncurrent assets – other		130		(2)		-		128
Current liabilities – other		(84)		2		34		(48)
Noncurrent liabilities – other		(145)		2		24		(119)
Net commodity risk	$	(36)	$	-	$	69	$	33

At December 31, 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	$	73		(4)		19	$	88
Other noncurrent assets – other		178		(13)		-		165
Current liabilities – other		(78)		4		26		(48)
Noncurrent liabilities – other		(140)		13		9		(118)
Net commodity risk	$	33	$	-	$	54	$	87

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

	Commodity Risk
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in millions)	2015		2014		2015		2014
Unrealized gain (loss) - regulatory assets and liabilities (1)	$	(45)	$	(6)	$	(69)	$	79
Realized gain (loss) - cost of electricity (2)		1		(22)		4		(48)
Realized loss - cost of natural gas (2)		(3)		(4)		(8)		(7)
Net commodity risk	$	(47)	$	(32)	$	(73)	$	24

(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.

Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Condensed Consolidated Statements of Cash Flows.

The majority of the Utility’s derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. At September 30, 2015, 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
	September 30,		December 31,
(in millions)	2015		2014
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(2)	$	(47)
Collateral posting in the normal course of business related to these derivatives		-		44
Net position of derivative contracts/additional collateral
posting requirements (1)	$	(2)	$	(3)

(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 September 30, 2015
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments	$	92	$	-	$	-	$	-	$	92
Nuclear decommissioning trusts
Money market investments		21		-		-		-		21
Global equity securities		1,445		12		-		-		1,457
Fixed-income securities		710		523		-		-		1,233
Total nuclear decommissioning trusts (2)		2,176		535		-		-		2,711
Price risk management instruments
(Note 7)
Electricity		-		4		185		7		196
Gas		-		4		-		-		4
Total price risk management
instruments		-		8		185		7		200
Rabbi trusts
Fixed-income securities		-		45		-		-		45
Life insurance contracts		-		71		-		-		71
Total rabbi trusts		-		116		-		-		116
Long-term disability trust
Money market investments		7		-		-		-		7
Global equity securities		-		18		-		-		18
Fixed-income securities		-		106		-		-		106
Total long-term disability trust		7		124		-		-		131
Total assets	$	2,275	$	783	$	185	$	7	$	3,250
Liabilities:
Price risk management instruments
(Note 7)
Electricity	$	60	$	3	$	164	$	(62)	$	165
Gas		-		2		-		-		2
Total liabilities	$	60	$	5	$	164	$	(62)	$	167

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

(2) Represents amount before deducting $294 million, primarily related to deferred taxes on appreciation of investment value.

	Fair Value Measurements
	At December 31, 2014
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments	$	94	$	-	$	-	$	-	$	94
Nuclear decommissioning trusts
Money market investments		17		-		-		-		17
Global equity securities		1,585		13		-		-		1,598
Fixed-income securities		741		389		-		-		1,130
Total nuclear decommissioning trusts (2)		2,343		402		-		-		2,745
Price risk management instruments
(Note 9 in the 2014 Form 10-K)
Electricity		-		17		232		2		251
Gas		1		1		-		-		2
Total price risk management
instruments		1		18		232		2		253
Rabbi trusts
Fixed-income securities		-		42		-		-		42
Life insurance contracts		-		72		-		-		72
Total rabbi trusts		-		114		-		-		114
Long-term disability trust
Money market investments		7		-		-		-		7
Global equity securities		-		25		-		-		25
Fixed-income securities		-		128		-		-		128
Total long-term disability trust		7		153		-		-		160
Other investments		33		-		-		-		33
Total assets	$	2,478	$	687	$	232	$	2	$	3,399
Liabilities:
Price risk management instruments
(Note 9 in the 2014 Form 10-K)
Electricity	$	47	$	5	$	163	$	(52)	$	163
Gas		-		3		-		-		3
Total liabilities	$	47	$	8	$	163	$	(52)	$	166

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

(2) Represents amount before deducting $324 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. 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 nine months ended September 30, 2015 and 2014.

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 California Independent System Operator-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 California Independent System Operator 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.

