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

ELECTRIC DISTRIBUTION RESOURCES

ENVIRONMENTAL MATTERS

CONTRACTUAL COMMITMENTS

RISK MANAGEMENT ACTIVITIES

CRITICAL ACCOUNTING POLICIES

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

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
CAISO	California Independent System Operator
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
EPS	earnings per common share
EV	electric vehicle
FERC	Federal Energy Regulatory Commission
GAAP	U.S. Generally Accepted Accounting Principles
GRC	general rate case
GT&S	gas transmission and storage
IRS	Internal Revenue Service
NRC	Nuclear Regulatory Commission
NTSB	National Transportation Safety Board
ORA	Office of Ratepayer Advocates
PSEP	pipeline safety enhancement plan
Regional Board	California Regional Water Control Board, Lahontan Region
SEC	U.S. Securities and Exchange Commission
SED	Safety and Enforcement Division of the CPUC, formerly known as the Consumer Protection and Safety Division or the CPSD
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
	March 31,
(in millions, except per share amounts)	2015		2014
Operating Revenues
Electric	$	3,013	$	3,001
Natural gas		886		890
Total operating revenues		3,899		3,891
Operating Expenses
Cost of electricity		1,000		1,210
Cost of natural gas		274		360
Operating and maintenance		1,923		1,299
Depreciation, amortization, and decommissioning		631		538
Total operating expenses		3,828		3,407
Operating Income		71		484
Interest income		1		3
Interest expense		(189)		(185)
Other income, net		58		19
Income (Loss) Before Income Taxes		(59)		321
Income tax provision (benefit)		(93)		91
Net Income		34		230
Preferred stock dividend requirement of subsidiary		3		3
Income Available for Common Shareholders	$	31	$	227
Weighted Average Common Shares Outstanding, Basic		477		459
Weighted Average Common Shares Outstanding, Diluted		481		460
Net Earnings Per Common Share, Basic	$	0.06	$	0.49
Net Earnings Per Common Share, Diluted	$	0.06	$	0.49
Dividends Declared Per Common Share	$	0.46	$	0.46

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2015		2014
Net Income	$	34	$	230
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $0 and $0, at respective dates)		-		-
Net change in investments
(net of taxes of $12 and $4, at respective dates)		(17)		5
Total other comprehensive income (loss)		(17)		5
Comprehensive Income		17		235
Preferred stock dividend requirement of subsidiary		3		3
Comprehensive Income Attributable to Common Shareholders	$	14	$	232

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Balance At
	March 31,		December 31,
(in millions)	2015		2014
ASSETS
Current Assets
Cash and cash equivalents	$	145	$	151
Restricted cash		298		298
Accounts receivable:
Customers (net of allowance for doubtful accounts of $60 and $66
at respective dates)		905		960
Accrued unbilled revenue		651		776
Regulatory balancing accounts		2,227		2,266
Other		314		377
Regulatory assets		451		444
Inventories:
Gas stored underground and fuel oil		108		172
Materials and supplies		310		304
Income taxes receivable		195		198
Other		422		443
Total current assets		6,026		6,389
Property, Plant, and Equipment
Electric		45,888		45,162
Gas		15,970		15,678
Construction work in progress		2,115		2,220
Other		2		2
Total property, plant, and equipment		63,975		63,062
Accumulated depreciation		(19,534)		(19,121)
Net property, plant, and equipment		44,441		43,941
Other Noncurrent Assets
Regulatory assets		6,412		6,322
Nuclear decommissioning trusts		2,526		2,421
Income taxes receivable		94		91
Other		1,048		963
Total other noncurrent assets		10,080		9,797
TOTAL ASSETS	$	60,547	$	60,127

