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

Proposal for Electric Vehicle (EV) Infrastructure Development

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
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
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				Six Months Ended
	June 30,				June 30,
(in millions, except per share amounts)	2015		2014		2015		2014
Operating Revenues
Electric	$	3,463	$	3,233	$	6,476	$	6,234
Natural gas		754		719		1,640		1,609
Total operating revenues		4,217		3,952		8,116		7,843
Operating Expenses
Cost of electricity		1,277		1,349		2,277		2,559
Cost of natural gas		118		200		392		560
Operating and maintenance		1,484		1,328		3,407		2,627
Depreciation, amortization, and decommissioning		651		557		1,282		1,095
Total operating expenses		3,530		3,434		7,358		6,841
Operating Income		687		518		758		1,002
Interest income		3		2		4		5
Interest expense		(192)		(188)		(381)		(373)
Other income, net		18		43		76		62
Income Before Income Taxes		516		375		457		696
Income tax provision		110		104		17		195
Net Income		406		271		440		501
Preferred stock dividend requirement of subsidiary		4		4		7		7
Income Available for Common Shareholders	$	402	$	267	$	433	$	494
Weighted Average Common Shares Outstanding, Basic		480		467		479		463
Weighted Average Common Shares Outstanding, Diluted		483		469		483		465
Net Earnings Per Common Share, Basic	$	0.84	$	0.57	$	0.90	$	1.07
Net Earnings Per Common Share, Diluted	$	0.83	$	0.57	$	0.90	$	1.06
Dividends Declared Per Common Share	$	0.46	$	0.46	$	0.91	$	0.91

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in millions)	2015		2014		2015		2014
Net Income	$	406	$	271	$	440	$	501
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, $7, $12 and $3, at respective dates)		-		(11)		(17)		(6)
Total other comprehensive income (loss)		-		(11)		(17)		(6)
Comprehensive Income		406		260		423		495
Preferred stock dividend requirement of subsidiary		4		4		7		7
Comprehensive Income Attributable to
Common Shareholders	$	402	$	256	$	416	$	488

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Balance At
	June 30,		December 31,
(in millions)	2015		2014
ASSETS
Current Assets
Cash and cash equivalents	$	249	$	151
Restricted cash		287		298
Accounts receivable:
Customers (net of allowance for doubtful accounts of $56 and $66
at respective dates)		1,049		960
Accrued unbilled revenue		936		776
Regulatory balancing accounts		2,204		2,266
Other		352		377
Regulatory assets		441		444
Inventories:
Gas stored underground and fuel oil		141		172
Materials and supplies		315		304
Income taxes receivable		192		198
Other		280		443
Total current assets		6,446		6,389
Property, Plant, and Equipment
Electric		46,687		45,162
Gas		16,208		15,678
Construction work in progress		2,075		2,220
Other		2		2
Total property, plant, and equipment		64,972		63,062
Accumulated depreciation		(19,962)		(19,121)
Net property, plant, and equipment		45,010		43,941
Other Noncurrent Assets
Regulatory assets		6,476		6,322
Nuclear decommissioning trusts		2,504		2,421
Income taxes receivable		94		91
Other		1,101		963
Total other noncurrent assets		10,175		9,797
TOTAL ASSETS	$	61,631	$	60,127

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	June 30,		December 31,
(in millions, except share amounts)	2015		2014
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	1,016	$	633
Accounts payable:
Trade creditors		1,178		1,244
Regulatory balancing accounts		876		1,090
Other		458		476
Disputed claims and customer refunds		448		434
Interest payable		203		197
Other		2,123		1,846
Total current liabilities		6,302		5,920
Noncurrent Liabilities
Long-term debt		15,544		15,050
Regulatory liabilities		6,330		6,290
Pension and other postretirement benefits		2,536		2,561
Asset retirement obligations		3,609		3,575
Deferred income taxes		8,732		8,513
Other		2,307		2,218
Total noncurrent liabilities		39,058		38,207
Commitments and Contingencies (Note 9)
Equity
Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares;
481,575,453 and 475,913,404 shares outstanding at respective dates		10,717		10,421
Reinvested earnings		5,308		5,316
Accumulated other comprehensive income (loss)		(6)		11
Total shareholders' equity		16,019		15,748
Noncontrolling Interest - Preferred Stock of Subsidiary		252		252
Total equity		16,271		16,000
TOTAL LIABILITIES AND EQUITY	$	61,631	$	60,127