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)	At September 30, 2015				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	185	$	51	Market approach	CRR auction prices	$	(15.97) - 8.17
Power purchase agreements	$	-	$	113	Discounted cash flow	Forward prices	$	17.64 - 38.80

(1) Represents price per megawatt-hour

	Fair Value at
(in millions)	At December 31, 2014				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	232	$	63	Market approach	CRR auction prices	$	(15.97) - 8.17
Power purchase agreements	$	-	$	100	Discounted cash flow	Forward prices	$	16.04 - 56.21

(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 nine months ended September 30, 2015 and 2014:

	Price Risk Management Instruments
(in millions)	2015		2014
Asset (liability) balance as of July 1	$	48	$	(11)
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		(27)		(9)
Asset (liability) balance as of September 30	$	21	$	(20)

(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)	2015		2014
Asset (liability) balance as of January 1	$	69	$	(30)
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		(48)		10
Asset (liability) balance as of September 30	$	21	$	(20)

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, floating rate senior notes, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at September 30, 2015 and December 31, 2014, 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 September 30, 2015 and December 31, 2014.

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 September 30, 2015				At December 31, 2014
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
PG&E Corporation	$	350	$	354	$	350	$	352
Utility		14,273		15,858		13,778		15,851

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 September 30, 2015
Nuclear decommissioning trusts
Money market investments	$	21	$	-	$	-	$	21
Global equity securities		510		963		(16)		1,457
Fixed-income securities		1,168		70		(5)		1,233
Total (1)	$	1,699	$	1,033	$	(21)	$	2,711
As of December 31, 2014
Nuclear decommissioning trusts
Money market investments	$	17	$	-	$	-	$	17
Global equity securities		520		1,087		(9)		1,598
Fixed-income securities		1,059		75		(4)		1,130
Total nuclear decommissioning trusts (1)		1,596		1,162		(13)		2,745
Other investments		5		28		-		33
Total	$	1,601	$	1,190	$	(13)	$	2,778

(1) Represents amounts before deducting $294 million and $324 million at September 30, 2015 and December 31, 2014, 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)	September 30, 2015
Less than 1 year	$	21
1–5 years		465
5–10 years		290
More than 10 years		457
Total maturities of debt securities	$	1,233

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014			2015	2014
(in millions)
Proceeds from sales and maturities of nuclear decommissioning
trust investments	$	244	$	182	$	1,023	$	1,059
Gross realized gains on securities held as available-for-sale		3		30		50		114
Gross realized losses on securities held as available-for-sale		(12)		-		(25)		(3)

NOTE 9: CONTINGENCIES AND COMMITMENTS

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

Enforcement and Litigation Matters

CPUC Matters

Improper CPUC Communications

In September 2014, the Utility notified the CPUC of ex parte communications between the Utility and the CPUC regarding the 2015 GT&S rate case. Ex parte communications include any communication between a decision maker and an interested person concerning substantive issues in certain identified categories of formal proceedings before the CPUC. In November 2014, the CPUC imposed a fine of $1.05 million on the Utility for these communications. In addition, the CPUC may disallow the Utility from recovering up to the entire amount of the revenue increase that may be authorized in the pending GT&S rate case and that otherwise would have been collected from ratepayers over a five-month period. The CPUC will determine the amount of this disallowance when it issues its decision to authorize the Utility’s GT&S revenue requirements, which is expected to be issued in 2016.

In October and December 2014, the Utility also notified the CPUC of additional email communications between the Utility and the CPUC regarding various matters (not limited to the GT&S rate case) that the Utility believes may constitute or describe ex parte communications. The Utility also notified the CPUC of an additional potential ex parte communication made in the 2011 General Rate Case to supplement a notification that the Utility voluntarily provided on October 6, 2014. Additionally, on May 21, 2015, the Utility filed various documents (including copies of internal email correspondence) with the CPUC to complete its response to orders issued by CPUC administrative law judges regarding potential ex parte communications between the Utility and CPUC personnel. For these additional communications, the Utility believes it is probable that CPUC enforcement action will be taken. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion and the number of factors that can be considered in determining the final penalties.