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	March 31,		December 31,
(in millions, except share amounts)	2015		2014
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	856	$	633
Accounts payable:
Trade creditors		1,007		1,244
Regulatory balancing accounts		1,039		1,090
Other		545		476
Disputed claims and customer refunds		446		434
Interest payable		150		197
Other		2,110		1,846
Total current liabilities		6,153		5,920
Noncurrent Liabilities
Long-term debt		15,051		15,050
Regulatory liabilities		6,307		6,290
Pension and other postretirement benefits		2,551		2,561
Asset retirement obligations		3,595		3,575
Deferred income taxes		8,626		8,513
Other		2,309		2,218
Total noncurrent liabilities		38,439		38,207
Commitments and Contingencies (Note 9)
Equity
Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares;
479,490,832 and 475,913,404 shares outstanding at respective dates		10,583		10,421
Reinvested earnings		5,126		5,316
Accumulated other comprehensive income (loss)		(6)		11
Total shareholders' equity		15,703		15,748
Noncontrolling Interest - Preferred Stock of Subsidiary		252		252
Total equity		15,955		16,000
TOTAL LIABILITIES AND EQUITY	$	60,547	$	60,127

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2015		2014
Cash Flows from Operating Activities
Net income	$	34	$	230
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		631		538
Allowance for equity funds used during construction		(28)		(22)
Deferred income taxes and tax credits, net		113		15
Disallowed capital expenditures		53		-
Other		52		56
Effect of changes in operating assets and liabilities:
Accounts receivable		236		321
Inventories		58		62
Accounts payable		(46)		31
Income taxes receivable/payable		3		(28)
Other current assets and liabilities		(114)		(37)
Regulatory assets, liabilities, and balancing accounts, net		195		(376)
Other noncurrent assets and liabilities		(107)		(19)
Net cash provided by operating activities		1,080		771
Cash Flows from Investing Activities
Capital expenditures		(1,191)		(1,197)
Proceeds from sales and maturities of nuclear decommissioning
trust investments		417		530
Purchases of nuclear decommissioning trust investments		(505)		(536)
Other		7		14
Net cash used in investing activities		(1,272)		(1,189)
Cash Flows from Financing Activities
Repayments under revolving credit facilities		-		(260)
Net issuances of commercial paper, net of discount of $0
and $1 at respective dates		223		15
Proceeds from issuance of long-term debt, net of premium, discount,
and issuance costs of $13 in 2014		-		1,237
Repayments of long-term debt		-		(889)
Common stock issued		151		302
Common stock dividends paid		(211)		(202)
Other		23		27
Net cash provided by financing activities		186		230
Net change in cash and cash equivalents		(6)		(188)
Cash and cash equivalents at January 1		151		296
Cash and cash equivalents at March 31	$	145	$	108
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(216)	$	(199)
Income taxes, net		-		1

Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	218	$	213
Capital expenditures financed through accounts payable		217		171
Noncash common stock issuances		5		5

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended
	March 31,
(in millions)	2015		2014
Operating Revenues
Electric	$	3,014	$	3,000
Natural gas		886		890
Total operating revenues		3,900		3,890
Operating Expenses
Cost of electricity		1,000		1,210
Cost of natural gas		274		360
Operating and maintenance		1,923		1,297
Depreciation, amortization, and decommissioning		631		538
Total operating expenses		3,828		3,405
Operating Income		72		485
Interest income		1		2
Interest expense		(187)		(179)
Other income, net		26		20
Income (Loss) Before Income Taxes		(88)		328
Income tax provision (benefit)		(92)		100
Net Income		4		228
Preferred stock dividend requirement		3		3
Income Available for Common Stock	$	1	$	225

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

	Three Months Ended March 31,
(in millions)	2015		2014
Net Income	$	4	$	228
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $0 and $0, at respective dates )		-		-
Total other comprehensive income (loss)		-		-
Comprehensive Income	$	4	$	228

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

	(Unaudited)
	Balance At
	March 31,		December 31,
(in millions)	2015		2014
ASSETS
Current Assets
Cash and cash equivalents	$	50	$	55
Restricted cash		298		298
Accounts receivable:
Customers (net of allowance for doubtful accounts of $60 and $66
at respective dates)		905		960
Accrued unbilled revenue		651		776
Regulatory balancing accounts		2,227		2,266
Other		333		375
Regulatory assets		451		444
Inventories:
Gas stored underground and fuel oil		108		172
Materials and supplies		310		304
Income taxes receivable		166		168
Other		408		409
Total current assets		5,907		6,227
Property, Plant, and Equipment
Electric		45,888		45,162
Gas		15,970		15,678
Construction work in progress		2,115		2,220
Total property, plant, and equipment		63,973		63,060
Accumulated depreciation		(19,532)		(19,120)
Net property, plant, and equipment		44,441		43,940
Other Noncurrent Assets
Regulatory assets		6,412		6,322
Nuclear decommissioning trusts		2,526		2,421
Income taxes receivable		94		91
Other		943		864
Total other noncurrent assets		9,975		9,698
TOTAL ASSETS	$	60,323	$	59,865