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Six Months Ended June 30,
(in millions)	2015		2014
Cash Flows from Operating Activities
Net income	$	440	$	501
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		1,282		1,095
Allowance for equity funds used during construction		(53)		(46)
Deferred income taxes and tax credits, net		219		51
Disallowed capital expenditures		128		-
Other		149		139
Effect of changes in operating assets and liabilities:
Accounts receivable		(241)		(30)
Inventories		20		(7)
Accounts payable		78		(101)
Income taxes receivable/payable		6		(39)
Other current assets and liabilities		77		94
Regulatory assets, liabilities, and balancing accounts, net		(62)		(311)
Other noncurrent assets and liabilities		(184)		(66)
Net cash provided by operating activities		1,859		1,280
Cash Flows from Investing Activities
Capital expenditures		(2,410)		(2,320)
Decrease in restricted cash		11		2
Proceeds from sales and maturities of nuclear decommissioning
trust investments		779		877
Purchases of nuclear decommissioning trust investments		(879)		(873)
Other		13		21
Net cash used in investing activities		(2,486)		(2,293)
Cash Flows from Financing Activities
Repayments under revolving credit facilities		-		(260)
Net issuances of commercial paper, net of discount of $2
and $1 at respective dates		681		237
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 at respective dates		486		1,236
Repayments of long-term debt		-		(889)
Common stock issued		252		589
Common stock dividends paid		(424)		(408)
Other		30		44
Net cash provided by financing activities		725		849
Net change in cash and cash equivalents		98		(164)
Cash and cash equivalents at January 1		151		296
Cash and cash equivalents at June 30	$	249	$	132

Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(334)	$	(318)
Income taxes, net		-		(1)
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	219	$	215
Capital expenditures financed through accounts payable		177		224
Noncash common stock issuances		10		10
Terminated capital leases		-		68

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended				Six Months Ended
	June 30,				June 30,
(in millions)	2015		2014		2015		2014
Operating Revenues
Electric	$	3,462	$	3,232	$	6,476	$	6,232
Natural gas		754		719		1,640		1,609
Total operating revenues		4,216		3,951		8,116		7,841
Operating Expenses
Cost of electricity		1,277		1,349		2,277		2,559
Cost of natural gas		118		200		392		560
Operating and maintenance		1,483		1,321		3,406		2,618
Depreciation, amortization, and decommissioning		651		556		1,282		1,094
Total operating expenses		3,529		3,426		7,357		6,831
Operating Income		687		525		759		1,010
Interest income		3		3		4		5
Interest expense		(189)		(185)		(376)		(364)
Other income, net		20		17		46		37
Income Before Income Taxes		521		360		433		688
Income tax provision		115		110		23		210
Net Income		406		250		410		478
Preferred stock dividend requirement		4		4		7		7
Income Available for Common Stock	$	402	$	246	$	403	$	471

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

	(Unaudited)
	Three Months Ended					Six Months Ended
	June 30,					June 30,
(in millions)	2015		2014			2015	2014
Net Income	$	406	$	250	$	410	$	478
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	$	406	$	250	$	410	$	478

See accompanying Notes to the Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

	(Unaudited)
	Balance At
	June 30,		December 31,
(in millions)	2015		2014
ASSETS
Current Assets
Cash and cash equivalents	$	148	$	55
Restricted cash		287		298
Accounts receivable:
Customers (net of allowance for doubtful accounts of $56 and $66
at respective dates)		1,049		960
Accrued unbilled revenue		936		776
Regulatory balancing accounts		2,204		2,266
Other		351		375
Regulatory assets		441		444
Inventories:
Gas stored underground and fuel oil		141		172
Materials and supplies		315		304
Income taxes receivable		160		168
Other		280		409
Total current assets		6,312		6,227
Property, Plant, and Equipment
Electric		46,687		45,162
Gas		16,208		15,678
Construction work in progress		2,075		2,220
Total property, plant, and equipment		64,970		63,060
Accumulated depreciation		(19,961)		(19,120)
Net property, plant, and equipment		45,009		43,940
Other Noncurrent Assets
Regulatory assets		6,476		6,322
Nuclear decommissioning trusts		2,504		2,421
Income taxes receivable		94		91
Other		998		864
Total other noncurrent assets		10,072		9,698
TOTAL ASSETS	$	61,393	$	59,865