In the Penalty Decision (further described below), the CPUC stated that it will begin a new investigation to examine allegations by the City of San Bruno that communications between the Utility’s employees and CPUC personnel violated the CPUC’s rules relating to ex parte communications. The Utility believes that the communications cited by San Bruno are not prohibited ex parte communications. If the CPUC determines that the communications constitute ex parte violations, it is reasonably possible that the CPUC will impose penalties or other remedies, but the Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion and the number of factors that can be considered in determining the final penalties.

The U.S. Attorney’s Office in San Francisco and the California Attorney General’s office have also begun investigations in connection with the ex parte communications. The Utility is cooperating with the federal and state investigators. It is uncertain whether any charges will be brought against the Utility.

CPUC Investigation Regarding Natural Gas Distribution Facilities Record-Keeping

On November 20, 2014, the CPUC began an investigation into whether the Utility violated applicable laws pertaining to record-keeping practices with respect to maintaining safe operation of its natural gas distribution service and facilities. The order also requires the Utility to show cause why (1) the CPUC should not find that the Utility violated provisions of the California Public Utilities Code, CPUC general orders or decisions, other rules, or requirements, and/or engaged in unreasonable and/or imprudent practices related to these matters, and (2) the CPUC should not impose penalties, and/or any other forms of relief, if any violations are found. In particular, the order cites the SED’s investigative reports alleging that the Utility violated rules regarding safety record-keeping in connection with six natural gas distribution incidents, including the natural gas explosion that occurred in Carmel, California on March 3, 2014, for which the CPUC has previously imposed a penalty of $10.85 million.

On September 30, 2015, the SED submitted its supplemental testimony, which included incidents allegedly related to record-keeping that had not been identified in the initial order, and also asserted violations related to the Utility’s pre-excavation location and marking practices, causal evaluation practices, and compliance with regulations governing pressure validation for certain distribution facilities. Testimony from intervenors was submitted in October 2015. The Utility’s response is due on November 12, 2015, followed by rebuttal testimony in December 2015. Hearings are scheduled for January 2016.

The CPUC can impose penalties of up to $50,000 per day, per violation, for violations that occurred after January 1, 2012. (The statutory maximum penalty for violations that occurred before January 1, 2012 is $20,000 per violation.) The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The CPUC is also required to consider the appropriateness of the amount of the penalty to the size of the entity charged. The CPUC has historically exercised this wide discretion in determining penalties.

PG&E Corporation and the Utility believe it is reasonably possible that the CPUC will impose penalties on the Utility or that the Utility will incur unrecoverable costs to implement operational remedies. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion (discussed above) and the number of factors that can be considered in determining penalties and given the fact that the extent of any alleged violations is currently unknown.

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 address a self-reported violation whereby the Utility did not properly 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. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the SED’s wide discretion and the number of factors that can be considered in determining penalties.

Potential Safety Citations

The SED periodically audits utility operating practices and conducts investigations of potential violations of laws and regulations applicable to the safety of the California utilities’ electric and natural gas facilities and operations. The CPUC has delegated authority to the SED to issue citations and impose fines for violations identified through audits, investigations, or self-reports. Although the SED can consider the discretionary factors discussed above (see “CPUC Investigation Regarding Natural Gas Distribution Facilities Record-Keeping” above) in determining the number of violations and whether to impose fines, the SED is required to impose the maximum statutory penalty of $50,000 for each separate violation and has the discretion to impose daily fines for continuing violations.

The SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of electric and natural gas laws and regulations. The Utility believes it is probable that the SED will impose fines or take other enforcement action based on some of the Utility’s self-reported non-compliance with laws and regulations or based on allegations of non-compliance with such laws and regulations that are contained in some of the SED’s audits. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred for fines imposed by the SED with respect to these matters given the wide discretion the SED has in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines.