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
	March 31,		December 31,
(in millions, except share amounts)	2015		2014
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	856	$	633
Accounts payable:
Trade creditors		1,007		1,243
Regulatory balancing accounts		1,039		1,090
Other		584		444
Disputed claims and customer refunds		446		434
Interest payable		149		195
Other		1,873		1,604
Total current liabilities		5,954		5,643
Noncurrent Liabilities
Long-term debt		14,701		14,700
Regulatory liabilities		6,307		6,290
Pension and other postretirement benefits		2,465		2,477
Asset retirement obligations		3,595		3,575
Deferred income taxes		8,885		8,773
Other		2,266		2,178
Total noncurrent liabilities		38,219		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		6,613		6,514
Reinvested earnings		7,952		8,130
Accumulated other comprehensive income		5		5
Total shareholders' equity		16,150		16,229
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	60,323	$	59,865

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2015		2014
Cash Flows from Operating Activities
Net income	$	4	$	228
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		631		538
Allowance for equity funds used during construction		(28)		(22)
Deferred income taxes and tax credits, net		112		(19)
Disallowed capital expenditures		53		-
Other		45		39
Effect of changes in operating assets and liabilities:
Accounts receivable		215		312
Inventories		58		62
Accounts payable		26		53
Income taxes receivable/payable		2		(25)
Other current assets and liabilities		(123)		26
Regulatory assets, liabilities, and balancing accounts, net		195		(376)
Other noncurrent assets and liabilities		(89)		(37)
Net cash provided by operating activities		1,101		779
Cash Flows from Investing Activities
Capital expenditures		(1,191)		(1,197)
Proceeds from sales and maturities of nuclear decommissioning
trust investments		417		530
Purchases of nuclear decommissioning trust investments		(505)		(536)
Other		7		11
Net cash used in investing activities		(1,272)		(1,192)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $0 and $1
at respective dates		223		(33)
Proceeds from issuance of long-term debt, net of premium, discount,
and issuance costs of $10 in 2014		-		890
Repayments of long-term debt		-		(539)
Preferred stock dividends paid		(3)		(3)
Common stock dividends paid		(179)		(179)
Equity contribution from PG&E Corporation		100		250
Other		25		30
Net cash provided by financing activities		166		416
Net change in cash and cash equivalents		(5)		3
Cash and cash equivalents at January 1		55		65
Cash and cash equivalents at March 31	$	50	$	68
Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(211)	$	(188)
Income taxes, net		-		1
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	217	$	171

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. As a result of the Penalty Decision, the March 31, 2015 Condensed Consolidated Statements of Income reflect total charges of $553 million, consisting of $400 million for a bill credit due to natural gas customers, $100 million of accrued fines payable to the State General Fund (bringing the total accrual for fines payable to $300 million), and $53 million of estimated disallowances related to pipeline safety improvements. (See Note 9 below.)

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

The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of PG&E Corporation and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2014 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in the 2014 Form 10-K. This quarterly report should be read in conjunction with the 2014 Form 10-K.

The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, legal and regulatory contingencies, environmental remediation liabilities, asset retirement obligations, and pension and other postretirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. Actual results could differ materially from those estimates.

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

The significant accounting policies used by PG&E Corporation and the Utility are discussed in Note 2 of the Notes to the Consolidated Financial Statements in the 2014 Form 10-K.

Variable Interest Entities

A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at March 31, 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 March 31, 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 for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate. Net periodic costs for both are included in Pension Benefits in the table below.

