
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C., 20549 FORM 10-Q
(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September ~~30,2016~~30, 2017 OR

[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___________ to __________

Commission File Number _______________		Exact Name of Registrant as Specified in its Charter _______________			State or Other Jurisdiction of Incorporation ______________		IRS Employer Identification Number ___________

1-12609		PG&E Corporation			California		94-3234914
1-2348		Pacific Gas and Electric Company			California		94-0742640

PG&E Corporation 77 Beale Street P.O. Box 770000 San Francisco, California 94177					Pacific Gas and Electric Company 77 Beale Street P.O. Box 770000 San Francisco, ~~California94177~~California 94177
Address of principal executive offices, including zip code

PG&E Corporation (415) 973-1000					Pacific Gas and Electric Company (415) 973-7000
Registrant's telephone number, including area code

Indicate by check mark whether ~~each~~the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) ~~have~~has been subject to such filing requirements for the past 90 days. ~~[X]~~
PG&E Corporation:				[X] Yes [ ] No
Pacific Gas and Electric Company:				[X] Yes [ ] No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
PG&E Corporation:					[X] Yes [ ] No
Pacific Gas and Electric Company:					[X] Yes [ ] No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, ~~or a~~ smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, ~~and~~ “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act.
PG&E Corporation:			[X] Large accelerated filer			[ ] Accelerated filer
			[ ] Non-accelerated filer (Do not check if a smaller reporting company)
			[ ] Smaller reporting company			[ ] Emerging growth company
Pacific Gas and Electric Company:			[ ] Large accelerated filer			[ ] Accelerated filer
			[X] Non-accelerated filer (Do not check if a smaller reporting company)
			[ ] Smaller reporting company			[ ] Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
PG&E Corporation:					[ ]
Pacific Gas and Electric Company:					[ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation:					[ ] Yes [X] No

Pacific Gas and Electric Company:							[ ] Yes [X] No

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.
Common stock outstanding as of October ~~24,2016:~~24, 2017:
PG&E Corporation:							~~505,666,694~~514,422,806
Pacific Gas and Electric Company:							264,374,809

PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY
FORM 10-Q

FOR THE QUARTERLY PERIOD ~~ENDEDSEPTEMBER 30,2016~~ENDED SEPTEMBER 30, 2017

TABLE OF CONTENTS

GLOSSARY

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

CONDENSED CONSOLIDATED BALANCE SHEETS

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

CONDENSED CONSOLIDATED BALANCE SHEETS

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

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

NOTE 10: SUBSEQUENT EVENTS

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

RESULTS OF OPERATIONS

OVERVIEW

RESULTS OF OPERATIONS

LIQUIDITY AND FINANCIAL RESOURCES

ENFORCEMENT AND LITIGATION MATTERS

REGULATORY MATTERS

~~LEGISLATIVE AND REGULATORY~~FEDERAL 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.

~~2015~~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, ~~2015~~
~~2016 Q1 Form 10-Q~~	~~PG&E Corporation and Pacific Gas and Electric Company's combined Quarterly Report on Form 10-Q for the quarter ended March 31, 2016~~
~~2016 Q2 Form 10-Q~~	~~PG&E Corporation and Pacific Gas and Electric Company's combined Quarterly Report on Form 10-Q for the quarter ended June 30,~~ 2016
AFUDC	allowance for funds used during construction
ALJ	~~Administrative Law Judge~~administrative law judge
~~ARO(s)~~ARO	asset retirement ~~obligation(s)~~obligation
ASU	~~Accounting Standards Update~~accounting standard update issued by the FASB (see below)
CAISO	California Independent System Operator
Cal Fire	California Department of Forestry and Fire Protection
~~CAISO~~CARB	California ~~Independent System Operator Corporation~~Air Resources Board
~~Central Coast Water Board~~CCA	~~Central Coast Regional Water Quality Control Board~~Community Choice Aggregator
CEC	California Energy Resources Conservation and Development Commission
CO2	carbon dioxide
CEMA	Catastrophic Event Memorandum Account
CP	cathodic protection
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
DER	distributed energy resources
DIDF	Distribution Investment Deferral Framework
Diablo Canyon	Diablo Canyon nuclear power plant
DOGGR	Division of Oil, Gas, and Geothermal Resources
DOI	U.S. Department of the Interior
DRP	electric distribution resources plan
DTSC	~~California~~ Department of Toxic Substances Control
~~EMANI~~EDA	~~European Mutual Association for Nuclear Insurance~~
~~Energy Division~~	~~CPUC’s Energy Division~~equity distribution agreement
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)
~~MOD POD~~IRS	~~modified presiding officer's decision~~Internal Revenue Service
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Item 2, of this Form 10-Q
NAV	net asset value
NDCTP	Nuclear Decommissioning Cost Triennial Proceedings
NEIL	Nuclear Electric Insurance Limited
~~NEM~~NERC	~~Net Energy Metering~~North American Electric Reliability Corporation
NRC	Nuclear Regulatory Commission
~~NTSB~~OES	~~National Transportation Safety Board~~State of California Office of Emergency Services
OII	order instituting investigation
OIR	order instituting rulemaking
ORA	Office of Ratepayer Advocates
~~POD~~PCIA	~~presiding officer's~~Power Charge Indifference Adjustment
PD	proposed decision
~~PSEP~~PFM	~~pipeline safety enhancement plan~~petition for modification
PVPHMSA	~~photovoltaic~~Pipeline and Hazardous Materials Safety Administration

~~Regional Board~~ROE	~~California Regional Water Control Board, Lahontan Region~~
~~RPS~~	~~Renewable Portfolio Standards~~return on equity
SEC	U.S. Securities and Exchange Commission
SED	Safety and Enforcement Division of the CPUC ~~formerly known as the Consumer Protection and Safety Division or the CPSD~~
TE	transportation electrification
TO	transmission owner

TURN	The Utility Reform Network
Utility	Pacific Gas and Electric Company
VIE(s)	variable interest entity(ies)
WEMA	Wildfire Expense Memorandum Account
Westinghouse	Westinghouse Electric Company, LLC

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	(Unaudited)								(Unaudited)
	Three Months Ended				Nine Months Ended				Three Months Ended				Nine Months Ended
	September 30,				September 30,				September 30,				September 30,
(in millions, except per share amounts)	2016		2015		2016		2015		2017		2016		2017		2016
Operating Revenues
Electric	$	3,994	$	3,868	$	10,590	$	10,344	$	3,648	$	3,994	$	10,036	$	10,590
Natural gas		816		682		2,363		2,322		869		816		2,999		2,363
Total operating revenues		4,810		4,550		12,953		12,666		4,517		4,810		13,035		12,953
Operating Expenses
Cost of electricity		1,613		1,681		3,719		3,958		1,466		1,613		3,436		3,719
Cost of natural gas		80		50		377		442		78		80		524		377
Operating and maintenance		1,783		1,621		5,631		5,028		1,364		1,783		4,414		5,631
Depreciation, amortization, and decommissioning		694		653		2,090		1,935		710		694		2,134		2,090
Total operating expenses		4,170		4,005		11,817		11,363		3,618		4,170		10,508		11,817
Operating Income		640		545		1,136		1,303		899		640		2,527		1,136
Interest income		8		2		17		6		9		8		22		17
Interest expense		(211)		(194)		(621)		(575)		(220)		(211)		(663)		(621)
Other income, net		24		24		74		100		25		24		59		74
Income Before Income Taxes		461		377		606		834		713		461		1,945		606
Income tax provision (benefit)		70		67		(105)		84		160		70		403		(105)
Net Income		391		310		711		750		553		391		1,542		711
Preferred stock dividend requirement of subsidiary		3		3		10		10		3		3		10		10
Income Available for Common Shareholders	$	388	$	307	$	701	$	740	$	550	$	388	$	1,532	$	701
Weighted Average Common Shares Outstanding, Basic		501		486		497		481		513		501		511		497
Weighted Average Common Shares Outstanding, Diluted		503		489		500		484		516		503		514		500
Net Earnings Per Common Share, Basic	$	0.77	$	0.63	$	1.41	$	1.54	$	1.07	$	0.77	$	3.00	$	1.41
Net Earnings Per Common Share, Diluted	$	0.77	$	0.63	$	1.40	$	1.53	$	1.07	$	0.77	$	2.98	$	1.40
Dividends Declared Per Common Share	$	0.49	$	0.46	$	1.44	$	1.37	$	0.53	$	0.49	$	1.55	$	1.44

See accompanying Notes to the Condensed Consolidated Financial Statements.	See accompanying Notes to the Condensed Consolidated Financial Statements.								See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)								(Unaudited)
	Three Months Ended				Nine Months Ended				Three Months Ended				Nine Months Ended
	September 30,				September 30,				September 30,				September 30,
(in millions)	2016		2015		2016		2015		2017		2016		2017		2016
Net Income	$	391	$	310	$	711	$	750	$	553	$	391	$	1,542	$	711
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $0, $0, $0 and $0, at respective dates)		-		-		-		-		-		-		1		-
Net change in investments
(net of taxes of $0, $0, $0 and $12, at respective dates)		-		-		-		(17)
Total other comprehensive income (loss)		-		-		-		(17)		-		-		1		-
Comprehensive Income		391		310		711		733		553		391		1,543		711
Preferred stock dividend requirement of subsidiary		3		3		10		10		3		3		10		10
Comprehensive Income Attributable to
Common Shareholders	$	388	$	307	$	701	$	723	$	550	$	388	$	1,533	$	701

See accompanying Notes to the Condensed Consolidated Financial Statements.	See accompanying Notes to the Condensed Consolidated Financial Statements.								See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)				(Unaudited)
	Balance At				Balance At
	September 30,		December 31,		September 30,		December 31,
(in millions)	2016		2015		2017		2016
ASSETS
Current Assets
Cash and cash equivalents	$	71	$	123	$	191	$	177
Restricted cash		168		234		7		7
Accounts receivable:
Customers (net of allowance for doubtful accounts of $53 and $54
at respective dates)		1,233		1,106
Customers (net of allowance for doubtful accounts of $58
at both periods)						1,368		1,252
Accrued unbilled revenue		956		855		972		1,098
Regulatory balancing accounts		1,475		1,760		1,478		1,500
Other		475		286		992		801
Regulatory assets		370		517		573		423
Inventories:
Gas stored underground and fuel oil		134		126		138		117
Materials and supplies		343		313		360		346
Income taxes receivable		218		155		25		160
Other		306		338		279		283
Total current assets		5,749		5,813		6,383		6,164
Property, Plant, and Equipment
Electric		51,532		48,532		54,148		52,556
Gas		17,384		16,749		18,938		17,853
Construction work in progress		2,117		2,059		2,421		2,184
Other		2		2		2		2
Total property, plant, and equipment		71,035		67,342		75,509		72,595
Accumulated depreciation		(21,605)		(20,619)		(22,986)		(22,014)
Net property, plant, and equipment		49,430		46,723		52,523		50,581
Other Noncurrent Assets
Regulatory assets		7,534		7,029		8,546		7,951
Nuclear decommissioning trusts		2,597		2,470		2,793		2,606
Income taxes receivable		70		135		52		70
Other		1,185		1,064		1,229		1,226
Total other noncurrent assets		11,386		10,698		12,620		11,853
TOTAL ASSETS	$	66,565	$	63,234	$	71,526	$	68,598

