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

REGULATORY MATTERS

LEGISLATIVE AND REGULATORY INITIATIVES

ENVIRONMENTAL MATTERS

CONTRACTUAL COMMITMENTS

RISK MANAGEMENT ACTIVITIES

CRITICAL ACCOUNTING POLICIES

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

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.

2016 Form 10-K	PG&E Corporation and Pacific Gas and Electric Company's combined Annual Report on Form 10-K for the year ended December 31, 2016
AB	Assembly Bill
AFUDC	allowance for funds used during construction
ALJ	administrative law judge
ARO	asset retirement obligation
ASU	accounting standard update issued by the FASB (see below)
CAISO	California Independent System Operator
Cal Fire	California Department of Forestry and Fire Protection
CARB	California Air Resources Board
CCA	Community Choice Aggregator
Central Coast Board	Central Coast Regional Water Quality Control Board
CEC	California Energy Resources Conservation and Development Commission
CO2	carbon dioxide
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
DER	distributed energy resources
Diablo Canyon	Diablo Canyon nuclear power plant
DOE	U.S. Department of Energy
DOGGR	Division of Oil, Gas, and Geothermal Resources
DOI	U.S. Department of the Interior
DTSC	Department of Toxic Substances Control
EMANI	European Mutual Association for Nuclear Insurance
EPA	Environmental Protection Agency
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
GHG	greenhouse gas
GRC	general rate case
GT&S	gas transmission and storage
GWH	gigawatt-hours
IOU(s)	investor-owned utility(ies)
IRS	Internal Revenue Service
LTIP	long-term incentive plan
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Item 2, of this Form 10-Q
MOU	memorandum of understanding
NAV	net asset value
NDCTP	Nuclear Decommissioning Cost Triennial Proceedings
NEIL	Nuclear Electric Insurance Limited
NEM	net energy metering
NERC	North American Electric Reliability Corporation
NRC	Nuclear Regulatory Commission
NTSB	National Transportation Safety Board
OEM	original equipment manufacturer
OII	order instituting investigation
ORA	Office of Ratepayer Advocates

PD	proposed decision
PHSMA	Pipeline and Hazardous Materials Safety Administration
QF	qualifying facility
Regional Board	California Regional Water Quality Control Board, Lahontan Region
RFO	requests for offers
ROE	return on equity
RPS	renewable portfolio standards
SB	Senate Bill
SEC	U.S. Securities and Exchange Commission
SED	Safety and Enforcement Division of the CPUC
TE	transportation electrification
TO	transmission owner
TURN	The Utility Reform Network
Utility	Pacific Gas and Electric Company
VIE(s)	variable interest entity(ies)
WECC	Western Electricity Coordinating Council
Westinghouse	Westinghouse Electric Company, LLC

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)	2017		2016
Operating Revenues
Electric	$	3,065	$	3,131
Natural gas		1,203		843
Total operating revenues		4,268		3,974
Operating Expenses
Cost of electricity		847		950
Cost of natural gas		325		222
Operating and maintenance		1,504		2,010
Depreciation, amortization, and decommissioning		712		697
Total operating expenses		3,388		3,879
Operating Income		880		95
Interest income		5		4
Interest expense		(218)		(203)
Other income, net		21		27
Income (Loss) Before Income Taxes		688		(77)
Income tax provision (benefit)		109		(187)
Net Income		579		110
Preferred stock dividend requirement of subsidiary		3		3
Income Available for Common Shareholders	$	576	$	107
Weighted Average Common Shares Outstanding, Basic		508		493
Weighted Average Common Shares Outstanding, Diluted		511		495
Net Earnings Per Common Share, Basic	$	1.13	$	0.22
Net Earnings Per Common Share, Diluted	$	1.13	$	0.22
Dividends Declared Per Common Share	$	0.49	$	0.46

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2017		2016
Net Income	$	579	$	110
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		579		110
Preferred stock dividend requirement of subsidiary		3		3
Comprehensive Income Attributable to Common Shareholders	$	576	$	107

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Balance At
	March 31,		December 31,
(in millions)	2017		2016
ASSETS
Current Assets
Cash and cash equivalents	$	164	$	177
Restricted cash		7		7
Accounts receivable:
Customers (net of allowance for doubtful accounts of $59 and $58
at respective dates)		1,197		1,252
Accrued unbilled revenue		773		1,098
Regulatory balancing accounts		1,655		1,500
Other		799		801
Regulatory assets		486		423
Inventories:
Gas stored underground and fuel oil		96		117
Materials and supplies		369		346
Income taxes receivable		160		160
Other		274		283
Total current assets		5,980		6,164
Property, Plant, and Equipment
Electric		53,074		52,556
Gas		18,045		17,853
Construction work in progress		2,446		2,184
Other		2		2
Total property, plant, and equipment		73,567		72,595
Accumulated depreciation		(22,487)		(22,014)
Net property, plant, and equipment		51,080		50,581
Other Noncurrent Assets
Regulatory assets		8,089		7,951
Nuclear decommissioning trusts		2,701		2,606
Income taxes receivable		70		70
Other		1,244		1,226
Total other noncurrent assets		12,104		11,853
TOTAL ASSETS	$	69,164	$	68,598

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)	2017		2016
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	763	$	1,516
Long-term debt, classified as current		700		700
Accounts payable:
Trade creditors		1,117		1,495
Regulatory balancing accounts		908		645
Other		632		433
Disputed claims and customer refunds		236		236
Interest payable		168		216
Other		2,014		2,323
Total current liabilities		6,538		7,564
Noncurrent Liabilities
Long-term debt		16,813		16,220
Regulatory liabilities		6,991		6,805
Pension and other postretirement benefits		2,666		2,641
Asset retirement obligations		4,716		4,684
Deferred income taxes		10,488		10,213
Other		2,347		2,279
Total noncurrent liabilities		44,021		42,842
Commitments and Contingencies (Note 9)
Equity
Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares;
510,610,267 and 506,891,874 shares outstanding at respective dates		12,292		12,198
Reinvested earnings		6,070		5,751
Accumulated other comprehensive loss		(9)		(9)
Total shareholders' equity		18,353		17,940
Noncontrolling Interest - Preferred Stock of Subsidiary		252		252
Total equity		18,605		18,192
TOTAL LIABILITIES AND EQUITY	$	69,164	$	68,598