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	June 30,		December 31,
(in millions, except share amounts)	2015		2014
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	1,011	$	633
Accounts payable:
Trade creditors		1,177		1,243
Regulatory balancing accounts		876		1,090
Other		482		444
Disputed claims and customer refunds		448		434
Interest payable		200		195
Other		1,899		1,604
Total current liabilities		6,093		5,643
Noncurrent Liabilities
Long-term debt		15,194		14,700
Regulatory liabilities		6,330		6,290
Pension and other postretirement benefits		2,449		2,477
Asset retirement obligations		3,609		3,575
Deferred income taxes		8,992		8,773
Other		2,263		2,178
Total noncurrent liabilities		38,837		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		6,703		6,514
Reinvested earnings		8,175		8,130
Accumulated other comprehensive income		5		5
Total shareholders' equity		16,463		16,229
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	61,393	$	59,865

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

	(Unaudited)
	Six Months Ended June 30,
(in millions)	2015		2014
Cash Flows from Operating Activities
Net income	$	410	$	478
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		1,282		1,094
Allowance for equity funds used during construction		(53)		(46)
Deferred income taxes and tax credits, net		219		18
Disallowed capital expenditures		128		-
Other		119		108
Effect of changes in operating assets and liabilities:
Accounts receivable		(242)		(31)
Inventories		20		(7)
Accounts payable		134		(72)
Income taxes receivable/payable		8		(35)
Other current assets and liabilities		67		141
Regulatory assets, liabilities, and balancing accounts, net		(62)		(311)
Other noncurrent assets and liabilities		(170)		(76)
Net cash provided by operating activities		1,860		1,261
Cash Flows from Investing Activities
Capital expenditures		(2,410)		(2,320)
Decrease in restricted cash		11		2
Proceeds from sales and maturities of nuclear decommissioning
trust investments		779		877
Purchases of nuclear decommissioning trust investments		(879)		(873)
Other		13		17
Net cash used in investing activities		(2,486)		(2,297)
Cash Flows from Financing Activities
Net issuances of commercial paper, net of discount of $2 and $1
at respective dates		676		125
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 $11 at respective dates		486		889
Repayments of long-term debt		-		(539)
Preferred stock dividends paid		(7)		(7)
Common stock dividends paid		(358)		(358)
Equity contribution from PG&E Corporation		185		580
Other		37		51
Net cash provided by financing activities		719		1,041
Net change in cash and cash equivalents		93		5
Cash and cash equivalents at January 1		55		65
Cash and cash equivalents at June 30	$	148	$	70

Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(330)	$	(307)
Income taxes, net		-		(1)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	177	$	224
Terminated capital leases		-		68

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 pending against the Utility relating to (1) the Utility’s safety recordkeeping for its natural gas transmission system, (2) the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density, and (3) the Utility’s pipeline installation, integrity management, recordkeeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the 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 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. The Penalty Decision requires that at least $688.5 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.)

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 June 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 June 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 six months ended June 30, 2015 and 2014 were as follows:

	Pension Benefits				Other Benefits
	Three Months Ended June 30,
(in millions)	2015		2014		2015		2014
Service cost for benefits earned	$	118	$	96	$	14	$	11
Interest cost		169		173		18		19
Expected return on plan assets		(218)		(201)		(28)		(26)
Amortization of prior service cost		3		5		5		5
Amortization of net actuarial loss		3		1		1		1
Net periodic benefit cost		75		74		10		10
Regulatory account transfer (1)		9		9		-		-
Total	$	84	$	83	$	10	$	10

(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
	Six Months Ended June 30,
(in millions)	2015		2014		2015		2014
Service cost for benefits earned	$	237	$	195	$	27	$	22
Interest cost		337		346		36		38
Expected return on plan assets		(436)		(403)		(56)		(52)
Amortization of prior service cost		7		10		10		11
Amortization of net actuarial loss		6		1		2		1
Net periodic benefit cost		151		149		19		20
Regulatory account transfer (1)		18		19		-		-
Total	$	169	$	168	$	19	$	20