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three months ended March 31, 2015 and 2014 were as follows:

	Pension Benefits				Other Benefits
	Three Months Ended March 31,
(in millions)	2015		2014		2015		2014
Service cost for benefits earned	$	119	$	99	$	13	$	11
Interest cost		168		173		18		19
Expected return on plan assets		(218)		(202)		(28)		(26)
Amortization of prior service cost		4		5		5		6
Amortization of net actuarial loss		3		-		1		-
Net periodic benefit cost		76		75		9		10
Regulatory account transfer (1)		9		9		-		-
Total	$	85	$	84	$	9	$	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.

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

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

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

	Pension		Other		Other
	Benefits		Benefits		Investments		Total
(in millions, net of income tax)	Three Months Ended March 31, 2015
Beginning balance	$	(21)	$	15	$	17	$	11
Amounts reclassified from other comprehensive income:
Amortization of prior service cost
(net of taxes of $2, $2, and $0, respectively) (1)		2		3		-		5
Amortization of net actuarial loss
(net of taxes of $1, $0, and $0, respectively) (1)		2		-		-		2
Regulatory account transfer
(net of taxes of $3, $2, and $0, respectively) (1)		(4)		(3)		-		(7)
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)

(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 March 31, 2014
Beginning balance	$	(7)		15		42		50
Other comprehensive income before reclassifications:
Change in investments
(net of taxes of $0, $0, and $4, respectively)		-		-		5		5
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost
(net of taxes of $2, $2, and $0, respectively)		3		4		-		7
Regulatory account transfer
(net of taxes of $2, $2, and $0, respectively)		(3)		(4)		-		(7)
Net current period other comprehensive income		-		-		5		5
Ending balance	$	(7)	$	15	$	47	$	55

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

Presentation of Debt Issuance Costs

In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update 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 will adopt this standard starting in the first quarter of 2016.

Accounting for Fees Paid in a Cloud Computing Arrangement

In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update 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.

Revenue Recognition Standard

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

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Long-term regulatory assets are composed of the following:

	Balance at
	March 31,		December 31,
(in millions)	2015		2014
Pension benefits	$	2,332	$	2,347
Deferred income taxes		2,521		2,390
Environmental compliance costs		674		717
Utility retained generation		446		456
Price risk management		170		127
Unamortized loss, net of gain, on reacquired debt		108		113
Electromechanical meters		53		70
Other		108		102
Total long-term regulatory assets	$	6,412	$	6,322

Regulatory Liabilities

Long-term regulatory liabilities are composed of the following:

	Balance at
	March 31,		December 31,
(in millions)	2015		2014
Cost of removal obligations	$	4,307	$	4,211
Recoveries in excess of asset retirement obligations		760		754
Public purpose programs		743		701
Other		497		624
Total long-term regulatory liabilities	$	6,307	$	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
	March 31,		December 31,
(in millions)	2015		2014
Electric distribution	$	643	$	344
Utility generation		434		261
Gas distribution		413		566
Energy procurement		412		608
Public purpose programs		87		109
Other		238		378
Total regulatory balancing accounts receivable	$	2,227	$	2,266

	Payable
	Balance at
	March 31,		December 31,
(in millions)	2015		2014
Energy procurement	$	217	$	188
Public purpose programs		144		154
Other (1)		678		748
Total regulatory balancing accounts payable	$	1,039	$	1,090

(1) At March 31, 2015 Other regulatory balancing accounts payable mostly includes 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

Revolving Credit Facilities and Commercial Paper Program

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at March 31, 2015:

					Letters of
	Termination	Facility			Credit		Commercial		Facility
(in millions)	Date	Limit			Outstanding		Paper		Availability
PG&E Corporation	April 2019	$	300	(1)	$	-	$	-	$	300
Utility	April 2019		3,000	(2)		33		556		2,411
Total revolving
credit facilities		$	3,300		$	33	$	556	$	2,711

(1) Includes a $100 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 $1.0 billion sublimit for letters of credit and a $300 million commitment for swingline loans.

PG&E Corporation and the Utility can issue commercial paper up to the maximum amounts of $300 million and $1.75 billion, respectively. PG&E Corporation and the Utility treat the amount of outstanding commercial paper as a reduction to the amount available under their respective revolving credit facilities.

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.