See accompanying Notes to the Condensed Consolidated Financial Statements.	See accompanying Notes to the Condensed Consolidated Financial Statements.				See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)				(Unaudited)
	Balance At				Balance At
	September 30,		December 31,		September 30,		December 31,
(in millions, except share amounts)	2016		2015		2017		2016
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	1,145	$	1,019	$	869	$	1,516
Long-term debt, classified as current		160		160		700		700
Accounts payable:
Trade creditors		1,370		1,414		1,419		1,495
Regulatory balancing accounts		764		715		1,328		645
Other		496		398		483		433
Disputed claims and customer refunds		233		454		240		236
Interest payable		144		206		163		216
Other		1,958		1,997		2,271		2,323
Total current liabilities		6,270		6,363		7,473		7,564
Noncurrent Liabilities
Long-term debt		16,528		15,925		16,619		16,220
Regulatory liabilities		6,613		6,321		7,265		6,805
Pension and other postretirement benefits		2,632		2,622		2,707		2,641
Asset retirement obligations		4,672		3,643		4,758		4,684
Deferred income taxes		9,850		9,206		11,085		10,213
Other		2,394		2,326		2,333		2,279
Total noncurrent liabilities		42,689		40,043		44,767		42,842
Commitments and Contingencies (Note 9)
Equity
Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares;
505,183,752 and 492,025,443 shares outstanding at respective dates		12,083		11,282
513,773,072 and 506,891,874 shares outstanding at respective dates						12,560		12,198
Reinvested earnings		5,278		5,301		6,482		5,751
Accumulated other comprehensive loss		(7)		(7)		(8)		(9)
Total shareholders' equity		17,354		16,576		19,034		17,940
Noncontrolling Interest - Preferred Stock of Subsidiary		252		252		252		252
Total equity		17,606		16,828		19,286		18,192
TOTAL LIABILITIES AND EQUITY	$	66,565	$	63,234	$	71,526	$	68,598

See accompanying Notes to the Condensed Consolidated Financial Statements.	See accompanying Notes to the Condensed Consolidated Financial Statements.				See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)				(Unaudited)
	Nine Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2016		2015		2017			2016
Cash Flows from Operating Activities
Net income	$	711	$	750	$	1,542		$	711
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		2,090		1,935		2,134	��		2,090
Allowance for equity funds used during construction		(84)		(80)		(63)			(84)
Deferred income taxes and tax credits, net		644		260		848			644
Disallowed capital expenditures		517		270		47			517
Other		293		247		204			293
Effect of changes in operating assets and liabilities:
Accounts receivable		(546)		(322)		(58)			(283)
Butte-related insurance receivable						(166)			(263)
Inventories		(38)		5		(35)			(38)
Accounts payable		189		95		76			189
Butte-related third-party claims						12			321
Income taxes receivable/payable		(63)		42		135			(63)
Other current assets and liabilities		254		(87)		23			(32)
Regulatory assets, liabilities, and balancing accounts, net		(634)		78		(30)			(634)
Other noncurrent assets and liabilities		(85)		(251)		68			(85)
Net cash provided by operating activities		3,248		2,942		4,737			3,283
Cash Flows from Investing Activities
Capital expenditures		(4,128)		(3,662)		(3,938)			(4,128)
Decrease in restricted cash		66		11		-			66
Proceeds from sales and maturities of nuclear decommissioning
trust investments		1,019		1,023		1,043			1,019
Purchases of nuclear decommissioning trust investments		(1,050)		(1,124)		(1,071)			(1,050)
Other		10		18		16			10
Net cash used in investing activities		(4,083)		(3,734)		(3,950)			(4,083)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $5
and $2 at respective dates		(128)		545
Net issuances (repayments) of commercial paper, net of discount of
$4 and $5 at respective dates						(652)			(128)
Short-term debt financing		250		-		250			250
Short-term debt matured		-		(300)		(250)			-
Proceeds from issuance of long-term debt, net of discount and
issuance costs of $6 and $14 at respective dates		594		486
issuance costs of $11 and $6 at respective dates						734			594
Long-term debt matured or repurchased						(345)			-
Common stock issued		727		689		345			727
Common stock dividends paid		(678)		(638)		(754)			(678)
Other		18		13		(101)			(17)
Net cash provided by financing activities		783		795
Net cash provided by (used in) financing activities						(773)			748
Net change in cash and cash equivalents		(52)		3		14			(52)
Cash and cash equivalents at January 1		123		151		177			123
Cash and cash equivalents at September 30	$	71	$	154	$	191		$	71

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(611)	$	(569)	$	(644)	$	(611)
Income taxes, net		154		-		158		154
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	248	$	223	$	272	$	248
Capital expenditures financed through accounts payable		325		245		301		325
Noncash common stock issuances		15		15		16		15

See accompanying Notes to the Condensed Consolidated Financial Statements.	See accompanying Notes to the Condensed Consolidated Financial Statements.				See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	(Unaudited)								(Unaudited)
	Three Months Ended				Nine Months Ended				Three Months Ended				Nine Months Ended
	September 30,				September 30,				September 30,				September 30,
(in millions)	2016		2015		2016		2015		2017		2016		2017		2016
Operating Revenues
Electric	$	3,993	$	3,868	$	10,590	$	10,344	$	3,647	$	3,993	$	10,038	$	10,590
Natural gas		816		682		2,363		2,322		869		816		2,999		2,363
Total operating revenues		4,809		4,550		12,953		12,666		4,516		4,809		13,037		12,953
Operating Expenses
Cost of electricity		1,613		1,681		3,719		3,958		1,466		1,613		3,436		3,719
Cost of natural gas		80	��	50		377		442		78		80		524		377
Operating and maintenance		1,782		1,622		5,630		5,028		1,428		1,782		4,477		5,630
Depreciation, amortization, and decommissioning		694		653		2,090		1,935		710		694		2,134		2,090
Total operating expenses		4,169		4,006		11,816		11,363		3,682		4,169		10,571		11,816
Operating Income		640		544		1,137		1,303		834		640		2,466		1,137
Interest income		8		2		16		6		10		8		22		16
Interest expense		(209)		(191)		(614)		(567)		(217)		(209)		(655)		(614)
Other income, net		23		22		68		68		24		23		52		68
Income Before Income Taxes		462		377		607		810		651		462		1,885		607
Income tax provision (benefit)		73		72		(99)		95		138		73		394		(99)
Net Income		389		305		706		715		513		389		1,491		706
Preferred stock dividend requirement		3		3		10		10		3		3		10		10
Income Available for Common Stock	$	386	$	302	$	696	$	705	$	510	$	386	$	1,481	$	696

See accompanying Notes to the Condensed Consolidated Financial Statements.	See accompanying Notes to the Condensed Consolidated Financial Statements.								See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)									(Unaudited)
	Three Months Ended					Nine Months Ended				Three Months Ended				Nine Months Ended
	September 30,					September 30,				September 30,				September 30,
(in millions)	2016		2015			2016	2015			2017		2016		2017		2016
Net Income	$	389	$	305	$	706	$	715		$	513	$	389	$	1,491	$	706
Other Comprehensive Income
Pension and other postretirement benefit plans obligations
(net of taxes of $0, $0, $0 and $0, at respective dates )		-		-		1		-			-		-		1		1
Total other comprehensive income (loss)		-		-		1		-			-		-		1		1
Comprehensive Income	$	389	$	305	$	707	$	715		$	513	$	389	$	1,492	$	707

See accompanying Notes to the Condensed Consolidated Financial Statements.	See accompanying Notes to the Condensed Consolidated Financial Statements.								See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)				(Unaudited)
	Balance At				Balance At
	September 30,		December 31,		September 30,		December 31,
(in millions)	2016		2015		2017		2016
ASSETS
Current Assets
Cash and cash equivalents	$	68	$	59	$	70	$	71
Restricted cash		168		234		7		7
Accounts receivable:
Customers (net of allowance for doubtful accounts of $53 and $54
at respective dates)		1,233		1,106
Customers (net of allowance for doubtful accounts of $58
at both periods)						1,368		1,252
Accrued unbilled revenue		956		855		972		1,098
Regulatory balancing accounts		1,475		1,760		1,478		1,500
Other		473		284		992		801
Regulatory assets		370		517		573		423
Inventories:
Gas stored underground and fuel oil		134		126		138		117
Materials and supplies		343		313		360		346
Income taxes receivable		194		130		24		159
Other		306		338		279		282
Total current assets		5,720		5,722		6,261		6,056
Property, Plant, and Equipment
Electric		51,532		48,532		54,148		52,556
Gas		17,384		16,749		18,938		17,853
Construction work in progress		2,117		2,059		2,421		2,184
Total property, plant, and equipment		71,033		67,340		75,507		72,593
Accumulated depreciation		(21,603)		(20,617)		(22,984)		(22,012)
Net property, plant, and equipment		49,430		46,723		52,523		50,581
Other Noncurrent Assets
Regulatory assets		7,534		7,029		8,546		7,951
Nuclear decommissioning trusts		2,597		2,470		2,793		2,606
Income taxes receivable		70		135		52		70
Other		1,066		958		1,104		1,110
Total other noncurrent assets		11,267		10,592		12,495		11,737
TOTAL ASSETS	$	66,417	$	63,037	$	71,279	$	68,374