(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 June 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)		2		3		5
Amortization of net actuarial loss
(net of taxes of $2 and $1, respectively)		1		1		2
Regulatory account transfer
(net of taxes of $3 and $3, respectively)		(3)		(4)		(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 June 30, 2014
Beginning balance	$	(7)	$	15	$	47	$	55
Other comprehensive income before reclassifications:
Change in investments
(net of taxes of $0, $0, and $3, respectively)		-		-		5		5
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $2, $2, and $0, respectively) (1)		3		3		-		6
Amortization of net actuarial loss
(net of taxes of $0, $0, and $0, respectively) (1)		1		1		-		2
Regulatory account transfer
(net of taxes of $2, $2, and $0, respectively) (1)		(4)		(4)		-		(8)
Change in investments
(net of taxes of $0, $0, and $10, respectively)		-		-		(16)		(16)
Net current period other comprehensive loss		-		-		(11)		(11)
Ending balance	$	(7)	$	15	$	36	$	44

	Pension		Other		Other
	Benefits		Benefits		Investments		Total
(in millions, net of income tax)	Six Months Ended June 30, 2015
Beginning balance	$	(21)	$	15	$	17	$	11
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $3, $4, and $0, respectively) (1)		4		6		-		10
Amortization of net actuarial loss
(net of taxes of $3, $1, and $0, respectively) (1)		3		1		-		4
Regulatory account transfer
(net of taxes of $6, $5, and $0, respectively) (1)		(7)		(7)		-		(14)
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)	Six Months Ended June 30, 2014
Beginning balance	$	(7)	$	15	$	42	$	50
Other comprehensive income before reclassifications:
Change in investments
(net of taxes of $0, $0, and $7, respectively)		-		-		10		10
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $4, $4, and $0, respectively) (1)		6		7		-		13
Amortization of net actuarial loss
(net of taxes of $0, $0, and $0, respectively) (1)		1		1		-		2
Regulatory account transfer
(net of taxes of $4, $4, and $0, respectively) (1)		(7)		(8)		-		(15)
Change in investments
(net of taxes of $0, $0, and $10, respectively)		-		-		(16)		(16)
Net current period other comprehensive loss		-		-		(6)		(6)
Ending balance	$	(7)	$	15	$	36	$	44

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 accounting standards update 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 accounting standards update 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 Accounting Standard Update, 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 July 2015, the FASB deferred 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
	June 30,		December 31,
(in millions)	2015		2014
Pension benefits	$	2,316	$	2,347
Deferred income taxes		2,649		2,390
Environmental compliance costs		686		717
Utility retained generation		434		456
Price risk management		142		127
Unamortized loss, net of gain, on reacquired debt		103		113
Electromechanical meters		36		70
Other		110		102
Total long-term regulatory assets	$	6,476	$	6,322

Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

	Balance at
	June 30,		December 31,
(in millions)	2015		2014
Cost of removal obligations	$	4,414	$	4,211
Recoveries in excess of asset retirement obligations		719		754
Public purpose programs		708		701
Other		489		624
Total long-term regulatory liabilities	$	6,330	$	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
	June 30,		December 31,
(in millions)	2015		2014
Electric distribution	$	672	$	344
Utility generation		392		261
Gas distribution		504		566
Energy procurement		308		608
Public purpose programs		82		109
Other		246		378
Total regulatory balancing accounts receivable	$	2,204	$	2,266

	Payable
	Balance at
	June 30,		December 31,
(in millions)	2015		2014
Energy procurement	$	173	$	188
Public purpose programs		177		154
Other (1)		526		748
Total regulatory balancing accounts payable	$	876	$	1,090

(1) At June 30, 2015 and December 31, 2014, Other regulatory balancing accounts payable mostly included energy supplier settlements related to the Utility’s outstanding bankruptcy claims. (See “Resolution of Remaining Chapter 11 Disputed Claims” in Note 9 below).

NOTE 4: DEBT

Short-term Borrowings

Revolving Credit Facilities and Commercial Paper Program

On April 27, 2015, PG&E Corporation and the Utility amended and restated their respective $300 million and $3.0 billion revolving credit facilities that were entered into on April 1, 2013. 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.

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

					Letters of
	Termination	Facility			Credit		Commercial		Facility
(in millions)	Date	Limit			Outstanding		Paper		Availability
PG&E Corporation	April 2020	$	300	(1)	$	-	$	5	$	295
Utility	April 2020		3,000	(2)		33		1,011		1,956
Total revolving
credit facilities		$	3,300		$	33	$	1,016	$	2,251

(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.