Borrowings under each amended and restated credit agreement (other than swing line loans) will bear interest based, at each borrower’s election, on (1) a London Interbank Offered Rate (“LIBOR”) plus an applicable margin or (2) the base rate plus an applicable margin. The base rate will equal the higher of the following: the administrative agent’s announced base rate, 0.5% above the overnight federal funds rate, and the one-month LIBOR plus an applicable margin. The applicable margin for LIBOR loans will range between 0.9% and 1.475% under PG&E Corporation’s amended and restated credit agreement and between 0.8% and 1.275% under the Utility’s amended and restated credit agreement. The applicable margin for base rate loans will range between 0% and 0.475% under PG&E Corporation’s amended and restated credit agreement and between 0% and 0.275% under the Utility’s amended and restated credit agreement. In addition, the facility fee under PG&E Corporation’s and the Utility’s amended and restated credit agreements will range between 0.1% and 0.275% and between 0.075% and 0.225%, respectively.

Pollution Control Bonds

At March 31, 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 0.02%. At March 31, 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 0.01% to 0.03%.

NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the three months ended March 31, 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		17		4
Equity contributions		-		100
Common stock issued		156		-
Share-based compensation		6		(1)
Common stock dividends declared		(221)		(179)
Preferred stock dividend requirement		-		(3)
Preferred stock dividend requirement of subsidiary		(3)		-
Balance at March 31, 2015	$	15,955	$	16,150

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. During the three months ended March 31, 2015, PG&E Corporation sold 1.4 million shares under the February 2015 equity distribution agreement for cash proceeds of $74 million, net of commissions paid of $1 million.

In addition, 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 three months ended March 31, 2015,

2.2 million shares were issued for cash proceeds of $77 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 March 31,
(in millions, except per share amounts)	2015		2014
Income available for common shareholders	$	31	$	227
Weighted average common shares outstanding, basic		477		459
Add incremental shares from assumed conversions:
Employee share-based compensation		4		1
Weighted average common shares outstanding, diluted		481		460
Total earnings per common share, diluted	$	0.06	$	0.49

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.

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

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. The Utility expects to fully recover in rates all costs related to derivatives as long as the current ratemaking mechanism remains in place and the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities 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.

Cash collateral paid or received is offset against the fair value of derivative instruments executed with the same counterparty under a master netting arrangement, where the right of offset and the intention to offset exist. Derivatives are presented in the Utility’s Condensed Consolidated Balance Sheets on a net basis.

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. The fair value of these items is 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
		March 31,	December 31,
Underlying Product	Instruments	2015	2014
Natural Gas (1) (MMBtus (2))	Forwards and Swaps	286,357,249	308,130,101
	Options	120,616,913	164,418,002
Electricity (Megawatt-hours)	Forwards and Swaps	5,254,402	5,346,787
	Congestion Revenue Rights (3)	213,503,515	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 based on demand when there is insufficient transmission capacity.

Presentation of Derivative Instruments in the Financial Statements

At March 31, 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	$	72	$	(3)	$	17	$	86
Other noncurrent assets – other		168		(5)		-		163
Current liabilities – other		(84)		3		33		(48)
Noncurrent liabilities – other		(175)		5		29		(141)
Net commodity risk	$	(19)	$	-	$	79	$	60

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 March 31,
(in millions)	2015		2014
Net unrealized gain (loss) - regulatory assets and liabilities (1)	$	(52)	$	58
Realized loss - cost of electricity (2)		(7)		(18)
Realized loss - cost of natural gas (2)		(1)		-
Total commodity risk	$	(60)	$	40

(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 March 31, 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
	March 31,		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 March 31, 2015
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Money market investments	$	96	$	-	$	-	$	-	$	96
Nuclear decommissioning trusts
Money market investments		29		-		-		-		29
Global equity securities		1,619		13		-		-		1,632
Fixed-income securities		673		539		-		-		1,212
Total nuclear decommissioning trusts (2)		2,321		552		-		-		2,873
Price risk management instruments
(Note 7)
Electricity		-		7		230		9		246
Gas		2		1		-		-		3
Total price risk management instruments		2		8		230		9		249
Rabbi trusts
Fixed-income securities		-		42		-		-		42
Life insurance contracts		-		74		-		-		74
Total rabbi trusts		-		116		-		-		116
Long-term disability trust
Money market investments		4		-		-		-		4
Global equity securities		-		24		-		-		24
Fixed-income securities		-		123		-		-		123
Total long-term disability trust		4		147		-		-		151
Total assets	$	2,423	$	823	$	230	$	9	$	3,485
Liabilities:
Price risk management instruments
(Note 7)
Electricity	$	59	$	11	$	188	$	(70)	$	188
Gas		-		1		-		-		1
Total liabilities	$	59	$	12	$	188	$	(70)	$	189