See accompanying Notes to the Condensed Consolidated Financial Statements.	See accompanying Notes to the Condensed Consolidated Financial Statements.				See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)				(Unaudited)
	Balance At				Balance At
	September 30,		December 31,		September 30,		December 31,
(in millions, except share amounts)	2016		2015		2017		2016
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term borrowings	$	981	$	1,019	$	869	$	1,516
Long-term debt, classified as current		160		160		700		700
Accounts payable:
Trade creditors		1,370		1,414		1,419		1,494
Regulatory balancing accounts		764		715		1,328		645
Other		765		418		502		453
Disputed claims and customer refunds		233		454		240		236
Interest payable		144		203		163		214
Other		1,681		1,750		1,999		2,072
Total current liabilities		6,098		6,133		7,220		7,330
Noncurrent Liabilities
Long-term debt		16,179		15,577		16,270		15,872
Regulatory liabilities		6,613		6,321		7,265		6,805
Pension and other postretirement benefits		2,540		2,534		2,612		2,548
Asset retirement obligations		4,672		3,643		4,758		4,684
Deferred income taxes		10,135		9,487		11,377		10,510
Other		2,350		2,282		2,279		2,230
Total noncurrent liabilities		42,489		39,844		44,561		42,649
Commitments and Contingencies (Note 9)
Shareholders' Equity
Preferred stock		258		258		258		258
Common stock, $5 par value, authorized 800,000,000 shares;
264,374,809 shares outstanding at respective dates		1,322		1,322		1,322		1,322
Additional paid-in capital		7,955		7,215		8,455		8,050
Reinvested earnings		8,291		8,262		9,460		8,763
Accumulated other comprehensive income		4		3		3		2
Total shareholders' equity		17,830		17,060		19,498		18,395
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	66,417	$	63,037	$	71,279	$	68,374

See accompanying Notes to the Condensed Consolidated Financial Statements.	See accompanying Notes to the Condensed Consolidated Financial Statements.				See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)				(Unaudited)
	Nine Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2016		2015		2017		2016
Cash Flows from Operating Activities
Net income	$	706	$	715	$	1,491	$	706
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation, amortization, and decommissioning		2,090		1,935		2,134		2,090
Allowance for equity funds used during construction		(84)		(80)		(63)		(84)
Deferred income taxes and tax credits, net		648		245		848		648
Disallowed capital expenditures		517		270		47		517
Other		234		200		196		234
Effect of changes in operating assets and liabilities:
Accounts receivable		(546)		(321)		(58)		(283)
Butte-related insurance receivable						(166)		(263)
Inventories		(38)		5		(35)		(38)
Accounts payable		194		148		76		194
Butte-related third-party claims						12		321
Income taxes receivable/payable		(64)		14		135		(64)
Other current assets and liabilities		258		(45)		36		(28)
Regulatory assets, liabilities, and balancing accounts, net		(634)		78		(30)		(634)
Other noncurrent assets and liabilities		(75)		(232)		69		(75)
Net cash provided by operating activities		3,206		2,932		4,692		3,241
Cash Flows from Investing Activities
Capital expenditures		(4,128)		(3,662)		(3,938)		(4,128)
Decrease in restricted cash		66		11		-		66
Proceeds from sales and maturities of nuclear decommissioning
trust investments		1,019		1,023		1,043		1,019
Purchases of nuclear decommissioning trust investments		(1,050)		(1,124)		(1,071)		(1,050)
Other		10		18		16		10
Net cash used in investing activities		(4,083)		(3,734)		(3,950)		(4,083)
Cash Flows from Financing Activities
Net issuances (repayments) of commercial paper, net of discount of $5
and $2 at respective dates		(293)		545
Net issuances (repayments) of commercial paper, net of discount of
$4 and $5 at respective dates						(652)		(293)
Short-term debt financing		250		-		250		250
Short-term debt matured		-		(300)		(250)		-
Proceeds from issuance of long-term debt, net of discount and
issuance costs of $6 and $14 at respective dates		594		486
issuance costs of $11 and $6 at respective dates						734		594
Long-term debt matured or repurchased						(345)		-
Preferred stock dividends paid		(10)		(10)		(10)		(10)
Common stock dividends paid		(423)		(537)		(784)		(423)
Equity contribution from PG&E Corporation		740		605		405		740
Other		28		20		(91)		(7)
Net cash provided by financing activities		886		809
Net cash provided by (used in) financing activities						(743)		851
Net change in cash and cash equivalents		9		7		(1)		9
Cash and cash equivalents at January 1		59		55		71		59
Cash and cash equivalents at September 30	$	68	$	62	$	70	$	68

Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(636)	$	(602)
Income taxes, net		158		151
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	-	$	244
Capital expenditures financed through accounts payable		301		325

See accompanying Notes to the Condensed Consolidated Financial Statements.

Supplemental disclosures of cash flow information

Cash received (paid) for:

Interest, net of amounts capitalized
$
(602)

$
(561)
Income taxes, net

151

-
Supplemental disclosures of noncash investing and financing activities

Common stock dividends declared but not yet paid
$
244

$
-
Capital expenditures financed through accounts payable

325

245

See accompanying Notes to the Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility 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 ~~operate in one segment, as the companies~~ assess financial performance and allocate resources on a consolidated ~~basis.~~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~~Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented. The information at December 31, ~~2015~~2016 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in the ~~2015~~2016 Form 10-K. This quarterly report should be read in conjunction with the ~~2015~~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, ~~asset retirement obligations,~~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.

Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Del Norte, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the wildfires, there were 21 major wildfires in California that, in total, burned over 245,000 acres, resulted in 43 fatalities, and destroyed an estimated 8,900 structures. The causes of these fires are being investigated by Cal Fire and the CPUC, including the possible role of the Utility’s power lines and other facilities. See Note 10 below.

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 ~~2015~~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 September 30, ~~2016,~~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 September 30, ~~2016,~~2017, it did not consolidate any of them.

Asset Retirement Obligations

Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three ~~yearsin~~years in conjunction with the ~~Nuclear Decommissioning Cost Triennial Proceedings. In~~NDCTP. On May 25, 2017, the ~~first quarter of 2016,~~CPUC issued a final decision in the ~~Utility submitted its updated~~2015 NDCTP adopting a nuclear decommissioning cost estimate ~~with~~of $1.1 billion for Humboldt Bay, corresponding to the ~~CPUC, which reflects~~Utility’s request, and $2.4 billion for Diablo Canyon, compared to the Utility’s request of $3.8 billion, or 64 percent of its request. On an ~~increase of approximately $1.4~~aggregate basis, the final decision adopted a $3.5 billion intotal nuclear decommissioning cost estimate, compared to $4.8 billion requested by the Utility. Compared to the Utility’s estimated ~~undiscounted~~ cost to decommission Diablo Canyon, the ~~Utility’s~~final decision adopts assumptions which lower costs for large component removal, site security, decommissioning contractor staff, spent nuclear ~~power plants.~~fuel storage, and waste disposal. The ~~change~~Utility can seek recovery of these costs in ~~total estimated cost~~the 2018 NDCTP. The CPUC’s final decision resulted in ~~an $818~~a $66 million ~~adjustment~~reduction to the ARO recognized on the Condensed Consolidated Balance Sheets. The adjustment relates to spent fuel storage, staffing, and out-of-state waste disposal costs. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. The Utility requested that the CPUC authorize the collection of increased annual revenue requirements beginning on January 1, 2017 based on these updated cost estimates.

On June 20, 2016, the Utility entered into a joint proposalwith certain parties to retire Diablo Canyon nuclear power plant at the expiration of its current operating licenses in 2024 (Unit 1) and 2025 (Unit 2), subject to certain approvals, resulting in an additional $115 million increase to the ARO recognized on the Condensed Consolidated Balance Sheets inrelated to the ~~second quarter~~assumed length of ~~2016.~~the wet cooling period of spent nuclear fuel after plant shut down.

The estimated ~~total~~ nuclear decommissioning cost ~~of $4.8 billion~~ is discounted for GAAP purposes and recognized as an ARO on the Condensed Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued in accordance with GAAP was ~~$3.5~~$3.4 billion at September ~~30,2016~~30, 2017, and ~~$2.5~~$3.5 billion at December 31, ~~2015.~~2016. These estimates are based on decommissioning cost studies, prepared in accordance with the CPUC requirements. Changes in these estimates could materially affect the amount of the recorded ARO for these assets.

Pension and Other ~~Postretirement~~Post-retirement Benefits

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

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, ~~2016~~2017 and ~~2015~~2016 were as follows:

	Pension Benefits				Other Benefits				Pension Benefits				Other Benefits
	Three Months Ended September 30,								Three Months Ended September 30,
(in millions)	2016		2015		2016		2015		2017		2016		2017		2016
Service cost for benefits earned	$	113	$	123	$	13	$	14	$	118	$	113	$	14	$	13
Interest cost		179		168		19		18		178		179		20		19
Expected return on plan assets		(207)		(219)		(26)		(28)		(193)		(207)		(24)		(26)
Amortization of prior service cost		2		4		3		4		(1)		2		4		3
Amortization of net actuarial loss		6��		1		1		1		6		6		1		1
Net periodic benefit cost		93		77		10		9		108		93		15		10
Regulatory account transfer (1)		(8)		8		-		-		(23)		(8)		-		-
Total	$	85	$	85	$	10	$	9	$	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.