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.

Long-term Debt

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 June 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 ranged from 0.01% to 0.03%. At June 30, 2015, the interest rates on the $309 million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements ranged from 0.02% to 0.03%.

NOTE 5: EQUITY

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

	PG&E Corporation		Utility
	Total		Total
(in millions)	Equity		Shareholders' Equity
Balance at December 31, 2014	$	16,000	$	16,229
Comprehensive income		423		410
Equity contributions		-		185
Common stock issued		262		-
Share-based compensation		34		4
Common stock dividends declared		(441)		(358)
Preferred stock dividend requirement		-		(7)
Preferred stock dividend requirement of subsidiary		(7)		-
Balance at June 30, 2015	$	16,271	$	16,463

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 shares were sold during the three months ended June 30, 2015.

PG&E Corporation 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 six months ended June 30, 2015, 4.3 million shares were issued for cash proceeds of $178 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				Six Months Ended
	June 30,				June 30,
(in millions, except per share amounts)	2015		2014		2015		2014
Income available for common shareholders	$	402	$	267	$	433	$	494
Weighted average common shares outstanding, basic		480		467		479		463
Add incremental shares from assumed conversions:
Employee share-based compensation		3		2		4		2
Weighted average common share outstanding, diluted		483		469		483		465
Total earnings per common share, diluted	$	0.83	$	0.57	$	0.90	$	1.06

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
		June 30,	December 31,
Underlying Product	Instruments	2015	2014
Natural Gas (1) (MMBtus (2))	Forwards and Swaps	267,835,872	308,130,101
	Options	125,392,380	164,418,002
Electricity (Megawatt-hours)	Forwards and Swaps	4,904,985	5,346,787
	Congestion Revenue Rights (3)	197,344,663	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 June 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	$	70	$	(4)	$	15	$	81
Other noncurrent assets – other		156		(5)		-		151
Current liabilities – other		(70)		4		23		(43)
Noncurrent liabilities – other		(147)		5		19		(123)
Net commodity risk	$	9	$	-	$	57	$	66

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				Six Months Ended
	June 30,				June 30,
(in millions)	2015		2014		2015		2014
Unrealized gain (loss) - regulatory assets and liabilities (1)	$	28	$	27	$	(24)	$	85
Realized gain (loss) - cost of electricity (2)		10		(8)		3		(26)
Realized loss - cost of natural gas (2)		(4)		(3)		(5)		(3)
Net commodity risk	$	34	$	16	$	(26)	$	56

(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 June 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
	June 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 June 30, 2015
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments	$	109	$	-	$	-	$	-	$	109
Nuclear decommissioning trusts
Money market investments		32		-		-		-		32
Global equity securities		1,587		13		-		-		1,600
Fixed-income securities		681		541		-		-		1,222
Total nuclear decommissioning trusts (2)		2,300		554		-		-		2,854
Price risk management instruments
(Note 7)
Electricity		1		8		212		6		227
Gas		1		4		-		-		5
Total price risk management instruments		2		12		212		6		232
Rabbi trusts
Fixed-income securities		-		42		-		-		42
Life insurance contracts		-		72		-		-		72
Total rabbi trusts		-		114		-		-		114
Long-term disability trust
Money market investments		4		-		-		-		4
Global equity securities		-		22		-		-		22
Fixed-income securities		-		117		-		-		117
Total long-term disability trust		4		139		-		-		143
Total assets	$	2,415	$	819	$	212	$	6	$	3,452
Liabilities:
Price risk management instruments
(Note 7)
Electricity	$	47	$	4	$	164	$	(51)	$	164
Gas		-		2		-		-		2
Total liabilities	$	47	$	6	$	164	$	(51)	$	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 $350 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 six months ended June 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 June 30, 2015				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	212	$	62	Market approach	CRR auction prices	$	(47.09) - 8.17
Power purchase agreements	$	-	$	102	Discounted cash flow	Forward prices	$	22.04 - 57.00

(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 six months ended June 30, 2015 and 2014:

	Price Risk Management Instruments
(in millions)	2015		2014
Asset (liability) balance as of April 1	$	42	$	(22)
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		6		11
Asset (liability) balance as of June 30	$	48	$	(11)

(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)		(21)		19
Asset (liability) balance as of June 30	$	48	$	(11)