Federal Matters

Federal Criminal Indictment

On July 29, 2014, a federal grand jury for the Northern District of California returned a 28-count superseding criminal indictment against the Utility in federal district court that succeeded the original indictment that was returned on April 1, 2014. The superseding indictment charges 27 felony counts alleging 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 illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident. The maximum statutory fine for each felony count is $500,000, for total fines of $14 million. The superseding indictment also seeks an 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.” Based on the superseding indictment’s allegations that the Utility derived gross gains of approximately $281 million and that the victims suffered losses of approximately $565 million, the maximum alternative fine would be approximately $1.13 billion. The trial is scheduled to begin March 8, 2016.

The Utility entered a plea of not guilty. The Utility believes that criminal charges and the alternative fine allegations 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. The Utility has filed several motions requesting that the court dismiss many of the counts based on various legal arguments. The court has heard oral argument on all the motions and the Utility is waiting for the court’s decisions. 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 considered to be probable.

Other Federal Matters

The Utility was informed that the U.S. Attorney’s Office was investigating a natural gas explosion that occurred in Carmel, California on March 3, 2014. (For more information refer to Note 14 of the Notes to the Consolidated Financial Statements appearing under Item 8 in the 2014 Form 10-K). The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the indicted case discussed above. It is uncertain whether any additional charges will be brought against the Utility.

Capital Expenditures Relating to Pipeline Safety Enhancement Plan

At September 30, 2015, approximately $657 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 to the statement of income in future periods to the extent total forecasted PSEP-related capital costs are higher than currently expected.

Penalty Decision Related to the CPUC’s Investigative Enforcement Proceedings Related to Natural Gas Transmission

The Penalty Decision (see Note 1 above) imposes penalties on the Utility totaling $1.6 billion comprised of: (1) a $300 million fine to be paid to the State General Fund, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund future pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million. In August 2015, the Utility paid the $300 million fine. At September 30, 2015, the Condensed Consolidated Balance Sheets include $400 million in current regulatory liabilities for the one-time bill credit that will be provided to the Utility’s natural gas customers in 2016.

The Penalty Decision requires that at least $689 million of the $850 million disallowance be allocated to capital expenditures, and that the Utility be precluded from including these capital costs in rate base. The CPUC will determine which safety projects and programs will be funded by shareholders in the Utility’s pending 2015 GT&S rate case. If the $850 million is not exhausted by designated safety-related projects and programs in the GT&S proceeding, the CPUC will identify additional projects in future proceedings to ensure that the full $850 million is spent. The CPUC is expected to issue a final decision in the Utility’s 2015 GT&S rate case in 2016 to identify safety-related projects and programs that will be subject to the disallowance. It is uncertain how the CPUC will identify the costs that are counted toward the $850 million shareholder-funded obligation. If the Utility’s actual costs exceed costs that the CPUC counts towards the $850 million maximum, the Utility would record additional charges if such costs are not otherwise authorized by the CPUC. As a result, the total shareholder-funded obligation could exceed $850 million.

For the three months and nine months ended September 30, 2015, the Utility recorded additional charges in operating and maintenance expenses in the Consolidated Statements of Income of $142 million and $770 million, respectively, as a result of the Penalty Decision. The cumulative charges at September 30, 2015, and the additional future charges to reach the $1.6 billion total are shown in the following table:


	Nine Months		Cumulative		Future
	Ended		Charges		Charges		Total
		September 30,		September 30,	and
(in millions)	2015		2015		Costs		Amount
Fine payable to the state (1)	$	100	$	300	$	-	$	300
Customer bill credit		400		400		-		400
Charge for disallowed capital (2)		270		270		419		689
Disallowed revenue for pipeline safety
expenses (3)		-		-		161		161
CPUC estimated cost of other remedies (4)		-		20		30		50
Total Penalty Decision fines and remedies	$	770	$	990	$	610	$	1,600

(1)In March 2015, the Utility increased its accrual from $200 million at December 31, 2014 to $300 million.

(2)The Penalty Decision prohibits the Utility from recovering certain expenses and capital spending associated with pipeline safety-related projects and programs that the CPUC will identify in the final decision to be issued in the Utility’s 2015 GT&S rate case. The Utility estimates that approximately $142 million and $270 million of capital spending (which include less than $1 million for remedy related capital costs)in the three months and nine months ended September 30, 2015, respectively, are probable of disallowance, subject to adjustment based on the final 2015 GT&S rate case decision.