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2017		2016
Cash Flows from Operating Activities
Net income	$	579	$	110
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		712		697
Allowance for equity funds used during construction		(19)		(27)
Deferred income taxes and tax credits, net		252		117
Disallowed capital expenditures		-		87
Other		8		73
Effect of changes in operating assets and liabilities:
Accounts receivable		373		210
Butte-related insurance receivable		(7)		-
Inventories		(2)		(14)
Accounts payable		(13)		(65)
Butte-related third-party claims		(44)		-
Income taxes receivable/payable		-		(75)
Other current assets and liabilities		(137)		179
Regulatory assets, liabilities, and balancing accounts, net		(176)		(87)
Other noncurrent assets and liabilities		48		(117)
Net cash provided by operating activities		1,574		1,088
Cash Flows from Investing Activities
Capital expenditures		(1,216)		(1,229)
Proceeds from sales and maturities of nuclear decommissioning
trust investments		470		439
Purchases of nuclear decommissioning trust investments		(493)		(463)
Other		4		3
Net cash used in investing activities		(1,235)		(1,250)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $2
and $1 at respective dates		(755)		(577)
Short-term debt financing		250		250
Short-term debt matured		(250)		-
Proceeds from issuance of long-term debt, net of discount and
issuance costs of $10 and $6 at respective dates		590		594
Common stock issued		146		146
Common stock dividends paid		(243)		(219)
Other		(90)		(13)
Net cash provided by (used in) financing activities		(352)		181
Net change in cash and cash equivalents		(13)		19
Cash and cash equivalents at January 1		177		123
Cash and cash equivalents at March 31	$	164	$	142

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(246)	$	(242)
Income taxes, net		1		-
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	250	$	226
Capital expenditures financed through accounts payable		237		373
Noncash common stock issuances		4		6

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)	2017		2016
Operating Revenues
Electric	$	3,067	$	3,132
Natural gas		1,204		843
Total operating revenues		4,271		3,975
Operating Expenses
Cost of electricity		847		950
Cost of natural gas		325		222
Operating and maintenance		1,504		2,011
Depreciation, amortization, and decommissioning		712		696
Total operating expenses		3,388		3,879
Operating Income		883		96
Interest income		5		4
Interest expense		(216)		(201)
Other income, net		17		24
Income (Loss) Before Income Taxes		689		(77)
Income tax provision (benefit)		120		(185)
Net Income		569		108
Preferred stock dividend requirement		3		3
Income Available for Common Stock	$	566	$	105

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

	(Unaudited)
	Three Months Ended March 31,
(in millions)	2017		2016
Net Income	$	569	$	108
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $0 and $0, at respective dates )		1		-
Total other comprehensive income (loss)		1		-
Comprehensive Income	$	570	$	108

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

	(Unaudited)
	Balance At
	March 31,		December 31,
(in millions)	2017		2016
ASSETS
Current Assets
Cash and cash equivalents	$	60	$	71
Restricted cash		7		7
Accounts receivable:
Customers (net of allowance for doubtful accounts of $59 and $58
at respective dates)		1,197		1,252
Accrued unbilled revenue		773		1,098
Regulatory balancing accounts		1,655		1,500
Other		850		801
Regulatory assets		486		423
Inventories:
Gas stored underground and fuel oil		96		117
Materials and supplies		369		346
Income taxes receivable		159		159
Other		274		282
Total current assets		5,926		6,056
Property, Plant, and Equipment
Electric		53,074		52,556
Gas		18,045		17,853
Construction work in progress		2,446		2,184
Total property, plant, and equipment		73,565		72,593
Accumulated depreciation		(22,485)		(22,012)
Net property, plant, and equipment		51,080		50,581
Other Noncurrent Assets
Regulatory assets		8,089		7,951
Nuclear decommissioning trusts		2,701		2,606
Income taxes receivable		70		70
Other		1,125		1,110
Total other noncurrent assets		11,985		11,737
TOTAL ASSETS	$	68,991	$	68,374

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)	2017		2016
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	763	$	1,516
Long-term debt, classified as current		700		700
Accounts payable:
Trade creditors		1,117		1,494
Regulatory balancing accounts		908		645
Other		661		453
Disputed claims and customer refunds		236		236
Interest payable		167		214
Other		1,774		2,072
Total current liabilities		6,326		7,330
Noncurrent Liabilities
Long-term debt		16,464		15,872
Regulatory liabilities		6,991		6,805
Pension and other postretirement benefits		2,572		2,548
Asset retirement obligations		4,716		4,684
Deferred income taxes		10,793		10,510
Other		2,286		2,230
Total noncurrent liabilities		43,822		42,649
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		8,175		8,050
Reinvested earnings		9,085		8,763
Accumulated other comprehensive income		3		2
Total shareholders' equity		18,843		18,395
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	68,991	$	68,374

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)	2017		2016
Cash Flows from Operating Activities
Net income	$	569	$	108
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		712		696
Allowance for equity funds used during construction		(19)		(27)
Deferred income taxes and tax credits, net		264		118
Disallowed capital expenditures		-		87
Other		57		68
Effect of changes in operating assets and liabilities:
Accounts receivable		322		183
Butte-related insurance receivable		(7)		-
Inventories		(2)		(14)
Accounts payable		(3)		(37)
Butte-related third-party claims		(44)		-
Income taxes receivable/payable		-		(74)
Other current assets and liabilities		(113)		184
Regulatory assets, liabilities, and balancing accounts, net		(176)		(87)
Other noncurrent assets and liabilities		38		(109)
Net cash provided by operating activities		1,598		1,096
Cash Flows from Investing Activities
Capital expenditures		(1,216)		(1,229)
Proceeds from sales and maturities of nuclear decommissioning
trust investments		470		439
Purchases of nuclear decommissioning trust investments		(493)		(463)
Other		4		3
Net cash used in investing activities		(1,235)		(1,250)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $2
and $1 at respective dates		(755)		(577)
Short-term debt financing		250		250
Short-term debt matured		(250)		-
Proceeds from issuance of long-term debt, net of discount and
issuance costs of $10 and $6 at respective dates		590		594
Preferred stock dividends paid		(3)		(3)
Common stock dividends paid		(244)		(179)
Equity contribution from PG&E Corporation		125		65
Other		(87)		(11)
Net cash provided by (used in) financing activities		(374)		139
Net change in cash and cash equivalents		(11)		(15)
Cash and cash equivalents at January 1		71		59
Cash and cash equivalents at March 31	$	60	$	44

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(242)	$	(237)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	237	$	373

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 serving northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.

This quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and 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 assess financial performance and allocate resources on a consolidated basis (i.e., the companies 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’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information at December 31, 2016 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in the 2016 Form 10-K. This quarterly report should be read in conjunction with the 2016 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, insurance recoveries, environmental remediation liabilities, AROs, 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. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations during the period in which such change occurred.