	Pension Benefits				Other Benefits				Pension Benefits				Other Benefits
	Nine Months Ended September 30,								Nine Months Ended September 30,
(in millions)	2016		2015		2016		2015		2017		2016		2017		2016
Service cost for benefits earned	$	339	$	360	$	39	$	41	$	354	$	339	$	44	$	39
Interest cost		537		505		57		54		535		537		58		57
Expected return on plan assets		(621)		(655)		(80)		(84)		(578)		(621)		(73)		(80)
Amortization of prior service cost		6		11		11		14		(5)		6		12		11
Amortization of net actuarial loss		18		7		3		3		17		18		3		3
Net periodic benefit cost		279		228		30		28		323		279		44		30
Regulatory account transfer (1)		(25)		26		-		-		(69)		(25)		-		-
Total	$	254	$	254	$	30	$	28	$	254	$	254	$	44	$	30

(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				Pension		Other
	Benefits		Benefits		Total		Benefits		Benefits		Total
(in millions, net of income tax)	Three Months Ended September 30, 2016						Three Months Ended September 30, 2017
Beginning balance	$	(23)	$	16	$	(7)	$	(25)	$	17	$	(8)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost
(net of taxes of $0 and $2, respectively)		2		1		3		(1)		2		1
Amortization of net actuarial loss
(net of taxes of $3 and $0, respectively)		3		1		4
(net of taxes of $2 and $0, respectively)								4		1		5
Regulatory account transfer
(net of taxes of $3 and $2, respectively)		(5)		(2)		(7)
(net of taxes of $2 and $2, respectively)								(3)		(3)		(6)
Net current period other comprehensive gain (loss)		-		-		-		-		-		-
Ending balance	$	(23)	$	16	$	(7)	$	(25)	$	17	$	(8)

(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 September 30, 2016
Beginning balance	$	(23)	$	16	$	(7)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost
(net of taxes of $0 and $2, respectively)		2		1		3
Amortization of net actuarial loss
(net of taxes of $3, and $0, respectively)		3		1		4
Regulatory account transfer
(net of taxes of $3 and $2, respectively)		(5)		(2)		(7)
Net current period other comprehensive gain (loss)		-		-		-
Ending balance	$	(23)	$	16	$	(7)

	Pension		Other				Pension		Other
	Benefits		Benefits		Total		Benefits		Benefits		Total
(in millions, net of income tax)	Three Months Ended September 30, 2015						Nine Months Ended September 30, 2017
Beginning balance	$	(21)	$	15	$	(6)	$	(25)	$	16	$	(9)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost
(net of taxes of $1 and $2, respectively)		3		2		5
(net of taxes of $2 and $5, respectively)								(3)		7		4
Amortization of net actuarial loss
(net of taxes of $0, and $0, respectively)		1		1		2
(net of taxes of $7 and $1, respectively)								10		2		12
Regulatory account transfer
(net of taxes of $3 and $3, respectively)		(4)		(3)		(7)
(net of taxes of $5 and $6, respectively)								(7)		(8)		(15)
Net current period other comprehensive gain (loss)		-		-		-		-		1		1
Ending balance	$	(21)	$	15	$	(6)	$	(25)	$	17	$	(8)

	Pension		Other
	Benefits		Benefits		Total
(in millions, net of income tax)	Nine Months Ended September 30, 2016
Beginning balance	$	(23)	$	16	$	(7)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost
(net of taxes of $2 and $5, respectively)		4		6		10
Amortization of net actuarial loss
(net of taxes of $7 and $1, respectively)		11		2		13
Regulatory account transfer
(net of taxes of $9 and $6, respectively)		(15)		(8)		(23)
Net current period other comprehensive gain (loss)		-		-		-
Ending balance	$	(23)	$	16	$	(7)

Pension

Other

Other

Benefits

Benefits

Investments

Total
(in millions, net of income tax)
Nine Months Ended September 30, 2015
Beginning balance
$
(21)

$
15

$
17

$
11
Amounts reclassified from other comprehensive income:

      Amortization of prior service cost

(net of taxes of $4, $6, and $0, respectively) (1)

7

8

-

15
      Amortization of net actuarial loss

(net of taxes of $3, $1, and $0, respectively) (1)

4

2

-

6
     Regulatory account transfer

(net of taxes of $7, $7, and $0, respectively) (1)

(11)

(10)

-

(21)
Change in investments

(net of taxes of $0, $0, and $12, respectively)

-

-

(17)

(17)
Net current period other comprehensive gain (loss)

-

-

(17)

(17)
Ending balance
$
(21)

$
15

$
-

$
(6)

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

There was no material difference between PG&E Corporation and the Utility for the information disclosed ~~above, with the exception of other investments which are held by PG&E Corporation.~~above.

Recently Adopted Accounting Guidance

~~Fair Value Measurement~~

In May 2015, the FASB issued ASU No. 2015-07, Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which standardizes reporting practices related to the fair value hierarchy for all investments for which fair value is measured using the net asset value per share. PG&E Corporation and the Utility adopted this guidance effectiveJanuary 1, 2016 and applied the requirements retrospectively for all periods presented. The adoption of this standard did not impact their Condensed Consolidated Financial Statements. All prior periods presented in these Condensed Consolidated financial statements reflect the retrospective adoption of this guidance. (See Note 8 below.)

~~Accounting for Fees Paid in a Cloud Computing Arrangement~~

In April 2015, the FASB issued ASU No. 2015-05, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement, which adds guidance to help entities evaluate the accounting treatment for cloud computing arrangements. PG&E Corporation and the Utility adopted this guidance effective January 1, 2016. The adoption of this guidance did not have a material impact on their Condensed Consolidated Financial Statements.

~~Presentation of Debt Issuance Costs~~

~~In April 2015, the FASB issued ASU No. 2015-03,~~ ~~Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,~~ which amends the existing guidance relating to the presentation of debt issuance costs. The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. PG&E Corporation and the Utility adopted this guidance effective January 1, 2016 and applied the requirements retrospectively for all periods presented. The adoption of this guidance did not have a material impact on their Condensed Consolidated Financial Statements. PG&E Corporation and the Utility reclassified $105 million and $103 million, respectively, of debt issuance costs as of December 31, 2015 with no impact to net income or total shareholders’ equity previously reported. All prior periods presented in these Condensed Consolidated Financial Statements reflect the retrospective adoption of this guidance.

~~Accounting Standards Issued But Not Yet Adopted~~

~~Share-based~~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 retrospectively adjusted. This change resulted in an increase to cash flows from operating activities and a decrease to cash flows from financing activities of $35 million for the nine months ended September 30, 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. On a retrospective basis, 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. Although PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on the Condensed Consolidated Financial Statements and related disclosures, it is not expected to have a material impact to financial results.

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, ~~2017.~~2018, with early adoption permitted. PG&E Corporation and the Utility will ~~early~~ adopt this ~~guidance~~ASU in the ~~fourth~~first quarter of ~~2016~~2018 and do not expect ~~this ASU to have~~ a material impact ~~on their~~ to the Condensed Consolidated ~~Financial~~ Statements of Cash Flows and related ~~disclosures.~~disclosures as a result of this ASU.

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 definition of a lease, recognition of lease assets and lease liabilities on the balance sheet, and ~~disclosing~~the disclosure of key information about leasing arrangements. Under the new standard, all lessees must recognize an asset and liability on the balance sheet. Operating leases were previously not recognized on the balance sheet. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2019, with ~~retrospective application.~~early adoption permitted. PG&E Corporation and the Utility plan to early adopt this guidance in the fourth quarter of 2018 using a modified retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect to apply. PG&E Corporation and the Utility expect this standard to increase lease assets and lease liabilities on the Condensed Consolidated Balance Sheets, and are ~~currently~~still evaluating the impact the guidance will have on ~~their~~ the Condensed Consolidated ~~Financial~~ Statements of Income, Statements of Cash Flows and ~~related~~lease disclosures.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued ASU No. 2016-01, Financial ~~Instruments—~~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 ~~measurement~~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 PG&E Corporation’s and the Utility’s investments are held in the nuclear decommissioning trusts. These investments 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 ~~are currently evaluating~~do not expect a material impact to the ~~impact the guidance will have on their~~ Condensed Consolidated Financial Statements and related ~~disclosures.~~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 (Topic 606), which amends ~~the~~ existing revenue recognition guidance,. ~~In August 2015, the FASB deferred~~ ~~the~~ effective ~~date of this amendment for public companies by one year to~~ January 1, 2018 ~~with early adoption permitted as~~. The objective of the ~~original effective date~~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 ~~January 1, 2017.~~financial statements through improved and expanded disclosure requirements.

~~(See~~ ~~ASU No. 2015-14,~~ ~~Revenue from Contracts with Customers (Topic 606): Deferral~~The majority of the ~~Effective Date~~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.

PG&E Corporation and the Utility ~~are currently evaluating~~intend to use the modified retrospective method when adopting the new standard on January 1, 2018. PG&E Corporation and the Utility expect that the impact of the new guidance will ~~have on their~~be immaterial to the Condensed Consolidated Financial ~~Statements~~Statements. Upon adoption of ASU 2014-09, the Utility plans to disclose revenues from contracts with customers separately from regulatory balancing account revenue and ~~related disclosures.~~disaggregate customer contract revenue by customer class.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets and Liabilities

Current Regulatory Assets

At September 30, 2017, the Utility had current regulatory assets of $573 million, which included $392 million of costs related to CEMA fire prevention and vegetation management. In 2014, the CPUC directed the Utility to perform additional vegetation management work in response to the severe drought in California.

Long-Term Regulatory Assets

Long-term regulatory assets are ~~composed~~comprised of the following:

	Balance at
	September 30,		December 31,		Asset Balance at
(in millions)	2016		2015		September 30, 2017		December 31, 2016
Deferred income taxes					$	4,373	$	3,859
Pension benefits	$	2,416	$	2,414		2,487		2,429
Deferred income taxes		3,649		3,054
Environmental compliance costs						779		778
Utility retained generation		376		411		331		364
Environmental compliance costs		760		748
Price risk management		96		138		77		92
Unamortized loss, net of gain, on reacquired debt		81		94		65		76
Other		156		170		434		353
Total long-term regulatory assets	$	7,534	$	7,029	$	8,546	$	7,951

At September 30, 2017, other long-term regulatory assets included $189 million of catastrophic event-related costs incurred 2012 through 2017 that the Utility believes is recoverable through CEMA based on historical experience in recovering costs for these types of events.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Liability Balance at
(in millions)	September 30, 2017		December 31, 2016
Cost of removal obligations	$	5,456	$	5,060
Recoveries in excess of AROs		622		626
Public purpose programs		573		567
Other		614		552
Total long-term regulatory liabilities	$	7,265	$	6,805

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the ~~2015~~2016 Form 10-K.

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

~~Long-term regulatory liabilities are composed of the following:~~

	Receivable
	Balance at
(in millions)	September 30, 2017		December 31, 2016
Electric distribution	$	-	$	132
Electric transmission		182		244
Utility generation		-		48
Gas distribution and transmission		654		541
Energy procurement		135		132
Public purpose programs		116		106
Other		391		297
Total regulatory balancing accounts receivable	$	1,478	$	1,500

	Balance at				Payable
	September 30,		December 31,		Balance at
(in millions)	2016		2015		September 30, 2017		December 31, 2016
Cost of removal obligations	$	4,939	$	4,605
Recoveries in excess of asset retirement obligations		656		631
Electric distribution					$	197	$	-
Utility generation						150		-
Electric transmission						142		99
Gas distribution and transmission						-		48
Energy procurement						131		13
Public purpose programs		539		600		426		264
Other		479		485		282		221
Total long-term regulatory liabilities	$	6,613	$	6,321
Total regulatory balancing accounts payable					$	1,328	$	645

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the ~~2015~~2016 Form 10-K.