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

(2) Represents amount before deducting $347 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)
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)
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 three months ended March 31, 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 CAISO-imposed congestion charges in the day-ahead market. CRRs are classified as Level 3 and are valued based on CRR auction prices, including historical prices. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility uses models to forecast CRR prices for those periods not covered in the auctions.

Level 3 Measurements and Sensitivity Analysis

The Utility’s market and credit risk management function, which reports to the Chief Risk Officer of the Utility, is responsible for determining the fair value of the Utility’s price risk management derivatives. The Utility’s finance and risk management functions collaborate to determine the appropriate fair value methodologies and classification for each derivative. Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.

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)	March 31, 2015				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	230	$	64	Market approach	CRR auction prices	$	(15.97) - 8.17
Power purchase agreements	$	-	$	124	Discounted cash flow	Forward prices	$	15.56 - 47.26

(1) Represents price per megawatt-hour

	Fair Value at
(in millions)	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 months ended March 31, 2015 and 2014:

	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)		(27)		8
Asset (liability) balance as of March 31	$	42	$	(22)

(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.

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 March 31, 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 March 31, 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 March 31, 2015				At December 31, 2014
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
PG&E Corporation	$	350	$	354	$	350	$	352
Utility		13,779		16,324		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 March 31, 2015
Nuclear decommissioning trusts
Money market investments	$	29	$	-	$	-	$	29
Global Equity securities		536		1,109		(13)		1,632
Fixed Income securities		1,133		82		(3)		1,212
Total nuclear decommissioning trusts (1)		1,698		1,191		(16)		2,873
Total	$	1,698	$	1,191	$	(16)	$	2,873
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 $347 million and $324 million at March 31, 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)	March 31, 2015
Less than 1 year	$	25
1–5 years		450
5–10 years		257
More than 10 years		480
Total maturities of debt securities	$	1,212

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

	Three Months Ended
	March 31, 2015		March 31, 2014
(in millions)
Proceeds from sales and maturities of nuclear decommissioning trust
investments	$	417	$	530
Gross realized gains on sales of securities held as available-for-sale		35		56
Gross realized losses on sales of securities held as available-for-sale		(3)		(1)

NOTE 9: CONTINGENCIES AND COMMITMENTS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows also may be affected by the outcome of the following matters.

Enforcement and Litigation Matters

CPUC Investigations Related to Natural Gas Transmission

The penalties, to be funded by shareholders, are 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. 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.

For the three months ended March 31, 2015, the Utility recorded additional charges of $553 million as a result of the Penalty Decision. The cumulative charges at March 31, 2015, and the anticipated future financial impact are shown in the following table:

					Anticipated
	Three Months		Cumulative		Future
	Ended		Charges		Financial		Total
(in millions)	March 31, 2015		March 31, 2015		Impact		Amount
Fine payable to the state (1)	$	100	$	300	$	-	$	300
Customer bill credit		400		400		-		400
Charge for disallowed capital (2)		53		53		636		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	$	553	$	773	$	827	$	1,600

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

(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 $53 million of capital spending in the three months ended March 31, 2015, is 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 March 31, 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 March 31, 2015, Condensed Consolidated Statements of Income. 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.

Improper CPUC Communications

In the Penalty Decision (discussed above), 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.

The Utility also 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. (The ORA, TURN, and the City of San Bruno have asked the CPUC to reconsider its decision contending that the applicable law supports the imposition of a fine ranging from $2.5 million to $250 million.) In addition, the CPUC disallowed the Utility from recovering up to the entire amount of the revenue increase that may be authorized in the GT&S rate case and that otherwise would have been collected from ratepayers over a five-month period. The Utility has asked the CPUC to reconsider its decision. The exact amount of any revenue disallowance will be determined in the CPUC’s final decision in the GT&S rate case that is scheduled to be issued in August 2015.