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 2016 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 has a controlling interest or was the primary beneficiary of any of these VIEs at March 31, 2017, the Utility 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, 2017, 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 months ended March 31, 2017 and 2016 were as follows:

	Pension Benefits				Other Benefits
	Three Months Ended March 31,
(in millions)	2017		2016		2017		2016
Service cost for benefits earned	$	118	$	113	$	15	$	13
Interest cost		179		179		19		19
Expected return on plan assets		(193)		(207)		(24)		(27)
Amortization of prior service cost		(2)		2		4		4
Amortization of net actuarial loss		6		6		1		1
Net periodic benefit cost		108		93		15		10
Regulatory account transfer (1)		(23)		(8)		-		-
Total	$	85	$	85	$	15	$	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 (Loss)

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 March 31, 2017
Beginning balance	$	(25)	$	16	$	(9)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost
(net of taxes of $1 and $2, respectively)		(1)		2		1
Amortization of net actuarial loss
(net of taxes of $3 and $0, respectively)		3		1		4
Regulatory account transfer
(net of taxes of $2 and $2, respectively)		(2)		(3)		(5)
Net current period other comprehensive gain (loss)		-		-		-
Ending balance	$	(25)	$	16	$	(9)

(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
	Benefits		Benefits		Total
(in millions, net of income tax)	Three Months Ended March 31, 2016
Beginning balance	$	(23)	$	16	$	(7)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost
(net of taxes of $1 and $2, respectively)		1		2		3
Amortization of net actuarial loss
(net of taxes of $2, and $0, respectively)		4		1		5
Regulatory account transfer
(net of taxes of $3 and $2, respectively)		(5)		(3)		(8)
Net current period other comprehensive gain (loss)		-		-		-
Ending balance	$	(23)	$	16	$	(7)

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

Recently Adopted Accounting Guidance

Share-Based Payment Accounting

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718), which amends the existing guidance relating to the accounting for share-based payment awards issued to employees, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statements of cash flows. PG&E Corporation and the Utility have adopted this standard as of the fourth quarter of 2016.

ASU 2016-09 requires, on a retrospective basis, that employee taxes paid for withheld shares be classified as cash flows from financing activities rather than as cash flows from operating activities. As such, the Condensed Consolidated Statements of Cash Flows for PG&E Corporation and the Utility for the prior periods presented were restated. This change resulted in an increase to cash flows from operating activities and a decrease to cash flows from financing activities of $32.6 million for the three months ended March 31, 2016.

Accounting Standards Issued But Not Yet Adopted

Presentation of Net Periodic Pension Cost

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715), which amends the existing guidance relating to the presentation of net periodic pension cost and net periodic postretirement benefit cost. The amendment requires an employer to disaggregate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement. In addition, on a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.

Restricted Cash

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows – Restricted Cash (Topic 230), which amends the existing guidance relating to the disclosure of restricted cash and restricted cash equivalents on the statement of cash flows. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018, with early adoption permitted. As of March 31, 2017, PG&E Corporation and the Utility held immaterial balances within restricted cash. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Statements of Cash Flows and related disclosures.

Recognition of Lease Assets and Liabilities

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the existing guidance relating to the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheet, which were previously not recognized. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019 and will be applied on a modified retrospective basis. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which amends the existing guidance relating to the recognition, measurement, presentation, and disclosure of financial instruments. The amendments require equity investments (excluding those accounted for under the equity method or those that result in consolidation) to be measured at fair value, with changes in fair value recognized in net income. The majority of investments held by PG&E Corporation and the Utility are classified as “available-for-sale” and gains or losses are refundable, or recoverable, from customers through rates. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2018. PG&E Corporation and the Utility do not anticipate a material impact to their Condensed Consolidated Financial Statements and related disclosures as a result of this ASU.

Revenue Recognition Standard

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which amends existing revenue recognition guidance, effective January 1, 2018. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements. PG&E Corporation and the Utility intend to use the modified retrospective method when adopting the new standard on January 1, 2018. PG&E Corporation and the Utility are currently reviewing all revenue streams and evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.

While the Utility expects that most of its revenue will be included in the scope of ASU 2014-09, it has not yet fully completed its evaluation. The majority of the Utility’s revenue, including energy provided to customers, is from tariff offerings that provide natural gas or electricity without a defined contractual term. For such arrangements, the Utility generally expects that the revenue from contracts with these customers will continue to be equivalent to the electricity or natural gas supplied and billed in that period (including unbilled revenues) and the adoption of the new guidance will not result in a significant shift in the timing of revenue recognition for such sales. The Utility continues to consider the impacts of outstanding industry-related issues being addressed by the American Institute of CPAs’ Revenue Recognition Working Group and the FASB’s Transition Resource Group. Additionally, the Utility expects more detailed revenue disclosures related to the nature, timing and uncertainty in revenues upon adoption of ASU 2014-09.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Long-term regulatory assets are comprised of the following:

	Balance at
(in millions)	March 31, 2017		December 31, 2016
Pension benefits	$	2,448	$	2,429
Deferred income taxes		4,049		3,859
Utility retained generation		352		364
Environmental compliance costs		716		778
Price risk management		92		92
Unamortized loss, net of gain, on reacquired debt		72		76
Other		360		353
Total long-term regulatory assets	$	8,089	$	7,951

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 Form 10-K.

Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Balance at
(in millions)	March 31, 2017		December 31, 2016
Cost of removal obligations	$	5,186	$	5,060
Recoveries in excess of AROs		682		626
Public purpose programs		546		567
Other		577		552
Total long-term regulatory liabilities	$	6,991	$	6,805

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 Form 10-K.

Regulatory Balancing Accounts

Current regulatory balancing accounts receivable and payable are comprised of the following:

	Receivable
	Balance at
(in millions)	March 31, 2017		December 31, 2016
Electric distribution	$	339	$	132
Electric transmission		235		244
Utility generation		248		48
Gas distribution and transmission		323		541
Energy procurement		7		132
Public purpose programs		116		106
Other		387		297
Total regulatory balancing accounts receivable	$	1,655	$	1,500

	Payable
	Balance at
(in millions)	March 31, 2017		December 31, 2016
Electric transmission	$	202	$	99
Gas distribution and transmission		30		48
Energy procurement		102		13
Public purpose programs		334		264
Other		240		221
Total regulatory balancing accounts payable	$	908	$	645

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 Form 10-K.

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, 2017:

					Letters of
	Termination	Facility			Credit		Commercial		Facility
(in millions)	Date	Limit			Outstanding		Paper		Availability
PG&E Corporation	April 2021	$	300	(1)	$	-	$	-	$	300
Utility	April 2021		3,000	(2)		40		263		2,697
Total revolving credit facilities		$	3,300		$	40	$	263	$	2,997

(1) Includes a $50 million lender commitment to the letter of credit sublimit 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 lender commitment to the letter of credit sublimit and a $75 million commitment for swingline loans.

Other Short-term Borrowings

In February 2017, the Utility’s $250 million floating rate unsecured term loan, issued in March 2016, matured and was repaid.

Additionally, in February 2017, the Utility entered into a $250 million floating rate unsecured term loan that matures on February 22, 2018. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.

Senior Notes Issuances

In March 2017, the Utility issued $400 million principal amount of 3.30% Senior Notes due March 15, 2027 and $200 million principal amount of 4.00% Senior Notes due December 1, 2046. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.