~~Regulatory Balancing Accounts~~

The Utility tracks (1) differences between the Utility’s authorized revenue requirement and customer billings, and (2) differences between incurred costs and customer billings. To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable. Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Condensed Consolidated Balance Sheets. These differences do not have an impact on net income. Balancing accounts will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected.

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

Receivable

Balance at

September 30,

December 31,
(in millions)
2016

2015
Electric distribution
$
43

$
380
Utility generation

-

122
Gas distribution

583

493
Energy procurement

174

262
Public purpose programs

122

155
Other

553

348
Total regulatory balancing accounts receivable
$
1,475

$
1,760

Payable

Balance at

September 30,

December 31,
(in millions)
2016

2015
Utility generation
$
47

$
-
Energy procurement

109

112
Public purpose programs

289

244
Other

319

359
Total regulatory balancing accounts payable
$
764

$
715

The electric distribution, utility generation, and gas distribution balancing accounts track the collection of revenue requirements approved in the GRC. Energy procurement balancing accounts track recovery of costs related to the procurement of electricity, including any environmental compliance-related activities. Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for commission-mandated programs such as energy efficiency and low income energy efficiency.

NOTE 4: DEBT

Revolving Credit Facilities and Commercial Paper Program

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at September 30, ~~2016:~~2017:

					Letters of										Letters of
	Termination	Facility			Credit		Commercial		Facility		Termination	Facility			Credit		Commercial		Facility
(in millions)	Date	Limit			Outstanding		Paper		Availability		Date	Limit			Outstanding		Paper		Availability
PG&E Corporation	April 2021	$	300	(1)	$	-	$	165	$	135	April 2022	$	300	(1)	$	-	$	-	$	300
Utility	April 2021		3,000	(2)		31		731		2,238	April 2022		3,000	(2)		50		369		2,581
Total revolving credit facilities		$	3,300		$	31	$	896	$	2,373		$	3,300		$	50	$	369	$	2,881

(1)Includes a $50 million lender commitment to the letter of credit sublimit and a $100 million commitment for ~~“swingline”~~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 ~~2, 2017.~~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 ~~2016,~~2017, the Utility issued ~~$600~~$400 million principal amount of ~~2.95%~~3.30% Senior Notes due March 15, 2027 and $200 million principal amount of 4.00% Senior Notes due December 1, ~~2026.~~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~~Pollution Control Bonds

~~AtSeptember~~In June 2017, the Utility repurchased and retired $345 million principal amount of pollution control bonds Series 2004 A through D. Additionally in June 2017, the Utility remarketed three series of pollution control bonds, previously held in treasury, totaling $145 million in principal amount. Series 2008 F and 2010 E bear interest at 1.75% per annum and mature on November 1, 2026. Series 2008 G bears interest at 1.05% per annum and matures on December 1, 2018.

At September 30, ~~2016,~~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 ~~0.89%~~0.88% to ~~0.92%~~0.95%. At September 30, ~~2016,~~2017, the interest rates on the ~~$309~~$149 million principal amount of pollution control bonds Series 2009 ~~A-D~~A and B, and the related loan agreements, ~~ranged from 0.77% to 0.85%~~were 0.89%. ~~Pollution control bonds Series 2009 C and D will mature on December 1, 2016.~~

NOTE 5: EQUITY

PG&E Corporation’s and the Utility’s changes in equity for the nine months ended September 30, ~~2016were~~2017 were as follows:

	PG&E Corporation		Utility		PG&E Corporation		Utility
	Total		Total		Total		Total
(in millions)	Equity		Shareholders' Equity		Equity		Shareholders' Equity
Balance at December 31, 2015	$	16,828	$	17,060
Balance at December 31, 2016					$	18,192	$	18,395
Comprehensive income		711		707		1,543		1,492
Equity contributions		-		740		-		405
Common stock issued		742		-		361		-
Share-based compensation		59		-		2		-
Common stock dividends declared		(724)		(667)		(802)		(784)
Preferred stock dividend requirement		-		(10)		-		(10)
Preferred stock dividend requirement of subsidiary		(10)		-		(10)		-
Balance at September 30, 2016	$	17,606	$	17,830
Balance at September 30, 2017					$	19,286	$	19,498

In February 2017, PG&E Corporation amended its February 2015 EDA providing for the sale of PG&E Corporation common stock having an aggregate price of up to $275 million. During the ~~three and~~ nine months ended September 30, ~~2016,~~2017, PG&E Corporation sold 0.4 ~~million and 2.6~~ million shares of its common stock under the February ~~2015 equity distribution agreement~~2017 EDA for cash proceeds of ~~$26~~$28.4 million, ~~and $149 million, respectively,~~ net of commissions paid of $0.2 ~~million and $1.3 million, respectively.~~million. There were no issuances under the February 2017 EDA for the three months ended September 30, 2017. As of September 30, ~~2016,~~2017, the remaining ~~gross~~ sales available under this agreement were ~~$275 million.~~

~~In August 2016, PG&E Corporation sold 4.9 million shares of its common stock in an underwritten public offering for net cash proceeds of $309~~$246.3 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 nine months ended September 30, ~~2016, 5.7~~2017, 6.4 million shares were issued for cash proceeds of ~~$269~~$316 million under these plans.

NOTE 6: EARNINGS PER SHARE

PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS:

	Three Months Ended				Nine Months Ended				Three Months Ended				Nine Months Ended
	September 30,				September 30,				September 30,				September 30,
(in millions, except per share amounts)	2016		2015		2016		2015		2017		2016		2017		2016
Income available for common shareholders	$	388	$	307	$	701	$	740	$	550	$	388	$	1,532	$	701
Weighted average common shares outstanding, basic		501		486		497		481		513		501		511		497
Add incremental shares from assumed conversions:
Employee share-based compensation		2		3		3		3		3		2		3		3
Weighted average common shares outstanding, diluted		503		489		500		484		516		503		514		500
Total earnings per common share, diluted	$	0.77	$	0.63	$	1.40	$	1.53	$	1.07	$	0.77	$	2.98	$	1.40

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 ~~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.

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

Price risk management activities that meet the definition of derivatives are recorded at fair value on 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 current ratemaking mechanism remains in place and~~ the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.

The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Condensed Consolidated Balance Sheets at fair value. Eligible derivatives are accounted for under the accrual method of accounting.

Volume of Derivative Activity

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

Contract Volume at

September 30,

December 31,
Underlying Product

Instruments

2016

2015
Natural Gas (1) (MMBtus (2))

Forwards, Futures and Swaps

376,296,893

333,091,813

Options

118,017,176

111,550,004
Electricity (Megawatt-hours)

Forwards, Futures and Swaps

3,128,038

3,663,512

Congestion Revenue Rights (3)

172,756,395

216,383,389

		Contract Volume at
		September 30,	December 31,
Underlying Product	Instruments	2017	2016
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	300,594,593	323,301,331
	Options	79,640,435	96,602,785
Electricity (Megawatt-hours)	Forwards, Futures and Swaps	3,505,504	3,287,397
	Congestion Revenue Rights (3)	249,876,873	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 September 30, 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	$	47	$	(7)	$	9	$	49
Other noncurrent assets – other		121		(3)		-		118
Current liabilities – other		(54)		7		11		(36)
Noncurrent liabilities – other		(81)		3		7		(71)
Total commodity risk	$	33	$	-	$	27	$	60

At December 31, 2016, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk								Commodity Risk
	Gross Derivative						Total Derivative		Gross Derivative						Total Derivative
(in millions)	Balance		Netting		Cash Collateral		Balance		Balance		Netting		Cash Collateral		Balance
Current assets – other	$	100	$	(8)	$	14	$	106	$	91	$	(10)	$	1	$	82
Other noncurrent assets – other		128		(8)		-		120		149		(9)		-		140
Current liabilities – other		(67)		8		10		(49)		(48)		10		-		(38)
Noncurrent liabilities – other		(104)		8		7		(89)		(101)		9		3		(89)
Net commodity risk	$	57	$	-	$	31	$	88
Total commodity risk									$	91	$	-	$	4	$	95

~~At December 31, 2015, the Utility’s outstanding derivative balances were as follows:~~

Commodity Risk

Gross Derivative

Total Derivative
(in millions)
Balance

Netting

Cash Collateral

Balance
Current assets – other
$
97

$
(4)

$
25

$
118
Other noncurrent assets – other

172

(2)

-

170
Current liabilities – other

(102)

4

44

(54)
Noncurrent liabilities – other

(140)

2

21

(117)
Net commodity risk
$
27

$
-

$
90

$
117

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

	Commodity Risk								Commodity Risk
	Three Months Ended				Nine Months Ended				Three Months Ended				Nine Months Ended
	September 30,				September 30,				September 30,				September 30,
(in millions)	2016		2015		2016		2015		2017		2016		2017		2016
Unrealized gain (loss) - regulatory assets and liabilities (1)	$	(29)	$	(45)	$	30	$	(69)	$	(6)	$	(29)	$	(58)	$	30
Realized gain (loss) - cost of electricity (2)		(7)		1		(48)		4
Realized loss - cost of electricity (2)										(4)		(7)		(8)		(48)
Realized loss - cost of natural gas (2)		(9)		(3)		(15)		(8)		(1)		(9)		(5)		(15)
Net commodity risk	$	(45)	$	(47)	$	(33)	$	(73)	$	(11)	$	(45)	$	(71)	$	(33)

(1)Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being recorded to the Condensed Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings.

(2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.

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

The majority of the Utility’s derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. At September 30, ~~2016,~~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				Balance at
	September 30,		December 31,		September 30,		December 31,
(in millions)	2016		2015		2017		2016
Derivatives in a liability position with credit risk-related
contingencies that are not fully collateralized	$	(8)	$	(2)	$	(16)	$	(24)
Related derivatives in an asset position		4		-		3		19
Collateral posting in the normal course of business related to
these derivatives		2		-		11		4
Net position of derivative contracts/additional collateral
posting requirements (1)	$	(2)	$	(2)	$	(2)	$	(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 ~~and other investments~~ at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:

Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 – Other inputs that are directly or indirectly observable in the marketplace.

Level 3 – Unobservable inputs which are supported by little or no market activities.

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.