(3)These costs are being expensed as incurred. Future GT&S revenues will be reduced for these unrecovered expenses.

(4)In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision, including approximately $30 million for the cost of future audits to be conducted by the SED. The amounts shown in the table above represent these estimated amounts and do not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. The Utility has submitted testimony in its 2017 GRC request to remove additionalremedy-related costs of approximately $61 million. The Utility could incur remedy-related costs that are higher than current estimates.

Other Legal and Regulatory Contingencies

Rehearing of CPUC Decisions Approving Energy Efficiency Incentive Awards

On September 17, 2015, the CPUC issued an order granting TURN’s and the ORA’s long-standing applications for rehearing of the CPUC decisions that awarded energy efficiency incentive payments to the California investor-owned utilities for the 2006-2008 energy efficiency program cycle. Under the ratemaking mechanism applicable to the 2006-2008 program cycle, the maximum amount of incentives that the Utility could have earned (or the maximum amount that the Utility could have been required to reimburse customers) over the 2006-2008 program cycle was $180 million. The Utility was awarded a total of $104 million for the 2006-2008 program cycle. In the re-opened energy efficiency proceeding, the CPUC will evaluate whether incentives awarded to the California investor-owned utilities were just and reasonable, and whether any refunds are due. It is uncertain when the CPUC will issue a decision and whether the Utility will be required to refund amounts or incur other obligations related to the 2006-2008 program cycle. PG&E Corporation and the Utility believe it is reasonably possible that the Utility will be required to refund amounts or incur other obligations related to this matter, but they are unable to reasonably estimate the amount of such refunds or other obligations.

Investigation of the Butte Fire

In September 2015, a wildfire (known as the “Butte Fire”) ignited and spread in Amador and Calaveras Counties in Northern California. The California Department of Forestry and Fire Protection (“Cal Fire”) is investigating the source of the fire including whether a live tree may have contacted apower line owned and operated by the Utility, in the vicinity of the ignition point. The Utility also is conducting an investigation. Cal Fire has reported that as a result of the fire there were two deaths and 965 structures, including 571 houses, were damaged or destroyed.

Although the cause of the fire has not yet been determined, PG&E Corporation and the Utility believe that it is reasonably possible that the Utility will incur a material amount of losses associated with third-party claims for property damage, fire suppression costs, personal injury, or other claims. PG&E Corporation and the Utility are unable to reasonably estimate the amount of possible losses (or range of amounts) given the preliminary stages of the investigation into the cause of the fire and uncertainty about the extent and value of real and personal property damaged by the fire which spread over 70,000 acres much of which is remote and rugged terrain. The Utility has insurance coverage for these types of claims. If the amount of insurance is insufficient to cover the Utility's liability resulting from the Butte fire, or if insurance is otherwise unavailable, PG&E Corporation’s and the Utility’s financial condition or results of operations could be materially affected.

Other Contingencies

Accruals for other legal and regulatory contingencies (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters” and “Other Legal and Regulatory Contingencies”) totaled $61 million at September 30, 2015, and $55 million at December 31, 2014. 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
	September 30,		December 31,
(in millions)	2015		2014
Topock natural gas compressor station (1)	$	296	$	291
Hinkley natural gas compressor station (1)		136		158
Former manufactured gas plant sites owned by the Utility or third parties		267		257
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites		153		150
Fossil fuel-fired generation facilities and sites		94		98
Total environmental remediation liability	$	946	$	954

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

At September 30, 2015, the Utility expected to recover $678 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC. Some of the Utility’s environmental remediation liability, such as the environmental remediation costs associated with the Hinkley site discussed below, will not be recovered in rates.

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 also is required to take measures to abate the effects of the contamination on the environment.