Variable Rate Interest

At March 31, 2017, 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 0.83% to 0.90%. At March 31, 2017, the interest rates on the $149 million principal amount of pollution control bonds Series 2009 A and B, and the related loan agreements, were 0.86%.

NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the three months ended March 31, 2017 were as follows:

	PG&E Corporation		Utility
	Total		Total
(in millions)	Equity		Shareholders' Equity
Balance at December 31, 2016	$	18,192	$	18,395
Comprehensive income		579		570
Equity contributions		-		125
Common stock issued		150		-
Share-based compensation		(56)		-
Common stock dividends declared		(257)		(244)
Preferred stock dividend requirement		-		(3)
Preferred stock dividend requirement of subsidiary		(3)		-
Balance at March 31, 2017	$	18,605	$	18,843

In February 2017, PG&E Corporation amended its February 2015 equity distribution agreement providing for the sale of PG&E Corporation common stock having an aggregate gross price of up to $275 million. During the three months ended March 31, 2017, PG&E Corporation sold 0.4 million shares of its common stock under the February 2017 equity distribution agreement for cash proceeds of $28 million, net of commissions paid of $0.2 million. As of March 31, 2017, the remaining gross sales available under this agreement were $246 million.

PG&E Corporation also issued common stock under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans. During the three months ended March 31, 2017, 3.3 million shares were issued for cash proceeds of $117 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)	2017		2016
Income available for common shareholders	$	576	$	107
Weighted average common shares outstanding, basic		508		493
Add incremental shares from assumed conversions:
Employee share-based compensation		3		2
Weighted average common shares outstanding, diluted		511		495
Total earnings per common share, diluted	$	1.13	$	0.22

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 contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

Derivatives are presented in the Utility’s Condensed Consolidated Balance Sheets recorded at fair value and 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 PG&E Corporation’s and the Utility’s 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 under the applicable ratemaking mechanism in place as long as 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
		March 31,	December 31,
Underlying Product	Instruments	2017	2016
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	271,615,354	323,301,331
	Options	67,861,423	96,602,785
Electricity (Megawatt-hours)	Forwards, Futures and Swaps	3,233,931	3,287,397
	Congestion Revenue Rights (3)	261,738,949	278,143,281

(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 March 31, 2017, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
	Gross Derivative						Total Derivative
(in millions)	Balance		Netting		Cash Collateral		Balance
Current assets – other	$	63	$	(16)	$	17	$	64
Other noncurrent assets – other		134		(5)		-		129
Current liabilities – other		(56)		16		2		(38)
Noncurrent liabilities – other		(97)		5		13		(79)
Total commodity risk	$	44	$	-	$	32	$	76

At December 31, 2016, 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	$	91	$	(10)	$	1	$	82
Other noncurrent assets – other		149		(9)		-		140
Current liabilities – other		(48)		10		-		(38)
Noncurrent liabilities – other		(101)		9		3		(89)
Total commodity risk	$	91	$	-	$	4	$	95

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

	Commodity Risk
	Three Months Ended March 31
(in millions)	2017		2016
Net unrealized gain (loss) - regulatory assets and liabilities (1)	$	(48)	$	(7)
Realized loss - cost of electricity (2)		(5)		(29)
Realized loss - cost of natural gas (2)		(1)		(1)
Total commodity risk	$	(54)	$	(37)

(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, 2017, 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)	2017		2016
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(35)	$	(24)
Related derivatives in an asset position		3		19
Collateral posting in the normal course of business related to
these derivatives		31		4
Net position of derivative contracts/additional collateral
posting requirements (1)	$	(1)	$	(1)

(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, and price risk management instruments 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 are held by PG&E Corporation and not the Utility.

	Fair Value Measurements
	At March 31, 2017
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	104	$	-	$	-	$	-	$	104
Nuclear decommissioning trusts
Short-term investments		8		-		-		-		8
Global equity securities		1,762		-		-		-		1,762
Fixed-income securities		721		553		-		-		1,274
Assets measured at NAV		-		-		-		-		15
Total nuclear decommissioning trusts (2)		2,491		553		-		-		3,059
Price risk management instruments
(Note 7)
Electricity		13		12		166		(6)		185
Gas		1		5		-		2		8
Total price risk management
instruments		14		17		166		(4)		193
Rabbi trusts
Fixed-income securities		-		62		-		-		62
Life insurance contracts		-		70		-		-		70
Total rabbi trusts		-		132		-		-		132
Long-term disability trust
Short-term investments		5		-		-		-		5
Assets measured at NAV		-		-		-		-		163
Total long-term disability trust		5		-		-		-		168
TOTAL ASSETS	$	2,614	$	702	$	166	$	(4)	$	3,656
Liabilities:
Price risk management instruments
(Note 7)
Electricity	$	14	$	21	$	117	$	(36)	$	116
Gas		-		1		-		-		1
TOTAL LIABILITIES	$	14	$	22	$	117	$	(36)	$	117

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

(2) Represents amount before deducting $358 million, primarily related to deferred taxes on appreciation of investment value.

	Fair Value Measurements
	At December 31, 2016
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	105	$	-	$	-	$	-	$	105
Nuclear decommissioning trusts
Short-term investments		9		-		-		-		9
Global equity securities		1,724		-		-		-		1,724
Fixed-income securities		665		527		-		-		1,192
Assets measured at NAV		-		-		-		-		14
Total nuclear decommissioning trusts (2)		2,398		527		-		-		2,939
Price risk management instruments
(Note 9 in the 2016 Form 10-K)
Electricity		30		18		181		(18)		211
Gas		-		11		-		-		11
Total price risk management
instruments		30		29		181		(18)		222
Rabbi trusts
Fixed-income securities		-		61		-		-		61
Life insurance contracts		-		70		-		-		70
Total rabbi trusts		-		131		-		-		131
Long-term disability trust
Short-term investments		8		-		-		-		8
Assets measured at NAV		-		-		-		-		170
Total long-term disability trust		8		-		-		-		178
TOTAL ASSETS	$	2,541	$	687	$	181	$	(18)	$	3,575
Liabilities:
Price risk management instruments
(Note 9 in the 2016 Form 10-K)
Electricity	$	9	$	12	$	126	$	(21)	$	126
Gas		-		2		-		(1)		1
TOTAL LIABILITIES	$	9	$	14	$	126	$	(22)	$	127

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

(2) Represents amount before deducting $333 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. There are no restrictions on the terms and conditions upon which the investments may be redeemed. 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, 2017 and 2016.

Trust Assets

Assets Measured at Fair Value

In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1.

Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1.

Fixed-income 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 fixed-income 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.

Assets Measured at NAV Using Practical Expedient

Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Condensed Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities.

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, 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 futures 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 futures, 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. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3.