Fair Value Measurements

At September 30, 2016
(in millions)
Level 1

Level 2

Level 3

Netting (1)

Total
Assets:

Short-term investments
$
-

$
-

$
-

$
-

$
-
Nuclear decommissioning trusts

Short-term investments

1

-

-

-

1
Global equity securities

1,678

-

-

-

1,678
Fixed-income securities

720

530

-

-

1,250
Assets measured at NAV

-

-

-

-

14
Total nuclear decommissioning trusts (2)

2,399

530

-

-

2,943
Price risk management instruments

(Note 7)

Electricity

10

16

192

(2)

216
Gas

-

10

-

-

10
Total price risk management instruments

10

26

192

(2)

226
Rabbi trusts

Fixed-income securities

-

59

-

-

59
Life insurance contracts

-

77

-

-

77
Total rabbi trusts

-

136

-

-

136
Long-term disability trust

Short-term investments

4

-

-

-

4
Assets measured at NAV

-

-

-

-

138
Total long-term disability trust

4

-

-

-

142
Total assets
$
2,413

$
692

$
192

$
(2)

$
3,447
Liabilities:

Price risk management instruments

(Note 7)

Electricity
$
25

$
8

$
136

$
(33)

$
136
Gas

-

2

-

-

2
Total liabilities
$
25

$
10

$
136

$
(33)

$
138

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

~~(2)~~ ~~Represents amount before deducting $346 million, primarily related to deferred taxes on appreciation of investment value.~~

	Fair Value Measurements										Fair Value Measurements
	At December 31, 2015										At September 30, 2017
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total		Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	64	$	-	$	-	$	-	$	64	$	120	$	-	$	-	$	-	$	120
Nuclear decommissioning trusts
Short-term investments		36		-		-		-		36		23		-		-		-		23
Global equity securities		1,520		-		-		-		1,520		1,875		-		-		-		1,875
Fixed-income securities		694		521		-		-		1,215		697		569		-		-		1,266
Assets measured at NAV		-		-		-		-		13		-		-		-		-		16
Total nuclear decommissioning trusts (2)		2,250		521		-		-		2,784		2,595		569		-		-		3,180
Price risk management instruments
(Note 9 in the 2015 Form 10-K)
(Note 7)
Electricity		-		9		259		18		286		4		7		153		(1)		163
Gas		-		1		-		1		2		-		4		-		-		4
Total price risk management instruments		-		10		259		19		288
Total price risk management
instruments												4		11		153		(1)		167
Rabbi trusts
Fixed-income securities		-		57		-		-		57		-		64		-		-		64
Life insurance contracts		-		70		-		-		70		-		71		-		-		71
Total rabbi trusts		-		127		-		-		127		-		135		-		-		135
Long-term disability trust
Short-term investments		7		-		-		-		7		5		-		-		-		5
Assets measured at NAV		-		-		-		-		158		-		-		-		-		148
Total long-term disability trust		7		-		-		-		165		5		-		-		-		153
Total assets	$	2,321	$	658	$	259	$	19	$	3,428
TOTAL ASSETS											$	2,724	$	715	$	153	$	(1)	$	3,755
Liabilities:
Price risk management instruments
(Note 9 in the 2015 Form 10-K)
(Note 7)
Electricity	$	69	$	1	$	170	$	(70)	$	170	$	11	$	17	$	105	$	(28)	$	105
Gas		-		2		-		(1)		1		-		2		-		-		2
Total liabilities	$	69	$	3	$	170	$	(71)	$	171
TOTAL LIABILITIES											$	11	$	19	$	105	$	(28)	$	107

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

(2) Represents amount before deducting ~~$314~~$387 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 nine months ended September 30, ~~2016~~2017 and ~~2015.~~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 ~~debt~~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

~~On January 1, 2016, PG&E Corporation and the Utility adopted FASB ASU No. 2015-07,~~ ~~Fair Value Measurement (Topic 820): Disclosures for~~ Investments ~~in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)and applied it retrospectively for the periods presented in their Condensed Consolidated Financial Statements. (See Note 2 above.) In accordance with this guidance, 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~~PG&E Corporation’s Chief ~~Risk and Audit~~Financial Officer, ~~of the Utility,~~ is responsible for determining the fair value of the Utility’s price risk management derivatives. The Utility’s finance and risk management functions collaborate to determine the appropriate fair value methodologies and classification for each derivative. Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.

Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. (See Note 7 above.)

	Fair Value at								Fair Value at
(in millions)	At September 30, 2016				Valuation	Unobservable			At September 30, 2017				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)		Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	192	$	43	Market approach	CRR auction prices	$	(23.81) - 8.76	$	153	$	35	Market approach	CRR auction prices	$	(11.88) - 6.93
Power purchase agreements	$	-	$	93	Discounted cash flow	Forward prices	$	18.07 - 38.80	$	-	$	70	Discounted cash flow	Forward prices	$	18.81 - 38.80

(1) Represents price per megawatt-hour

	Fair Value at								Fair Value at
(in millions)	At December 31, 2015				Valuation	Unobservable			At December 31, 2016				Valuation	Unobservable
Fair Value Measurement	Assets		Liabilities		Technique	Input	Range (1)		Assets		Liabilities		Technique	Input	Range (1)
Congestion revenue rights	$	259	$	63	Market approach	CRR auction prices	$	(161.36) - 8.76	$	181	$	35	Market approach	CRR auction prices	$	(11.88) - 6.93
Power purchase agreements	$	-	$	107	Discounted cash flow	Forward prices	$	15.08 - 37.27	$	-	$	91	Discounted cash flow	Forward prices	$	18.07 - 38.80

(1) Represents price per megawatt-hour

Level 3 Reconciliation

The following ~~tables present~~table presents the reconciliation for Level 3 price risk management instruments for the three and nine months ended September 30, ~~2016~~2017 and ~~2015:~~2016:

	Price Risk Management Instruments				Price Risk Management Instruments
(in millions)	2016		2015		2017		2016
Asset (liability) balance as of July 1	$	66	$	48	$	48	$	66
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		(10)		(27)		-		(10)
Asset (liability) balance as of September 30	$	56	$	21	$	48	$	56

(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.

	Price Risk Management Instruments				Price Risk Management Instruments
(in millions)	2016		2015		2017		2016
Asset (liability) balance as of January 1	$	89	$	69	$	55	$	89
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)		(33)		(48)		(7)		(33)
Asset (liability) balance as of September 30	$	56	$	21	$	48	$	56

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 September 30, ~~2016~~2017 and December 31, ~~2015,~~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 September 30, ~~2016~~2017 and December 31, ~~2015.~~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 September 30, 2016				At December 31, 2015				At September 30, 2017				At December 31, 2016
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
PG&E Corporation	$	350	$	356	$	350	$	354	$	349	$	352	$	348	$	352
Utility		15,417		18,440		14,918		16,422		16,211		18,672		15,813		17,790

Available for Sale Investments

The following table provides a summary of available-for-sale investments:

				Total		Total						Total		Total
	Amortized			Unrealized		Unrealized		Total Fair	Amortized			Unrealized		Unrealized		Total Fair
(in millions)	Cost			Gains		Losses		Value	Cost			Gains		Losses		Value
As of September 30, 2016
As of September 30, 2017
Nuclear decommissioning trusts
Short-term investments	$	1	$	-	$	-	$	1	$	23	$	-	$	-	$	23
Global equity securities		579		1,116		(3)		1,692		540		1,353		(2)		1,891
Fixed-income securities		1,164		89		(3)		1,250		1,216		56		(6)		1,266
Total (1)	$	1,744	$	1,205	$	(6)	$	2,943	$	1,779	$	1,409	$	(8)	$	3,180
As of December 31, 2015
As of December 31, 2016
Nuclear decommissioning trusts
Short-term investments	$	36	$	-	$	-	$	36	$	9	$	-	$	-	$	9
Global equity securities		508		1,034		(9)		1,533		584		1,157		(3)		1,738
Fixed-income securities		1,165		58		(8)		1,215		1,156		48		(12)		1,192
Total (1)	$	1,709	$	1,092	$	(17)	$	2,784	$	1,749	$	1,205	$	(15)	$	2,939

(1) Represents amounts before deducting ~~$346~~$387 million and ~~$314~~$333 million at September 30, ~~2016~~2017 and December 31, ~~2015,~~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)	September 30, ~~2016~~2017
Less than 1 year	$	3327
1–5 years		~~443~~403
5–10 years		~~271~~340
More than 10 years		~~503~~496
Total maturities of fixed-income securities	$	~~1,250~~1,266

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

	Three Months Ended				Nine Months Ended				Three Months Ended				Nine Months Ended
	September 30,				September 30,				September 30,				September 30,
	2016		2015			2016	2015		2017		2016			2017	2016
(in millions)
Proceeds from sales and maturities of nuclear decommissioning
trust investments	$	257	$	244	$	1,019	$	1,023	$	249	$	257	$	1,043	$	1,019
Gross realized gains on securities held as available-for-sale		6		3		15		50		8		6		50		15
Gross realized losses on securities held as available-for-sale		(14)		(12)		(17)		(25)		-		(14)		(8)		(17)

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. ~~PG&E Corporation and~~A gain contingency is recorded in the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact ofperiod in which all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred.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

Litigation and Regulatory Citations in Connection with the Butte Fire

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, destroyed549 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.

Third-Party Claims

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 September 30, 2017, 77 known 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. The complaints involve approximately 3,770 individual plaintiffs representing approximately 2,080 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. Plaintiffs also seek punitive damages. The number of individual complaints and plaintiffs may increase in the future. The Utility continues mediating and settling cases.

Also, in May 2017, the OES indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $190 million. This claim would include costs incurred by the OES for tree and debris removal, infrastructure damage, erosion control, and other claims related to the Butte fire. Also, in June 2017, the County of Calaveras indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $85 million. This claim would include costs that the County of Calaveras incurred or expects to incur for infrastructure damage, erosion control, and other costs related to the Butte fire.

On April 28, 2017, the Utility moved for summary adjudication on plaintiffs’ claims for punitive damages. On August 10, 2017, the Court denied the Utility’s motion on the grounds that plaintiffs might be able to show conscious disregard for public safety based on the fact that the Utility relied on contractors to fulfill their contractual obligation to hire and train qualified employees. On August 16, 2017, the Utility filed a writ with the Court of Appeals challenging this novel theory of punitive damages liability. The Court of Appeals accepted the writ on September 15, 2017 and ordered the trial court and plaintiffs to show cause why the relief requested by the Utility should not be granted. Briefing on the writ should be completed by early 2018.