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.

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 19-22, 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. 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 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.

Potential Safety Citations

The SED periodically audits utility operating practices, conducts investigations of potential violations, and has authority to issue citations and impose fines on the utilities for violations of applicable laws and regulations. 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 identified through the Utility’s self-reports, SED investigations and audits. The Utility believes it is probable that the SED will impose fines or take other enforcement action based on some of the Utility’s remaining self-reports or based on allegations 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 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 and State 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 replacing the indictment that had been returned on April 1, 2014. The superseding indictment charges 27 felony counts alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record keeping, pipeline integrity management, and identification of pipeline threats. The superseding indictment also includes one felony count charging that the Utility illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident. The maximum statutory fine for each felony count is $500,000, for total fines of $14 million. The superseding indictment also seeks an alternative fine under the Alternative Fines Act which states, in part: “If any person derives pecuniary gain from the offense, or if the offense results in pecuniary loss to a person other than the defendant, the defendant may be fined not more than the greater of twice the gross gain or twice the gross loss.” Based on the superseding indictment’s allegations that the Utility derived gross gains of approximately $281 million and that the victims suffered losses of approximately $565 million, the maximum alternate fine would be approximately $1.13 billion.

The Utility entered a plea of not guilty. The Utility believes that criminal charges and the alternate fine allegations are not merited and that it did not knowingly and willfully violate minimum safety standards under the Natural Gas Pipeline Safety Act or obstruct the NTSB’s investigation, as alleged in the superseding indictment.

The trial is set to begin March 8, 2016. PG&E Corporation and the Utility have not accrued any charges for criminal fines in their Condensed Consolidated Financial Statements as such amounts are not considered to be probable.

Other Federal and State Matters

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 (see “Improper CPUC Communications” above). The Utility is cooperating with the federal and state investigators. It is uncertain whether any charges will be brought against the Utility. In addition, 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 Annual Report on 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 March 31, 2015, approximately $600 million of PSEP-related capital costs is recorded in property, plant, and equipment on the Condensed Consolidated Balance Sheets. The Utility would be required to record charges in future periods to the extent PSEP-related capital costs are higher than currently expected.

Other Legal and Regulatory Contingencies

Accruals for other legal and regulatory contingencies (excluding amounts related to the enforcement and litigation matters described above) totaled $39 million at March 31, 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)	March 31, 2015		December 31, 2014
Topock natural gas compressor station (1)	$	298	$	291
Hinkley natural gas compressor station (1)		153		158
Former manufactured gas plant sites owned by the Utility or third parties		257		257
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites		159		150
Fossil fuel-fired generation facilities and sites		98		98
Total environmental remediation liability	$	965	$	954

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

At March 31, 2015 the Utility expected to recover $677 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC. One of these mechanisms allows the Utility rate recovery for 90% of its hazardous substance remediation costs for certain approved sites (including the Topock site) without a reasonableness review. The Utility 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 subject to the regulatory authority of the Regional Board. On January 22, 2015, the Regional Board issued a preliminary draft clean-up and abatement order that proposes that the Utility continue and improve its remedial treatment methods evaluated in the environmental report, along with a proposed monitoring and reporting program and proposed deadlines in 2021 and 2026 to meet specified interim clean-up targets. The Regional Board is tentatively scheduled to consider final adoption of the clean-up and abatement order at its September 2015 meeting.

The Utility’s environmental remediation liability at March 31, 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 subject to the regulatory authority of the California Department of Toxic Substances Control and the U.S. Department of the Interior. In September 2014, the Utility submitted its 90% remedial design plan to regulatory authorities and expects to submit its final remedial design plan in mid-2015, which would seek approval to begin construction of an in-situ groundwater treatment system that will convert hexavalent chromium into a non-toxic and non-soluble form of chromium. The Utility has implemented interim remediation measures, including a system of extraction wells and a treatment plant designed to prevent movement of the chromium plume toward the Colorado River. The Utility's environmental remediation liability at March 31, 2015 reflects its best estimate of probable future costs associated with its final remediation plan. Future costs will depend on many factors, including the extent of work to be performed to implement the final groundwater remedy and the Utility's required time frame for remediation. Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition and cash flows.