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 June 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 June 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 June 30, 2015				At December 31, 2014
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
PG&E Corporation	$	350	$	351	$	350	$	352
Utility		14,272		15,715		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 June 30, 2015
Nuclear decommissioning trusts
Money market investments	$	32	$	-	$	-	$	32
Global Equity securities		516		1,091		(7)		1,600
Fixed Income securities		1,169		60		(7)		1,222
Total (1)	$	1,717	$	1,151	$	(14)	$	2,854
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 $350 million and $324 million at June 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)	June 30, 2015
Less than 1 year	$	19
1–5 years		458
5–10 years		277
More than 10 years		468
Total maturities of debt securities	$	1,222

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2015		2014			2015	2014
(in millions)
Proceeds from sales and maturities of nuclear decommissioning
trust investments	$	362	$	347	$	779	$	877
Gross realized gains on securities held as available-for-sale		12		28		47		84
Gross realized losses on securities held as available-for-sale		(10)		(2)		(13)		(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

Improper CPUC Communications

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. 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. 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.

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. In November 2014, the CPUC imposed a fine of $1.05 million on the Utility for these communications. In addition, the CPUC disallowed 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.

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. 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.

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. 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. It is uncertain what action the CPUC or other parties will take in response to these additional reported communications. It is possible that additional orders will be issued to which the Utility will be required to respond. The CPUC could impose fines and penalties on the Utility relating to communications reported to the CPUC or with respect to additional communications that the Utility may identify and report in response to new orders that may be issued or in connection with new or ongoing investigations or legal proceedings.

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.

Other CPUC Matters

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 for 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. On April 10, 2015, the assigned Commissioner issued a scoping memo and ruling stating that the scope of the proceeding is whether or not the Utility violated any applicable laws, rules, or regulations “by its record-keeping policies and practices with respect to maintaining safe operation of its gas distribution system.” The scope of the proceeding also may include matters resulting from the SED’s ongoing reviews of the Utility’s record-keeping practices relating to mapping, pre-excavation location and marking, and pressure validation for distribution facilities, among other issues.

The procedural schedule requires the SED’s and intervenors’ testimony to be submitted starting in September 2015 with the Utility’s response due in November 2015, followed by rebuttal testimony in December 2015. Hearings are scheduled for January 2016.

PG&E Corporation and the Utility believe it is reasonably possible that the CPUC will impose penalties on the Utility or require the Utility 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 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. In addition, the Utility could incur material costs to implement operational remedies, which may not be recoverable.

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. In addition, the California utilities are required to inform the SED of self-identified or self-corrected violations. The SED has authority to issue citations and impose fines for violations identified through audits, investigations, or self-reports. The SED can consider various factors in determining whether to impose fines and the amount of fines, including the severity of the safety risk associated with each violation, the number and duration of the violations, whether the violation was self-reported, and whether corrective actions were taken.

The SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of 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 natural gas 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 recordkeeping, 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 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. 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. The trial is set to begin March 8, 2016.

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). It is uncertain whether any charges will be brought against the Utility. The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the indicted case.

Capital Expenditures relating to Pipeline Safety Enhancement Plan

At June 30, 2015, approximately $645 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 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.

For the three months and six months ended June 30, 2015, the Utility recorded additional charges of $75 million and $628 million, respectively, as a result of the Penalty Decision. The cumulative charges at June 30, 2015, and the anticipated future financial impact are shown in the following table:

					Anticipated
	Six Months		Cumulative		Future
	Ended		Charges		Financial		Total
(in millions)	June 30, 2015		June 30, 2015		Impact		Amount
Fine payable to the state (1)	$	100	$	300	$	-	$	300
Customer bill credit		400		400		-		400
Charge for disallowed capital (2)		128		128		561		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
recorded	$	628	$	848	$	752	$	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 $75 million and $128 million of capital spending (which include less than $1 million for remedy related capital costs)in the three months and six months ended June 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 estimates that the Utility would incur $50 million to comply with the other remedies in the Penalty Decision, including $30 million to reimburse the CPUC for the costs of future audits. Remedial costs are expensed as incurred. Other than the refund of CPUC audit costs, the majority of the remedies have been completed or are underway and the associated costs have already been incurred.