In the third quarter of 2017, the Utility reached settlements with plaintiffs in the “preference” trial involving six households and with the plaintiffs in the representative trial that had been scheduled for August 2017 and October 2017, respectively. While there are no trials related to the Butte fire currently scheduled, one plaintiff has moved for a preference trial involving one household. The motion is set for hearing on December 1, 2017.

On October 25, 2017, the Utility filed a motion to stay the trial court proceedings pending a decision by the Court of Appeals on the pending writ of mandate regarding punitive damages. A hearing on the stay motion is calendared for December 1, 2017.

Estimated Losses from Third-Party Claims

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. On June 22, 2017, the Superior Court for the County of Sacramento ruled on a motion of several plaintiffs and found that the Utility is liable for inverse condemnation. While the ruling is binding only between the Utility and the plaintiffs in the coordination proceeding, others could file lawsuits and make similar claims. 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. While the Utility believes it was not negligent, there can be no assurance that a court or jury would agree with the Utility.

The Utility currently believes that it is probable that it will incur a loss of at least $1.1 billion, increased from the $750 million previously estimated as of December 31, 2016, in connection with the Butte fire. The Utility’s updated estimate resulted primarily from an increase in the number of claims filed against the Utility and experience to date in resolving claims. This amount is based on updated 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 certain other damages, but does not include punitive damages for which the Utility could be liable. In addition, while this amount includes the Utility’s early assumptions about fire suppression costs (including its assessment of the Cal Fire loss), it does not include any significant portion of the estimated claims from the OES and the County of Calaveras. The Utility still does not have sufficient information to reasonably estimate any liability it may have for these additional claims.

The Utility currently is unable to reasonably estimate the upper end of the range of losses because it has insufficient information on the claims of over 1,000 households, including all of the recently filed claims, as well as the claims from the OES and the County of Calaveras. 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, results from the ongoing mediation and settlement process, review of potential claims from the OES and the County of Calaveras, outcomes of future court or jury decisions, and information about damages, including punitive damages, that the Utility could be liable for, management estimates and assumptions regarding the financial impact of the Butte fire may result in material increases to the loss accrued.

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⁽¹⁾		(60)
Balance at December 31, 2016	$	690
Accrued losses		350
Payments⁽¹⁾		(338)
Balance at September 30, 2017	$	702

(1) As of September 30, 2017 the Utility entered into settlement agreements in connection with the Butte fire corresponding to approximately $515 million of which $398 million has been paid by the Utility.

In addition to the amounts reflected in the table above, the Utility has incurred cumulative legal expenses of $72 million in connection with the Butte fire. For the three and nine months ended September 30, 2017, the Utility has incurred legal expenses in connection with the Butte fire of $18 million and $45 million, respectively.

Loss Recoveries

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 $922 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 September 30, 2017, the Utility recorded $922 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, in the three and nine months ended September 30, 2017, the Utility received $21 million and $53 million, respectively, of reimbursements from the insurance policies of one of its vegetation management contractors (excluded from the table below). Recoveries of additional amounts under the insurance policies of the Utility’s vegetation management contractors, including policies where the Utility is listed as an additional insured, 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
Reimbursements		(50)
Balance at December 31, 2016	$	575
Accrued insurance recoveries		297
Reimbursements		(131)
Balance at September 30, 2017	$	741

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.

Regulatory Citations

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. The Utility paid the citations in June 2017.

“Ghost Ship” Fire

On December 2, 2016, 36 people died in a fire that occurred in the “Ghost Ship” warehouse in Oakland, California, during a music event. The families of 34 people who died in the fire have filed lawsuits against the property owner, the master tenant and neighboring tenants, and others, alleging defective electrical wiring and violations of fire safety codes.

On May 16, 2017, a master complaint was filed, and added both PG&E Corporation and the Utility as defendants. The master complaint alleges that the Utility violated the California Labor Code and various electric rules in that it (1) should have inspected the premises to evaluate potential workplace hazards to Utility employees installing/maintaining its meters there, (2) should not have permitted sub-meters in the building or should have inspected those sub-meters, and (3) should have known that the building’s sub-meters and electrical system as a whole were dangerous and should have terminated service. The Utility filed a demurrer to the master complaint on June 30, 2017, on multiple grounds, including that the Utility has no duty to inspect its customers’ electrical equipment. On September 12, 2017, Alameda County Superior Court (the “court”) denied the Utility’s demurrer and on October 6, 2017, the Utility filed its answer with the court. The governmental entities (City of Oakland, County of Alameda and State of California) filed demurrers on September 12, 2017. On October 9, 2017, the plaintiffs dismissed, without prejudice, the State of California as a party to the case. On October 13, 2017, the plaintiffs filed opposition briefs to the demurrers filed by the City of Oakland and the County of Alameda. A hearing is scheduled for November 7, 2017.

Several investigations regarding the origin and cause of the fire were conducted, including by the City of Oakland and the County of Alameda, the CPUC, and a third-party consulting and engineering firm. In June 2017, the City of Oakland released Oakland Fire Department’s report of the investigation stating that the cause of the fire was undetermined. The other investigations remain underway.

PG&E Corporation and the Utility are uncertain when and how the Ghost Ship Fire lawsuit will be resolved and believe there is a remote possibility a material loss will occur.

Valero Refinery Outage

On June 30, 2017, Valero Energy Corp. filed a lawsuit against the Utility after an electric outage occurred in its Benicia refinery in May 2017. Valero’s complaint alleges causes of action for breach of contract, breach of implied contract, breach of implied warranty, breach of covenant of good faith and fair dealing, negligence and gross negligence and seeks $75 million in damages from the Utility, resulting from refinery equipment damage, lost revenue and punitive damages. The Utility retained a third-party consulting and engineering firm to perform a causal evaluation of this outage. On September 11, 2017, Valero filed a first amended complaint removing its gross negligence and punitive damage claims. On October 23, 2017, the Utility filed with the court its response to Valero’s amended complaint. On October 27, 2017, Valero served the Utility with initial disclosures stating Valero’s total claim is $114 million in damages associated with equipment damage and lost profits.

PG&E Corporation and the Utility believe it is reasonably possible that they will incur a material loss as a result of this lawsuit, but is unable to reasonably estimate the amount or range because it is in early stages of litigation.

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. The Utility is cooperating with this investigation. It is uncertain whether any charges will be brought against the Utility as a result of these investigations.

CPUC Matters

Order Instituting an Investigation into Compliance with Ex Parte Communication Rules

~~During 2014 and 2015,~~On September 1, 2017, the Utility filed several reports to notify the CPUC of communications that the Utility believes may have constituted or described ex parte communications that either should not have occurred or that should have been timely reported to the CPUC. Ex parte communications include communications between a decision maker or a commissioner’s advisor and interested persons concerning substantive issues in certain formal proceedings. Certain communications are prohibited and others are permissible with proper noticing and reporting.

On November 23, 2015, the CPUC issued an OII into whether the Utility should be sanctioned for violating rules pertaining to ex parte communications and Rule 1.1 of the CPUC’s Rules of Practice and Procedure governing the conduct of those appearing before the CPUC. The OII cites some of the communications the Utility reported to the CPUC. The OII also cites the ex parte violations alleged in the City of San Bruno’s July 2014 motion, which it filed in CPUC investigations related to the Utility’s natural gas transmission pipeline operations and practices.

~~On July 12, 2016, the~~ assigned ~~commissioner and~~ ALJ issued a ~~ruling that adopted recommendations included~~PD in ~~a process report~~this proceeding adopting, with one modification, the settlement agreement jointly submitted to the CPUC on March 28, 2017, by the Utility, the Cities of San Bruno and San Carlos, the ORA, the SED, ~~TURN (together,~~and TURN.

If adopted, the ~~“other parties”)~~PD would increase the payment to the California General Fund from $1 million to $12 million resulting in a total penalty of $97.5 million comprised of: (1) a $12 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 the Utility’s 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 ~~in April 2016. The approved framework for resolving~~and CPUC decision-makers, as well as certification of employee training on the ~~proceeding included a total of 159 communications (the 46 communications already included in~~CPUC ex parte communication rules. Under the ~~OII and 113 additional communications) in the scope~~terms of the ~~proceeding,~~settlement agreement, customers will bear no costs associated with the financial remedies set forth above.

On September 21, 2017, the Utility submitted a ~~procedure for moving undisputed facts into~~motion to the ~~evidentiary record and~~CPUC accepting the proposed modification of the settlement agreement to increase the Utility’s payment to the California General Fund from $1 million to $12 million. Further, the Utility also reported that it has identified several communications that appear to raise issues similar to other communications that are part of this proceeding.

On November 1, 2017, the Utility filed a ~~diligence process for providing additional factual information. The~~status report advising the CPUC that the Utility and the ~~other~~ parties ~~disagreed on~~to the ~~inclusion of~~settlement agreement were unable to reach an ~~additional 21~~agreement with respect to how to proceed regarding communications inthat the scope and filed briefs on the issue. The ruling confirmed that these additional 21 communications were not included within the scope of the OII and do not, in themselves, appear to be ex parte violations, but granted the other parties’ request to seek additional information regarding these communications.

~~In a status report jointly submitted~~Utility reported to the CPUC on ~~October 14, 2016,~~September 21, 2017. Also on November 1, 2017, the non-Utility parties ~~proposed an update~~ to the ~~framework~~settlement requested that the CPUC approve the settlement, as modified by the PD, and open a second phase of the OII to investigate and consider appropriate sanctions for ~~resolving~~ the ~~proceeding. The revised framework includes a total of 165~~new communications ~~(159 communications previously included in~~reported by the ~~proceeding, reduced by two communications the other parties agreed not to pursue, plus 8 additional communications out of~~Utility on September 21, communications previously in disagreement). The parties also proposed to begin settlement discussions on November 30, 2016, followed by a joint status report proposed for January 13, 2017. In the event a settlement cannot be reached, the parties proposed to submit their opening briefs on January 27, 2017, and ~~reply briefs on February 17, 2017. On October 31, 2016, the CPUC issued a proposed decision adopting the schedule proposed by the parties in the October 14, 2016 status report.~~ others that may be discovered.

The ~~proposed decision extends the~~ statutory deadline for this proceeding previously was extended to ~~May 17,~~December 29, 2017. The Utility is unable to predict the outcome of this proceeding.