Reasonably Possible Environmental Contingencies

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, the Utility’s undiscounted future costs could increase to as much as $1.8 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 three months ended March 31, 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 March 31, 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 three months ended March 31, 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. The Utility disclosed its commitments at December 31, 2014 in Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2014 Form 10-K. The Utility has not entered into any new material commitments during the three months ended March 31, 2015.

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.

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. The penalties, to be funded by shareholders, are 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. PG&E Corporation’s and the Utility’s financial results for the three months ended March 31, 2015, reflect various charges associated with the Penalty Decision as discussed below.

Summary of Changes in Net Income and Earnings per Share

PG&E Corporation’s financial results for the three months ended March 31, 2015 reflect an increase in the Utility’s revenues, as authorized in the CPUC’s final decision issued in the Utility’s 2014 GRC on August 14, 2014 and various changes associated with the Penalty Decision issued on April 9, 2015.

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

			EPS
(in millions, except per share amounts)	Earnings		(Diluted)
Income Available for Common Shareholders - March 31, 2014	$	227	$	0.49
2014 GRC cost recovery (1)		99		0.21
Growth in rate base earnings (2)		26		0.05
Nuclear refueling outage		26		0.05
Timing of taxes (3)		20		0.04
Gain on disposition of SolarCity stock		14		0.03
Fines and penalties (4)		(369)		(0.77)
Timing of 2015 GT&S cost recovery (5)		(36)		(0.08)
Increase in shares outstanding (6)		-		(0.02)
Other		24		0.06
Income Available for Common Shareholders - March 31, 2015	$	31	$	0.06

(1) Represents the increase in base revenues authorized by the CPUC in the 2014 GRC decision for the three months ended March 31, 2015, including the impact of flow-through ratemaking treatment for federal tax deductions for repairs. In 2013, the Utility incurred approximately $200 million of expense and $1 billion of capital costs above authorized levels. The 2014 GRC decision authorized revenues that support this higher level of spending during 2014 and throughout the GRC period. The increase in revenue related to 2014 was not recognized until the quarter ended September 30, 2014, when the 2014 GRC decision was issued.

(2) Represents the impact of the increase in rate base as authorized in various rate cases during the three months ended March 31, 2015 as compared to the same period in 2014.

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

(4) Represents the impact during the three months ended March 31, 2015 of the Penalty Decision issued on April 9, 2015. See “Enforcement and Litigation Matters” below.

(5) Represents expenses during the three months ended March 31, 2015 requested in the GT&S rate case with no corresponding increase in revenue. The Utility’s 2015 GT&S request to increase revenues is pending a CPUC decision. After a final decision is issued, the Utility will be authorized to collect any increase in revenue requirements from January 1, 2015.

(6) Represents the impact of a higher number of weighted average shares of common stock outstanding during the three months ended March 31, 2015 as compared to the same periods in 2014. PG&E Corporation issues shares to fund its equity contributions to the Utility to maintain the Utility’s capital structure and fund operations, including unrecovered expenses.

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 costs the Utility incurs for designated pipeline safety projects and programs and to implement remedial measures, as required by the Penalty Decision. The Utility also could incur fines associated with pending federal criminal charges that the Utility knowingly and willfully violated the Pipeline Safety Act and illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident. 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” below.)

•	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. In response to the Utility’s violations of the CPUC’s rules regarding ex parte communications relating to the 2015 GT&S rate case, the CPUC issued a decision to disallow up to five months of the GT&S incremental revenues that would otherwise be authorized in the final decision, which is scheduled to be issued in August 2015. The Utility and other parties have filed applications requesting the CPUC to reconsider this decision. It is uncertain whether this decision will be upheld and what amount of GT&S revenue requirements will ultimately be authorized. In addition, the Utility has a TO rate case pending at the FERC. 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, including costs to identify and remove encroachments from transmission pipeline rights-of-way to perform and to perform continuing work under the Utility’s PSEP. 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 calculating 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 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 three months ended March 31, 2015, PG&E Corporation issued $151 million of common stock and made equity contributions to the Utility of $100 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 penalties that 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.