Hinkley Site

The Utility has been implementing interim remediation measures at the Hinkley site to reduce the mass of the chromium plume and to monitor and control movement of the plume. The Utility's remediation and abatement efforts at the Hinkley site are overseen by the Regional Board. On October 16, 2015, the Regional Board issued a revised draft clean-up and abatement order, updating previous versions of the draft order released in September 2015 and January 2015. The updated draft order proposes that the Utility continue and improve its remediation efforts; defines the boundaries of the chromium plume, and take other action. The draft order also proposes to set plume capture requirements, proposes deadlines for the Utility to meet interim cleanup targets, and proposes to establish a monitoring and reporting program. After a public comment period, the Regional Board is expected to consider adoption of a final clean-up and abatement order at its November 2015 meeting.

The Utility’s environmental remediation liability at September 30, 2015 reflects the Utility’s best estimate of probable future costs associated with the continuation of interim remediation measures and the anticipated final clean-up and abatement order. 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 overseen by the DTSC and the U.S. Department of the Interior. While the Utility has been working with these agencies to develop a final remediation plan, the Utility has been employing various 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. In September 2014, the Utility submitted its near-final remediation plan to the agencies for approval. The Utility’s plan proposes that the Utility construct an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. The DTSC is conducting an additional environmental review of the proposed plan, and the Utility anticipates that the DTSC’s draft environmental impact report will be issued for public comment in July 2016. After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in December 2016. After the Utility modifies its plan in response to the final report, the Utility plans to seek approval to begin construction of the new in-situ treatment system in early 2017.

The Utility's environmental remediation liability at September 30, 2015 reflects its best estimate of probable future costs associated with its anticipated final remediation plan. Future costs will depend on many factors, including the scope and timing of required remediation work. 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 $1.8 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.

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. The Utility has 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.

At December 31, 2014, the Consolidated Balance Sheets reflected $434 million in net claims, within Disputed claims and customer refunds, and $291 million of cash in escrow for payment of the remaining net disputed claims, within Restricted cash. There were no significant changes to these balances during the nine months ended September 30, 2015.

Tax Matters

The IRS is currently auditing several items in the 2011 to 2014 tax returns. The most significant relates to a 2011 accounting method change to adopt guidance issued by the IRS in determining which repair costs are deductible for the electric transmission and distribution businesses. PG&E Corporation and the Utility expect that the IRS will complete its audit of the 2011 and 2012 deductible repair costs for the electric transmission and distribution businesses in 2015. The IRS also is expected to issue guidance in late 2015 or 2016 that clarifies which repair costs are deductible for the natural gas transmission and distribution businesses. PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months depending on the IRS guidance that is issued and the resolution of the outstanding audits related to the 2011 and 2012 tax returns. As of September 30, 2015, it is reasonably possible that unrecognized tax benefits will decrease by approximately $380 million within the next 12 months most of which would not impact net income.

There were no other significant developments to tax matters during the nine months ended September 30,2015. (Refer to Note 8 of the Notes to the Consolidated Financial Statements in Item 8 of the 2014 Form 10-K.)

Purchase 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. At December 31, 2014 the Utility hadundiscounted future expected obligations of approximately $53.3 billion. (See Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2014 Form 10-K.) During the nine months ended September 30, 2015, the Utility entered into several renewable energy and other power purchase agreements that were approved by the CPUC and completed major milestones with respect to construction, resulting in additional commitments of approximately $780 million over the next 25 years.

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

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 2014 Form 10-K.

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 (as well as earnings from operations and EPS on an earnings from operations basis) compared to the same period in the prior year (see “Results of Operations” below). “Earnings from operations” is a non-GAAP financial measure and is calculated as income available for common shareholders less items impacting comparability. “Items impacting comparability” represent items that management does not consider part of the normal course of operations and affect comparability of financial results between periods. PG&E Corporation uses earnings from operations to understand and compare operating results across reporting periods for various purposes including internal budgeting and forecasting, short- and long-term operating plans, and employee incentive compensation. PG&E Corporation believes that earnings from operations provide additional insight into the underlying trends of the business allowing for a better comparison against historical results and expectations for future performance. Earnings from operations are not a substitute or alternative for GAAP measures such as income available for common shareholders and may not be comparable to similarly titled measures used by other companies.