Level 3 Measurements and Sensitivity Analysis

The Utility’s market and credit risk management function, which reports to the Chief Financial Officer, 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 March 31, 2017				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	166	$	30	Market approach	CRR auction prices	$	(11.88) - 11.14
Power purchase agreements	$	-	$	87	Discounted cash flow	Forward prices	$	18.07 - 38.80

(1) Represents price per megawatt-hour

	Fair Value at
(in millions)	At December 31, 2016				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	181	$	35	Market approach	CRR auction prices	$	(11.88) - 6.93
Power purchase agreements	$	-	$	91	Discounted cash flow	Forward prices	$	18.07 - 38.80

(1) Represents price per megawatt-hour

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the three months ended March 31, 2017 and 2016:

	Price Risk Management Instruments
(in millions)	2017		2016
Asset (liability) balance as of January 1	$	55	$	89
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		(6)		(14)
Asset (liability) balance as of March 31	$	49	$	75

(1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.

Financial Instruments

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

The fair values of cash, restricted cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at March 31, 2017 and December 31, 2016, 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, 2017 and December 31, 2016.

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, 2017				At December 31, 2016
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
PG&E Corporation	$	348	$	352	$	348	$	352
Utility		16,405		18,407		15,813		17,790

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, 2017
Nuclear decommissioning trusts
Short-term investments	$	8	$	-	$	-		$	8
Global equity securities		549		1,230		(2	)		1,777
Fixed-income securities		1,233		50		(9	)		1,274
Total (1)	$	1,790	$	1,280	$	(11	)	$	3,059
As of December 31, 2016
Nuclear decommissioning trusts
Short-term investments	$	9	$	-	$	-		$	9
Global equity securities		584		1,157		(3	)		1,738
Fixed-income securities		1,156		48		(12	)		1,192
Total (1)	$	1,749	$	1,205	$	(15	)	$	2,939

(1) Represents amounts before deducting $358 million and $333 million at March 31, 2017 and December 31, 2016, respectively, primarily related to deferred taxes on appreciation of investment value.

The fair value of fixed-income securities by contractual maturity is as follows:

	As of
(in millions)	March 31, 2017
Less than 1 year	$	13
1–5 years		444
5–10 years		302
More than 10 years		515
Total maturities of fixed-income securities	$	1,274

The following table provides a summary of activity for fixed income and equity securities:

	Three Months Ended
	March 31, 2017		March 31, 2016
(in millions)
Proceeds from sales and maturities of nuclear decommissioning trust
investments	$	470	$	439
Gross realized gains on sales of securities held as available-for-sale		29		5
Gross realized losses on sales of securities held as available-for-sale		(5)		(2)

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. A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. A gain contingency is recorded in the period in which all uncertainties have been resolved. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. For more information, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows may be materially affected by the outcome of the following matters.

Enforcement and Litigation Matters

Butte Fire Litigation

In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the wildfire. According to Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures. Cal Fire’s report concluded that the wildfire was caused when a gray pine tree contacted the Utility’s electric line which ignited portions of the tree, and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree. In March 2017, the Utility received a demand from Cal Fire indicating that it will seek to recover firefighting costs of $87 million from the Utility, and on April 13, 2017, Cal Fire filed a complaint with the Superior Court of the State of California, County of Calaveras, seeking to recover its costs on the theory that the Utility and its vegetation management contractors were negligent, among other claims. While the Utility believes it was not negligent, there can be no assurance that a court or jury would agree with the Utility. In addition, the Utility anticipates that other agencies, including the California Governor’s Office of Emergency Services and the County of Calaveras, may also submit claims against the Utility.

Also, on April 25, 2017, the SED issued two citations to the Utility in connection with the Butte fire, totaling $8.3 million. The SED’s investigation found that neither the Utility nor its vegetation management contractors took appropriate steps to prevent the gray pine from leaning and contacting the Utility’s electric line, which created an unsafe and dangerous condition that resulted in that tree leaning and making contact with the electric line, thus causing a fire. (See “Potential Safety Citations” below.)

As previously disclosed, on May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management contractors in the Superior Court of California for Sacramento County. Subrogation insurers also filed a separate master complaint on the same date. The California Judicial Council had previously authorized the coordination of all cases in Sacramento County. As of March 31, 2017, approximately 55 complaints have been filed against the Utility and its two vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador involving approximately 2,000 individual plaintiffs representing approximately 1,150 households and their insurance companies. These complaints are part of or are in the process of being added to the two master complaints. Plaintiffs seek to recover damages and other costs, principally based on inverse condemnation and negligence theories of liability. The number of individual complaints and plaintiffs may increase in the future. The Utility continues mediating and settling cases.

On April 14, 2017, the Superior Court of California for Sacramento County found that six “preference” households (households that include individuals who due to their age and/or physical condition are not likely to meaningfully participate in a trial under normal scheduling) are entitled to a trial no later than August 11, 2017. The court did not decide on the venue of the preference trial.

The court also set a representative trial date for October 30, 2017 in Sacramento. A representative trial is a trial where the parties agree, or the court decides, on plaintiffs who are “representative” of broader groups of plaintiffs such that the trial may assist the parties in settling other cases after obtaining verdicts in the representative trial. The next case management conference is scheduled for May 11, 2017.

In connection with this matter, the Utility may be liable for property damages, interest, and attorneys’ fees without having been found negligent, through the theory of inverse condemnation. In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent. The Utility believes that it is probable that it will incur a loss of at least $750 million for all potential damages described above. This amount is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the number and types of trees damaged or destroyed, as well as assumptions about personal injury damages, attorneys’ fees, fire suppression costs, and other damages that the Utility could be liable for under the theories of inverse condemnation and/or negligence.

The following table presents changes in the third-party claims liability since December 31, 2015. The balance for the third-party claims liability is included in Other current liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:

Loss Accrual (in millions)
Balance at December 31, 2015	$	-
Accrued losses		750
Payments		(60)
Balance at December 31, 2016	$	690
Accrued losses		-
Payments		(44)
Balance at March 31, 2017	$	646

In addition to the amounts reflected in the table above, the Utility has incurred cumulative legal expenses of $37 million. For the three months ended March 31, 2017, the Utility has incurred legal expenses of $10 million.

The Utility currently is unable to reasonably estimate the upper end of the range of losses because it is still in an early stage of the evaluation of claims, the mediation and settlement process, and discovery. The process for estimating costs associated with claims relating to the Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including additional discovery from the plaintiffs and results from the ongoing mediation and settlement process, management estimates and assumptions regarding the financial impact of the Butte fire may result in material increases to the loss accrued.

The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Butte fire in an aggregate amount of approximately $900 million. The Utility records insurance recoveries when it is deemed probable that a recovery will occur and the Utility can reasonably estimate the amount or its range. Through March 31, 2017, the Utility recorded $632 million for probable insurance recoveries in connection with losses related to the Butte fire. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries. In addition, the Utility is pursuing coverage under the insurance policies of its two vegetation management contractors, including under policies where the Utility is listed as an additional insured. Recoveries of any amounts under these policies are uncertain.