At June 30, 2015, the Condensed Consolidated Balance Sheets include $300 million in other current liabilities for the fines payable, and $400 million in current regulatory liabilities for the one-time bill credit due to the Utility’s natural gas customers. The charges recorded are reflected in operating and maintenance expenses in the June 30, 2015, Condensed Consolidated Statements of Income.

The Penalty Decision requires that at least $688.5 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. 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. It is uncertain what costs the CPUC will ultimately count towards the $850 million shareholder-funded obligation. To the extent the Utility’s actual costs exceed qualified amounts and are not authorized for recovery, the Utility may be required to record additional charges in future periods. The CPUC is expected to issue a final decision in the Utility’s 2015 GT&S rate case in 2016 to identify the safety-related project and programs that will be subject to the disallowance.

Other Legal and Regulatory Contingencies

Accruals for other legal and regulatory contingencies (excluding amounts related to the enforcement and litigation matters described above) totaled $43 million at June 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
(in millions)	June 30, 2015		December 31, 2014
Topock natural gas compressor station (1)	$	297	$	291
Hinkley natural gas compressor station (1)		149		158
Former manufactured gas plant sites owned by the Utility or third parties		263		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		96		98
Total environmental remediation liability	$	958	$	954

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

At June 30, 2015, the Utility expected to recover $676 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC. The Utility will also incur environmental remediation costs that it does not seek to recover in rates, such as the costs associated with the Hinkley site.

Natural Gas Compressor Station Sites

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. One of these stations is located near Hinkley, California and is referred to below as the “Hinkley site.” Another station is located near Needles, California and is referred to below as the “Topock site.” The Utility is also required to take measures to abate the effects of the contamination on the environment.

Hinkley Site

The Utility 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. In January 2015, the Regional Board issued an updated draft clean-up and abatement order that proposes the Utility continues and improves its remedial treatment methods and contains a proposed monitoring and reporting program. The Regional Board is expected to issue a revised draft clean-up and abatement order in August 2015. After a public comment period, the Regional Board is expected to consider adoption of a final clean-up and abatement order (which may include deadlines to meet specified interim clean up targets) at its November 2015 meeting.

The Utility’s environmental remediation liability at June 30, 2015 reflects the Utility’s best estimate of probable future costs associated with its final remediation plan and interim remediation measures. Future costs will depend on many factors, including the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the required time period by which those standards must be met, and the nature and extent of the chromium contamination. Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition, results of operations, and cash flows.

Topock Site

The Utility's remediation and abatement efforts at the Topock site are 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 June 30, 2015 reflects its best estimate of probable future costs associated with its 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 six months ended June 30, 2015.

Tax Matters

The IRS is currently reviewing several matters in the 2011, 2012, and 2013 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 review of the deductible repair costs for the electric transmission and distribution businesses in 2015. The IRS is also expected to issue guidance during 2015 that determines 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 audits related to the 2011, 2012, and 2013 tax returns. As of June 30, 2015, it is reasonably possible that unrecognized tax benefits will decrease by approximately $370 million within the next 12 months, and most of this decrease would not impact net income.

There were no other significant developments to tax matters during the six months ended June 30, 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 had undiscounted 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 six months ended June 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 $465 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				Six Months Ended
	June 30,				June 30,
			EPS				EPS
(in millions, except per share amounts)	Earnings		(Diluted)		Earnings		(Diluted)
Income Available for Common Shareholders - 2014	$	267	$	0.57	$	494	$	1.06
Natural gas matters (1)		57		0.12		81		0.18
Earnings from Operations - 2014 (2)	$	324	$	0.69	$	575	$	1.24
2014 GRC cost recovery (3)		99		0.21		198		0.41
Growth in rate base earnings		26		0.05		52		0.11
Nuclear refueling outage		-		-		26		0.05
Timing of taxes (4)		18		0.04		38		0.08
Gain on disposition of SolarCity stock⁽⁵⁾		(14)		(0.03)		-		-
Timing of 2015 GT&S cost recovery (6)		(44)		(0.09)		(80)		(0.17)
Increase in shares outstanding		-		(0.02)		-		(0.05)
Other		33		0.06		51		0.11
Earnings from Operations - 2015 (2)	$	442	$	0.91	$	860	$	1.78
Pipeline-related expenses (7)		(9)		(0.02)		(19)		(0.04)
Legal and regulatory related expenses (7)		(10)		(0.02)		(18)		(0.04)
Fines and penalties (8)		(44)		(0.09)		(413)		(0.85)
Insurance recoveries (9)		23		0.05		23		0.05
Income Available for Common Shareholders - 2015	$	402	$	0.83	$	433	$	0.90

⁽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⁾ "Earnings from operations" is not calculated in accordance with GAAP and excludes the items impacting comparability shown in Note (1) above and Notes (6), (7), and (8) below.