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
			EPS				EPS
(in millions, except per share amounts)	Earnings		(Diluted)		Earnings		(Diluted)
Income Available for Common Shareholders - 2014	$	811	$	1.71	$	1,305	$	2.79
Natural gas matters (1)		13		0.03		94		0.20
Environmental-related costs (2)		(4)		(0.01)		(4)		(0.01)
Earnings from Operations - 2014 (3)	$	820	$	1.73	$	1,395	$	2.98
Growth in rate base earnings		26		0.05		79		0.16
Nuclear refueling outage		-		-		26		0.05
2014 GRC cost recovery (4)		(228)		(0.47)		-		-
Timing of 2015 GT&S cost recovery (5)		(78)		(0.16)		(159)		(0.33)
Regulatory and legal matters (6)		(24)		(0.05)		(18)		(0.04)
Gain on disposition of SolarCity stock (7)		(14)		(0.03)		(13)		(0.03)
Timing of taxes (8)		(45)		(0.09)		(7)		(0.01)
Increase in shares outstanding		-		(0.05)		-		(0.10)
Miscellaneous		(45)		(0.09)		(31)		(0.05)
Earnings from Operations - 2015 (3)	$	412	$	0.84	$	1,272	$	2.63
Insurance recoveries (9)		6		0.01		29		0.06
Fines and penalties (10)		(84)		(0.16)		(497)		(1.03)
Pipeline-related expenses (11)		(19)		(0.04)		(38)		(0.08)
Legal and regulatory related expenses (11)		(8)		(0.02)		(26)		(0.05)
Income Available for Common Shareholders - 2015	$	307	$	0.63	$	740	$	1.53

(1) In 2014, natural gas matters included pipeline-related costs to perform work under the PSEP and other activities associated with safety improvements to the Utility’s natural gas system, as well as legal and other costs related to natural gas matters. Natural gas matters also included charges recorded related to fines, third party liability claims, and insurance recoveries in 2014.

(2) The Utility reduced its accrual related to the Hinkley whole house water program in the third quarter of 2014.

(3) “Earnings from operations” is not calculated in accordance with GAAP and excludes the items impacting comparability shown in Notes (1) and (2) above and Notes (9), (10), and (11) below.

(4)Represents the increase in base revenues authorized by the CPUC in the 2014 GRC decision, as well as the impact of flow-through ratemaking treatment for federal tax deductions for repairs, for the first two quarters of 2014. In 2014, the increase in base revenue and the impact of flow-through repairs deductions was not recognized until the quarter ended September 30, 2014, when the 2014 GRC decision was issued. Alsoincludes 2014 GRC related items included in Miscellaneous in previous quarters.

(5)Represents expenses during the three and nine months ended September 30, 2015 as compared to the same periods in 2014, with no corresponding increase in revenue. The Utility has requested the CPUC to authorize an increase to its revenue requirements for 2015, 2016, and 2017 in its 2015 GT&S rate case. Based on the procedural schedule, it is unlikely that the Utility will be able to recognize a revenue increase from a final 2015 GT&S rate case decision until 2016.

(6)Primarily reflects incentive awards received in 2014. Also includes legal costs included in Miscellaneous in previous quarters.

(7)Represents the gain recognized during the three months ended September 30, 2014 as compared to the three months ended September 30, 2015 during which no comparable gain was recognized.

(8)Represents the timing of taxes reportable in quarterly financial statements.

(9)Represents insurance recoveries of $10 million and $49 million, pre-tax, for third party claims and associated legal costs related to the San Bruno accident the Utility received during the three and nine months ended September 30, 2015, respectively. The Utility has received a cumulative total of $515 million through insurance related to $558 million of third-party claims and $92 million of legal costs incurred. No further insurance recoveries related to these claims and costs are expected.

(10)Represents the impact of the Penalty Decision (see Note 9 of the Notes to the Condensed Consolidated Financial Statements for before-tax amounts).

(11) In 2015, pipeline-related expenses include costs incurred to identify and remove encroachments from transmission pipeline rights of way and to perform remaining work under the Utility’s PSEP. Legal and regulatory related expenses include various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.