The following table presents changes in the insurance receivable since December 31, 2015. The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:

Insurance Receivable (in millions)
Balance at December 31, 2015	$	-
Accrued insurance recoveries		625
Insurance reimbursements		(50)
Balance at December 31, 2016	$	575
Accrued insurance recoveries		7
Insurance reimbursements		-
Balance at March 31, 2017	$	582

On April 28, 2017 the Utility received another $50 million in insurance reimbursements.

If the Utility records losses in connection with claims relating to the Butte fire that materially exceed the amount the Utility accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected in the reporting periods during which additional charges are recorded, depending on whether the Utility is able to record or collect insurance recoveries in amounts sufficient to offset such additional accruals.

CPUC Matters

Order Instituting an Investigation into Compliance with Ex Parte Communication Rules

On March 28, 2017, the Utility, the Cities of San Bruno and San Carlos, the ORA, the SED, and TURN (together, the “parties”) jointly submitted to the CPUC a settlement agreement in connection with the order instituting an investigation into the Utility’s compliance with the CPUC’s ex parte communication rules and jointly moved for its approval. As previously disclosed, the Utility has already incurred a disallowance of $72 million imposed by the CPUC in connection with certain ex parte communications in the Utility’s 2015 GT&S rate case. Of the $72 million total GT&S ex parte disallowance, $57 million was recognized in 2016 and the remaining $15 million was recognized in the first quarter of 2017.

Pursuant to the settlement agreement, the Utility agreed to a total financial remedy of $86.5 million comprised of: (1) a $1 million payment to the California General Fund, (2) forgoing collection of $63.5 million of GT&S revenue requirements for the years 2018 ($31.75 million) and 2019 ($31.75 million), (3) a $10 million one-time revenue requirement adjustment to be amortized in equivalent annual amounts over its next GRC cycle (i.e., the GRC following the 2017 GRC), and (4) compensation payments to the Cities of San Bruno and San Carlos in a total amount of $12 million ($6 million to each city). In addition, the settlement agreement provides for certain non-financial remedies, including enhanced noticing obligations between the Utility and CPUC decision-makers, as well as certification of employee training on the CPUC ex parte communication rules. Under the terms of the settlement agreement, customers will bear no costs associated with the financial remedies set forth above.

The CPUC may accept, reject, or modify the terms of the settlement agreement, including imposing additional penalties on the Utility. On May 1, 2017, a PD was issued extending the statutory deadline for this proceeding from May 17, 2017 to December 29, 2017. The PD is on the CPUC's May 11, 2017 meeting agenda. The Utility is unable to predict the outcome of this proceeding.

At March 31, 2017, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets include a $13 million accrual for the portions of the settlement agreement that would be payable to the California General Fund and the Cities of San Bruno and San Carlos. In accordance with accounting rules, adjustments related to revenue requirements would be recorded in the periods in which they are incurred.

For more information about the proceeding, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K.

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 had been completed and that remediation work, including removal of the encroachments, was 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 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 CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports. There are a number of audit findings, as well as other potential violations identified through various investigations and the Utility’s self-reported non-compliance with laws and regulations, that the SED has yet to act upon. This includes the Utility’s February 2017 self-report related to customer service representatives who handle gas emergency calls that was not timely submitted to the CPUC. The Utility believes it is probable that the SED will impose penalties or take other enforcement action with respect to some of these violations. 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 and other CPUC staff has in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines.

The SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000, with an administrative limit of $8 million per citation issued. The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day. The SED also has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The SED is also required to consider the appropriateness of the amount of the penalty to the size of the entity charged. The SED has historically exercised broad discretion in determining whether violations are continuing and the amount of penalties to be imposed. The CPUC can also issue an OII and possible additional fines even after the SED has issued a citation. The SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of electric and natural gas laws and regulations.

On April 25, 2017, the SED issued two citations totaling $8.3 million to the Utility in connection with the Butte fire. The SED’s investigation found that neither the Utility nor its contractors took appropriate steps to remedy the condition and consequences when two gray pine trees in a stand were removed and that appropriate steps were not taken to prevent a remaining gray pine from leaning and contacting the Utility’s electric line. The SED concluded that this failure created an unsafe and dangerous condition that resulted in the remaining gray pine tree leaning and making contact with the electric line, thus causing a fire. The SED issued a first citation to the Utility for $8 million, for failing to maintain its electric line safely and properly. According to the citation, this violation began in January 2015, when the Utility and/or its contractors first failed to identify that the planned removal of the two nearby trees would allow the remaining gray pine tree to become hazardous and make contact with the Utility’s electric line. The SED also issued a second citation to the Utility for a total of $300,000 for two violations, including a $250,000 citation for failure to timely report to the CPUC that the Utility’s facilities may have been linked to the ignition of the Butte fire, and a $50,000 citation for failing to maintain the minimum required clearance of 18 inches between the electric line and the remaining gray pine tree. The Utility has 30 calendar days (until May 25, 2017) to pay or appeal the citations.

Federal Investigations

In 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility has cooperated with those investigations. In addition, in October 2016, the Utility received a grand jury subpoena and letter from the U.S. Attorney for the Northern District of California advising that the Utility is a target of a federal investigation regarding possible criminal violations of the Migratory Bird Treaty Act and conspiracy to violate the act. The investigation involves a removal by the Utility of a hazardous tree that contained an osprey nest and egg in Inverness, California, on March 18, 2016. It is uncertain whether any charges will be brought against the Utility as a result of these investigations.

Other Matters

PG&E Corporation and the Utility are subject to various claims, lawsuits and regulatory proceedings that separately are not considered material. Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $48 million at March 31, 2017 and $45 million at December 31, 2016. 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.

Disallowance of Plant Costs

The Utility is subject to various cost caps within its rate cases that increase the risk of overspend throughout the rate case cycles. Charges may be required in the future based on the Utility’s ability to manage its capital spending and on the outcome of the CPUC’s audit of 2011 through 2014 capital spending related to its 2015 GT&S rate case. PG&E Corporation and the Utility would record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates and the amount of disallowance can be reasonably estimated. Capital disallowances are reflected in operating and maintenance expenses in the Condensed Consolidated Statements of Income. For more information, see Note 13 “Contingencies and Commitments” of the Notes to the Consolidated Financial Statements in the 2016 Form 10-K.

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
	March 31,		December 31,
(in millions)	2017		2016
Topock natural gas compressor station (1)	$	296	$	299
Hinkley natural gas compressor station (1)		132		135
Former manufactured gas plant sites owned by the Utility or third parties		308		285
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites		133		131
Fossil fuel-fired generation facilities and sites		111		108
Total environmental remediation liability	$	980	$	958

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

The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the EPA under the federal Resource Conversation and Recovery Act as well as other state hazardous waste laws. The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. The Utility assesses and monitors, on an ongoing basis, measures that may be necessary to comply with these laws and regulations and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.