⁽³⁾ Represents the increase in base revenues authorized by the CPUC in the 2014 GRC decision for the three and six months ended June 30, 2015, including the impact of flow-through ratemaking treatment for federal tax deductions for repairs. In 2014, the Utility was incurring approximately $200 million of expense and $1 billion of capital costs above authorized levels until the 2014 GRC decision authorized revenues that supported this higher level of spending. The increase in revenue related to 2014 was not recognized until the quarter ended September 30, 2014, when the 2014 GRC decision was issued.

⁽⁴⁾ Represents the timing of taxes reportable in quarterly financial statements.

⁽⁵⁾ Represents the comparative negative impact of a gain recognized during the three months ended June 30, 2014 as compared to the three months ended June 30, 2015 during which no comparable gain was recognized. For the six months ended June 30, 2015, this comparative negative impact was offset by a gain recognized during the three months ended March 31, 2015.

⁽⁶⁾ Represents expenses reflected in Earnings from Operations during the three and six months ended June 30, 2015 as compared to the same periods in 2014, with no corresponding increase in revenue. The Utility has requested the CPUC authorize an increase to its revenue requirements for 2015, 2016, and 2017 in its GT&S rate case. Based on the procedural schedule, it is unlikely that the Utility will be able to recognize any increase in its GT&S revenue in 2015.

⁽⁷⁾ In 2015, pipeline-related expenses includes 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 includes various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.

⁽⁸⁾ Represents the impact of the Penalty Decision (see Note 9 of the Notes to the Condensed Consolidated Financial Statements for before-tax amounts).

⁽⁹⁾ Insurance recoveries related to third-party claims and associated legal costs recognized in the three and six months ended June 30, 2015 (See "Results of Operations" below).

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 alleging that the Utility knowingly and willfully violated the Pipeline Safety Act and illegally obstructed the NTSB’s investigation into the cause of the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010. 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. Federal and state authorities also are conducting investigations in connection with certain communications between the Utility and CPUC personnel. The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the indicted case. Fines may be imposed, or other regulatory or governmental enforcement action could be taken, with respect to these and other enforcement matters, including new CPUC investigations. (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 GT&S rate case, the Utility has requested that the CPUC authorize revenue requirements for the Utility’s gas transmission and storage operations from 2015 through 2017. The Utility has requested an increase in its 2015 revenue requirements of $555 million over the comparable authorized revenues, as well as increases for 2016 and 2017. Based on the scoping ruling and procedural schedule that was issued on June 11, 2015, the CPUC is expected to issue a two-part decision, the first decision to authorize GT&S revenue requirements (which would reflect a potential disallowance to be imposed as a penalty for the Utility’s violation of the CPUC’s ex parte communication rules as well as a reduction in the Utility's request to reflect any costs associated with implementing the remedies ordered by the Penalty Decision), and a second decision to reduce the authorized revenue requirements by the costs of designated safety-related projects and programs up to the $850 million maximum cost disallowance imposed by the Penalty Decision. Any revenue requirement increase would be retroactive to January 1, 2015. Based on the procedural schedule it is unlikely that the Utility will be able to recognize any increase in GT&S revenues in 2015. If the Utility does not recognize any increase in 2015, the authorized revenue increase would be recorded in 2016. (See “Ratemaking Proceedings” below for more information.) In addition, the Utility intends to file its 2017 GRC application with the CPUC by September 2015, 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 and future years. 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 $150 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 costs also 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.

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The Amount and Timing of the Utility’s Financing Needs. PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure. For the six months ended June 30, 2015, PG&E Corporation issued $252 million of common stock and made equity contributions to the Utility of $185 million. PG&E Corporation forecasts that it will continue issuing a material amount of equity to support the Utility’s capital expenditures and to fund unrecovered pipeline-related costs (including costs incurred under the Penalty Decision) and to pay the fine imposed by the Penalty Decision and additional fines and penaltiesthat may be required by the final outcomes of ongoing enforcement matters. These 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.