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:

•	Penalties, Fines and Remedial Costs. Future financial results will be impacted by the timing and amount of disallowed costs the Utility incurs for designated pipeline safety-related projects and programs and to implement remedial measures, as required by the Penalty Decision. The Utility also could be required to pay fines associated with pending federal criminal charges. Based on the superseding indictment’s allegations, the maximum statutory fine would be $14 million and the maximum alternative fine would be approximately $1.13 billion. The Utility also could be required to pay fines, or incur other unrecoverable costs, associated with the CPUC’s pending investigation of the Utility’s natural gas distribution record-keeping practices, enforcement action that may be taken with respect to ex parte communications or other improper communications between the Utility and the CPUC, or other enforcement matters. (See “Enforcement and Litigation Matters” in Note 9 of the Notes to the Condensed Consolidated Financial Statements.)

•	The Timing and Outcome of Ratemaking Proceedings. In the 2015 GT&S rate case, the Utility has requested that the CPUC authorize an increase in the Utility’s revenue requirements for gas transmission and storage operations beginning on January 1, 2015, with additional increases in 2016 and 2017. Any revenue requirement increase would be retroactive to January 1, 2015. Based on the scoping ruling and procedural schedule that was issued on June 11, 2015, the CPUC’s initial decision to authorize revenue requirements is not likely to be issued before December 31, 2015. If the Utility does not recognize any increase in 2015, the authorized revenue increase would be recorded in 2016. (See “Ratemaking Proceedings−2015 Gas Transmission and Storage Rate Case” below for more information.) In September 2015, the Utility filed its 2017 GRC application to request that the CPUC authorize revenue requirements for the Utility’s electric generation business and its electric and natural gas distribution business for 2017 through 2019. (See “Ratemaking Proceedings−2017 General Rate Case” below for more information.) Also, the CPUC recently granted applications for rehearing of CPUC decisions issued in 2008, 2009, and 2010 that awarded a total of $104 million of incentive revenues to the Utility based on implementation of customer energy efficiency programs. It is uncertain whether the Utility would be required to refund any of the incentive revenues or incur other expense related to the final resolution of the re-opened proceedings. In addition, the Utility has one transmission owner rate case pending at the FERC (See “Ratemaking Proceedings – FERC TO Rate Cases” below). The outcome of ratemaking proceedings can be affected by many factors, including the level of opposition by intervening parties, potential rate impacts, the Utility’s reputation, the regulatory and political environments, and other factors.

•	The Ability of the Utility to Control Operating Costs and Capital Expenditures. Whether the Utility is able to earn its authorized rate of return could be materially affected if the Utility’s actual costs differ from the amounts that have been authorized in the final 2014 GRC decision and that may be authorized in the 2015 GT&S rate case and future rate case decisions. In addition to incurring shareholder-funded costs and costs associated with remedial measures required by the Penalty Decision, the Utility forecasts that in 2015 it will incur unrecovered pipeline-related expenses ranging from $100 million to $125 million, which primarily relate to costs to identify and remove encroachments from transmission pipeline rights-of-way. Actual costs could be higher. The ultimate amount of unrecovered costsalso could be affected by how the CPUC determines which costs are included in determining whether the $850 million shareholder-funded obligation under the Penalty Decision has been met, and the outcome of pending and future investigations and enforcement matters. (See “Enforcement and Litigation Matters” below.) The Utility’s ability to recover costs in the future also could be affected by decreases in customer demand driven by legislative and regulatory initiatives relating to distributed generation resources, renewable energy requirements, and changes in the electric rate structure.

•	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 nine months ended September 30, 2015, PG&E Corporation issued $689 million of common stock and made equity contributions to the Utility of $605 million. PG&E Corporation forecasts that it will continue issuing a material amount of equity in 2016 and future years to support the Utility’s capital expenditures. PG&E Corporation will issue additional equity to fund the Utility’s unrecoverable pipeline-related expenses (including charges incurred under the Penalty Decision) and to pay fines and penalties that may be required by the final outcomes of pending enforcement matters. These additional equity issuances would have a further 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 the outcome of the matters discussed in “Enforcement and Litigation Matters” below, changes in their respective credit ratings, 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 “Item 1A. Risk Factors”in the 2014 Form 10-K and in Part II below under “Item 1A. Risk Factors.” 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.