The Utility’s environmental remediation liability at March 31, 2017 reflects its best estimate of probable future costs associated with its final remediation plans. Future costs will depend on many factors, including the extent of work to implement final remediation plans 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.

At March 31, 2017, the Utility expected to recover $696 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC. Some of the Utility’s environmental remediation liability, such as the environmental remediation costs associated with the Hinkley site discussed below, will not be recovered in rates.

Natural Gas Compressor Station Sites

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

Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the DTSC and the DOI. In November 2015, the Utility submitted its final remediation design to the agencies for approval. The Utility’s design 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 conducted an additional environmental review of the proposed design and issued a draft environmental impact report for public comment in January 2017. After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in mid-2017. After the Utility modifies its design in response to the final report, the Utility will seek approval to begin construction of the new in-situ treatment system in late 2017 or early 2018.

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. In November 2015, the Regional Board adopted a final clean-up and abatement order to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order requires setting plume capture requirements, requires establishing a monitoring and reporting program, and finalizes deadlines for the Utility to meet interim cleanup targets.

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 by as much as $1 billion (including amounts related to the Topock and Hinkley 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, financial condition, and cash flows during the period in which they are recorded.

Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL and EMANI, covering nuclear or non- nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, as of April 1, 2017, the current maximum aggregate annual retrospective premium obligation for the Utility is approximately $58 million. EMANI provides $200 million for any one accident and in the annual aggregate the excess of the combined amount recoverable under the Utility’s NEIL policies. If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $3.3 million, as of April 1, 2017. For more information about the Utility’s nuclear insurance coverage, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 Form 10-K.

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. While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers. 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. Under these settlement agreements, amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. Generally, any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers either through settlement or through the conclusion of the various FERC and judicial proceedings are refunded to customers through rates in future periods.

At March 31, 2017 and December 31, 2016, the Condensed Consolidated Balance Sheets reflected $236 million, respectively, in net claims within Disputed claims and customer refunds. The Utility is uncertain when or how the remaining net disputed claims liability will be resolved.

Tax Matters

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the resolution of audits. As of March 31, 2017, it is reasonably possible that unrecognized tax benefits will decrease by approximately $60 million within the next 12 months. PG&E Corporation and the Utility believe that the majority of the decrease will not impact net income.

Gain Contingencies

Litigation Related to the San Bruno Accident and Natural Gas Spending

As of March 31, 2017, there were seven shareholder derivative lawsuits seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by certain current and former officers and directors (the “Individual Defendants”), among other claims. Four of the cases were consolidated as the San Bruno Fire Derivative Cases and are pending in the Superior Court of California, County of San Mateo (the “Court”). The remaining three cases are Tellardin v. Anthony F. Earley, Jr., et al., Iron Workers Mid-South Pension Fund v. Johns, et al., and Bushkin v. Rambo, et al. (the “Additional Derivative Cases”).

On March 15, 2017, the parties in the San Bruno Fire Derivative Cases filed with the Court a settlement that they reached to resolve the consolidated shareholder derivative lawsuit and certain additional claims against the Individual Defendants. Pursuant to the settlement stipulation, subject to certain conditions: (1) the Individual Defendants’ directors and officers liability insurance carriers will pay $90 million to PG&E Corporation within 11 business days of the entry of the judgment approving settlement in the San Bruno Fire Derivative Cases, (2) PG&E Corporation and the Utility will implement certain corporate governance therapeutics for five years, and (3) the Utility will implement certain gas operations therapeutics and maintain certain of them for three years, at an estimated cost of up to approximately $32 million.

In addition, PG&E Corporation agreed to pay any fee and expense award that the Court may grant to counsel for the plaintiffs in the San Bruno Fire Derivative Cases in an amount not to exceed $25 million for fees and $500,000 for expenses. PG&E Corporation and the Utility also agreed, under their indemnification obligations to the Individual Defendants, to pay $18.3 million of the Individual Defendants’ costs, fees, and expenses incurred in connection with responding to, defending and settling the San Bruno Fire Derivative Cases and the Additional Derivative Cases, including certain fees and expenses for investigating these claims. The $18.3 million has been paid, with the majority reflected in PG&E Corporation’s and the Utility’s financial statements through December 31, 2016.

The settlement is expressly conditioned on, among other things, the Additional Derivative Cases being dismissed with prejudice, which condition can only be waived by PG&E Corporation and a majority of the Individual Defendants.

The settlement is subject to the Court’s approval and its terms may change as a result of the settlement approval process. The preliminary settlement approval hearing took place on April 21, 2017. At this hearing, PG&E Corporation and the Utility agreed that notwithstanding the expiration of the five-year and three-year periods applicable to the corporate and gas operations therapeutics described above, neither entity will make any material changes to such therapeutics unless those changes are reported in PG&E Corporation’s Corporate Responsibility and Sustainability Report or another suitable report at least three months prior to their taking effect. With this modification, the Court preliminarily approved the settlement, preliminarily finding it fair, reasonable, adequate, and in the best interests of PG&E Corporation, the Utility, and the shareholders of PG&E Corporation.

The final approval hearing has been set for July 18, 2017. If the Court approves the settlement and enters a judgment substantially in the form requested by the parties, the settlement will become effective when certain conditions specified in the settlement stipulation are satisfied, including the expiration of any right to appeal the judgment.

There was no impact on PG&E Corporation or the Utility’s Condensed Consolidated Financial Statements in the quarter ended March 31, 2017. If the settlement is approved, PG&E Corporation estimates it will record $64.5 million in insurance proceeds in the period the settlement becomes effective.

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, 2016, the Utility had undiscounted future expected obligations of approximately $47 billion. (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2016 Form 10-K.) The Utility has not entered into any new material commitments during the three months ended March 31, 2017.

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, 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 is also 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 also should be read in conjunction with the 2016 Form 10-K.

Summary of Changes in Net Income and Earnings per Share

The following table is a summary reconciliation of the key changes in PG&E Corporation’s income available for common shareholders and EPS (as well as earnings from operations and EPS based on earnings from operations) 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
	March 31,
			EPS
(in millions, except per share amounts)	Earnings (1)		(diluted)
PG&E Corporation’s Earnings on a GAAP basis - 2017	$	576	$	1.13
Fines and penalties (3)		36		0.07
Pipeline-related expenses (4)		16		0.03
Butte fire related costs (net of insurance) (5)		2		-
Legal and regulatory related expenses (6)		2		-
GT&S revenue timing impact (7)		(88)		(0.17)
PG&E Corporation's Earnings from Operations - 2017 (2)	$	544	$	1.06

PG&E Corporation’s Earnings on a GAAP basis - 2016	$	107	$	0.22
Butte fire related costs (net of insurance) (8)		226		0.45
Fines and penalties (9)		51		0.10
Pipeline-related expenses (10)		13		0.03
Legal and regulatory related expenses (10)		10		0.02
PG&E Corporation's Earnings from Operations - 2016 (2)	$	407	$	0.82
Timing of 2015 GT&S revenue impact (11)		75		0.15
Tax benefit on stock compensation (12)		31		0.06
Growth in rate base earnings		17		0.03
Miscellaneous		29		0.05
Timing of 2017 GRC decision (13)		(15)		(0.03)
Increase in shares outstanding		-		(0.02)
PG&E Corporation's Earnings from Operations - 2017 (2)	$	544	$	1.06

(1) Tax effect is performed at PG&E Corporation’s statutory tax rate of 40.75% except for fines, which are not tax deductible. See footnote (3) below.

(2) “Earnings from operations” is not calculated in accordance with GAAP and excludes the items impacting comparability shown in footnotes (3) through (10).

(3) The Utility incurred costs of $60 million (before the tax impact of $24 million) during the three months ended March 31, 2017 associated with fines and penalties. This includes costs of $32 million (before the tax impact of $13 million) during the three months ended March 31, 2017 associated with safety-related cost disallowances imposed by the CPUC in its April 9, 2015 decision in the gas transmission pipeline investigations. The Utility also recorded $15 million (before the tax impact of $6 million) during the three months ended March 31, 2017 for disallowances imposed by the CPUC in its final phase two decision of the 2015 GT&S rate case for prohibited ex parte communications. In addition, the Utility accrued financial remedies of $12 million (before the tax impact of $5 million), and $1 million (which is not tax deductible), during the three months ended March 31, 2017, in connection with the settlement filed with the CPUC on March 28, 2017 related to the Order Instituting an Investigation into Compliance with Ex Parte Communication Rules. Future fines or penalties may be imposed in connection with other enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.

(4) The Utility incurred costs of $28 million (before the tax impact of $12 million) during the three months ended March 31, 2017 for pipeline related expenses incurred in connection with the multi-year effort to identify and remove encroachments from transmission pipeline rights of way.

(5) The Utility recorded costs of $3 million (before the tax impact of $1 million) during the three months ended March 31, 2017 associated with the Butte fire, net of insurance. This includes charges of $10 million (before the tax impact of $4 million) related to legal costs associated with the Butte fire, partially offset by $7 million (before the tax impact of $3 million) of probable insurance recovery.

(6) The Utility incurred costs of $4 million (before the tax impact of $2 million) during the three months ended March 31, 2017 for legal and regulatory related expenses incurred in connection with various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.

(7) As a result of the CPUC’s final phase two decision in the 2015 GT&S rate case, during the three months ended March 31, 2017, the Utility recorded revenues of $150 million (before the tax impact of $62 million) in excess of the 2017 authorized revenue requirement, which includes the final component of under-collected revenues retroactive to January 1, 2015.

(8) For the three months ended March 31, 2016, the Utility incurred charges of $350 million (before the tax impact of $142 million) related to estimated property damages in connection with the Butte fire and $31 million (before the tax impact of $13 million) for Utility clean-up, repair, and legal costs associated with the Butte fire.

(9) Represents disallowed capital charges of $87 million (before the tax impact of $36 million) during the three months ended March 31, 2016.

(10) Represents pipeline-related expenses of $22 million (before the tax impact of $9 million) during the three months ended March 31, 2016, including costs incurred to identify and remove encroachments from transmission pipeline rights of way. Legal and regulatory related expenses of $17 million (before the tax impact of $7 million) during the three months ended March 31, 2016 include various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.

(11) Represents the impact in 2016 of the delay in the Utility’s 2015 GT&S rate case. The CPUC issued its final phase two decision on December 1, 2016, delaying recognition of the full 2016 revenue increase until the fourth quarter of 2016.

(12) Represents the incremental tax benefit related to share-based compensation awards that vested during the three months ended March 31, 2017. Pursuant to ASU 2016-09, which PG&E Corporation and the Utility adopted in 2016, excess tax benefits associated with vested awards are reflected in net income.

(13) Represents the increase in GRC-related capital costs (depreciation and interest) but does not include an offsetting revenue increase, which is pending a final decision in the Utility’s 2017 GRC proceeding.

Key Factors Affecting Financial Results

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

The Outcome of Enforcement, Litigation, and Regulatory Matters. The Utility’s future financial results may continue to be impacted by the outcome of current and future enforcement, litigation, and regulatory matters, including the Butte fire litigation, related insurance recoveries, and the effect, if any, that the SED’s $8.3 million citations issued in connection with the Butte fire may have on such litigation, the ex parte OII and the related settlement agreement that is subject to the CPUC approval, the probation and monitorship imposed as a result of the Utility’s conviction in the federal criminal trial and potential recommendations that the monitor may make, and potential penalties in connection with the Utility’s safety and other self-reports. (See Item 1A. Risk Factors in the 2016 Form 10-K.)

The Timing and Outcome of Ratemaking Proceedings. The Utility’s results may be impacted by the timing and outcome of its 2017 GRC, FERC TO rate case, and petition for modification related to its cost of capital. (See “2017 General Rate Case,” “Transmission Owner Rate Case,” and “Cost of Capital” in “Regulatory Matters” below for more information.) The outcome of regulatory proceedings can be affected by many factors, including arguments made 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 and Recover Operating Costs and Capital Expenditures. The Utility is committed to delivering safe, reliable, sustainable, and affordable electric and gas services to its customers. Increasing demands from state laws and policies relating to increased renewable energy resources, the reduction of GHG emissions, the expansion of energy efficiency programs, the development and widespread deployment of distributed generation and self-generation resources, and the development of energy storage technologies have increased pressure on the Utility to achieve efficiencies in its operations in order to maintain the affordability of its service. In any given year the Utility’s ability to earn its authorized rate of return depends on its ability to manage costs within the amounts authorized in rate case decisions. The Utility forecasts that in 2017 it will incur unrecovered pipeline-related expenses ranging from $80 million to $125 million which primarily relate to costs to identify and remove encroachments from transmission pipeline rights-of-way. Also, the CPUC decision in the Utility’s 2015 GT&S rate case establishes various cost caps that will increase the risk of overspend over the rate case cycle through 2018. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

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, 2017, PG&E Corporation issued $150 million of common stock and used $125 million of the cash proceeds to make equity contributions to the Utility. PG&E Corporation forecasts that it will continue issuing a material amount of equity in future years, including $400 million to $600 million in 2017, primarily to support the Utility’s capital expenditures. PG&E Corporation may issue additional equity to fund unrecoverable pipeline-related expenses and to pay fines and penalties that may be required by the final outcomes of pending enforcement matters. These additional issuances could have a material dilutive impact 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 Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1, 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 2016 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 that 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 “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.