At September 30, 2017, ~~in order to allow~~PG&E Corporation’s and the ~~parties to complete settlement discussions or file briefs, and~~Utility’s Condensed Consolidated Balance Sheets include a $24 million accrual for the ~~ALJ~~amounts payable to ~~prepare~~the California General Fund and ~~file a proposed decision.~~

~~The Utility expects that~~ the ~~other parties may argue that the number~~Cities of ~~violations exceeds the 165 communications referenced~~San Bruno and San Carlos. In accordance with accounting rules, adjustments related to revenue requirements would be recorded in the ~~October 14, 2016 joint status report either because a single communication may have violated~~periods in which they are incurred.

For more ~~than one rule or because they believe some~~information about the proceeding, see Note 13 “Contingencies and Commitments” of the ~~material provided during discovery constitutes impermissible ex parte communications.~~Notes to the Consolidated Financial Statements in the 2016 Form 10-K.

Order Instituting an Investigation into the Utility’s Safety Culture

On August 27, 2015, the CPUC began a formal investigation into whether the organizational culture and governance of PG&E Corporation and the Utility prioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards. The ~~Utility expects~~CPUC directed the SED to ~~contest many~~evaluate the Utility’s and PG&E Corporation’s organizational culture, governance, policies, practices, and accountability metrics in relation to the Utility’s record of ~~these assertions. If~~operations, including its record of safety incidents. The CPUC authorized the ~~matter does not settle,~~SED to engage a consultant to assist in the SED’s investigation and the preparation of a report containing the SED’s assessment.

On May 8, 2017, the CPUC President released the consultant’s report, accompanied by a scoping memo and ruling. The scoping memo establishes a second phase in this OII in which the CPUC will ~~determine which communications included within~~evaluate the ~~scope~~safety recommendations of the consultant that may lead to the CPUC’s adoption of the recommendations in the report, in whole or in part. This phase of the proceeding ~~were in violation of its rules. The CPUC~~ will also ~~determine whether~~consider all necessary measures, including, but not limited to, ~~impose penalties or other remedies, as~~ a ~~result~~reduction of ~~a potential settlement or otherwise. The CPUC can impose fines up to $50,000 for each violation, and up to $50,000 per day if~~the Utility’s return on equity until any recommendations adopted by the CPUC ~~determines that~~are implemented. The Utility plans to adopt and implement the ~~violation was continuing. The CPUC has wide discretion to determine the amount of penalties based on the totality~~vast majority of the ~~circumstances, including such factors as how many days each violation continued; the gravity of the violations; the type of harm caused~~consultant’s recommendations by the ~~violations~~middle of 2018. A workshop took place in September 2017 at which the consultant presented its report and ~~the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation.~~answered stakeholders’ questions. The ~~CPUC~~Utility’s testimony is also required to consider the appropriateness of the amount of the penalty to the size of the entity charged. The CPUC has historically exercised broad discretion in determining whether violations are continuing and the amount of penaltiesexpected to be ~~imposed.~~ filed with the CPUC in the fourth quarter of 2017 with other parties’ testimony and evidentiary hearings expected in the first quarter of 2018.

PG&E Corporation and the Utility ~~believe it is probable that~~are unable to predict the outcome of this proceeding, including whether additional fines, penalties, or other ratemaking tools will ultimately be adopted by the CPUC, and whether the CPUC will ~~impose penalties~~require that a portion of return on equity for the Utility ~~in the OII but are unable to reasonably estimate the amount or range of future charges that could~~ be ~~incurred, because it is uncertain how~~dependent on making safety progress as the CPUC ~~will calculate the number of violations or the penalty for any violations.~~may define in this proceeding.

Finally, the U.S. Attorney’s Office in San Francisco and the California Attorney General’s office also have been investigating matters related to allegedly improper communication between the Utility and CPUC personnel. The Utility is cooperating with these investigations. It is uncertain whether any charges will be brought against the Utility.

~~CPUC Investigation Regarding Natural Gas Distribution Facilities Record-Keeping~~

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

On August 18, 2016, the CPUC unanimously approved a modified presiding officer’s decision (the “MOD POD”) issued on August 17, 2016 in this investigation. In accordance with the MOD POD, the amount of the fine increased from $24.3 million to $25.6 million, to include a $50,000 fine omitted from the June 1, 2016 presiding officer’s decision (the “POD”) and $1.3 million resulting from the per-day fine increase for the missing leak repair records for the De Anza division. With the $10.85 million citation previously paid in 2015 for the City of Carmel-by-the-Sea (“Carmel”) incident, the total fine imposed on the Utility was $36.5 million. The remaining $25.6 million was paid in September 2016.

In accordance with the MOD POD, the decision denies the appeals previously filed by the SED and Carmel from the POD, and closes this proceeding but allows the parties an opportunity to request that this proceeding be reopened if needed to ensure proper implementation of a compliance plan to be developed by the parties.

On September 26, 2016, the SED filed an application for rehearing of the CPUC’s decision. Specifically, the application indicates that the CPUC erred in certain of its determinations (including those related to maximum allowable operating pressure documentation that, if adopted, could result in an additional fine of $7 million), calculations (including thoserelated to the missing DeAnza records violations) and certain other findings, and requests that the CPUC adopt its recommendations. On October 11, 2016, the Utility submitted its response to the CPUC in which it opposed the SED’s application for rehearing arguing that the application failed to identify a legal error warranting rehearing by the CPUC. The Utility cannot predict when or if the CPUC will grant the rehearing or if it will adopt the SED’s recommendations.

On October 24, 2016, the Utility held a meet and confer with parties to develop remedial measures necessary to address the issues identified in the CPUC decision with the objective of establishing a compliance plan that includes all feasible and cost-effective measures necessary to improve the Utility’s natural gas distribution system record-keeping. Under the current schedule, the parties are expected to submit a compliance plan to the CPUC on or before December 16, 2016.

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 SED periodically audits utility operating practices and conducts investigations of potential violations of laws and regulations applicable to the safety of the California utilities’ electric and natural gas facilities and operations. The CPUC has delegated authority to the SED to issue citations and impose ~~fines~~penalties for violations identified through audits, investigations, or self-reports. The SED can impose fines up to $50,000 for each violation, per day, and can consider the discretionary factors discussed above (see “Order Instituting an Investigation into Compliance with Ex Parte Communication Rules” above) in determining theThere are a number of audit findings, as well as other potential violations identified through various investigations and ~~whether to impose daily fines for continuing violations. On September 29, 2016,~~ the ~~CPUC issued a final decision adopting improvements~~Utility’s self-reported non-compliance with laws and ~~refinements to its gas and electric safety citation programs. Specifically, the final decision refines the criteria for~~regulations, on which the SED has yet to ~~use in determining whether~~act. This includes the Utility’s February 2017 self-report related to ~~issue a citation and~~customer service representatives who handle gas emergency calls that was not timely submitted to the amount of penalty, sets an administrative limit of $8 million per citation issued, makes self-reporting voluntary in both gas and electric programs, adopts detailed criteria for the utilities to use to voluntarily self-report a potential violation, and refines other issues in the programs. The decision also merges the rules applicable to its gas and electric safety citation programs into a single set of rules that replace the previous safety citation programs and adopts non-substantive changes to these programs so that the programs can be similar in structure and process where appropriate. The decision closes the proceeding.

~~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.~~CPUC. The Utility believes it is probable that the SED will impose ~~fines~~penalties or take other enforcement action ~~based on~~with respect to some or all of ~~the Utility’s self-reported non-compliance with laws and regulations or based on allegations of non-compliance with such laws and regulations that are contained in some of the SED’s audits.~~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 ~~has~~and other CPUC staff have in determining whether to bring enforcement action and the number of factors that can be considered in determining the amount of fines.

In September 2016, the Utility reported that it discovered in November 2015 that approximately 550,000 atmospheric corrosion inspections on above-ground gas distribution meters completed in 2014, which constituted 35% of such inspections in 2014, were performed by non-operator qualified personnel. The Utility did not provide timely notification of such non-compliance to the CPUC. The SED is investigating the Utility’s self-report.

The SED ~~could~~has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it is required to impose ~~fines on~~ the ~~Utility~~maximum statutory penalty of ~~up to~~ $50,000, with an administrative limit of $8 million per ~~inspection, and also for failure to timely file a self-report in connection with such inspections.~~citation issued. The SED ~~has the authority to issue~~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 ~~citation for a series~~day. The SED also has wide discretion to determine the amount of ~~related incidents,~~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 also is required to consider the appropriateness of the amount of the penalty to the size of the entity charged. The SED historically has 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 ~~is unable~~ranging from $50,000 to ~~reasonably estimate the amount or range~~$16.8 million for violations of future charges that could be incurred for fines that could be imposed with respect to this self-report, for the reasons indicated above, or to predict whether the CPUC will open a formal proceeding as a result of the SED’s investigation.

~~Federal Matters~~

~~Federal Criminal Trial~~electric and natural gas laws and regulations.

On ~~June 14, 2016,~~January 12, 2017, a ~~federal criminal trial~~residential structure fire occurred in Yuba City, California resulting in the collapse of the house and injuries to two persons inside the house. The CPUC, a third-party engineering firm engaged by the Utility, and local fire and police officials have investigated the incident. Following SED’s investigation which included a review of the third-party engineering firm’s report, on October 20, 2017, the SED issued a notice of probable violations against the ~~Utilitybegan in the United States District Court~~Utility. The SED found two violations, for the Northern District of California, in San Francisco, on 12 felony counts alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record-keeping, pipeline integrity management, and identification of pipeline threats, and one felony count charging that the Utility illegally obstructed the NTSB investigation into the cause of the San Bruno accident. On July 26, 2016, the court granted the government’s motion to dismiss Count 13 alleging that the Utility knowingly and willfully failed to retain a strength test pressure record with respect to a distribution feeder main, thereby reducing the total number of counts from 13 to 12.

On August 2, 2016, the remaining Alternative Fines Act sentencing allegations in the case were dismissed. The Alternative Fines Act states, in part: “If any person derives pecuniary gain from the offense, or if the offense results in pecuniary loss to a person other than the defendant, the defendant may be fined not more than the greater of twice the gross gain or twice the gross loss.” (The remaining allegations related to $281 million of gross gains that the government alleged the Utility derived. As previously disclosed, in December 2015, the court dismissed the government’s allegations regarding the amount of losses.)

On August 9, 2016, the jury returned its verdict. The jury acquitted the Utility on all six of the record-keeping allegations but found the Utility guilty on six felony counts that include one count of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act.

On August 16, 2016, the Utility filed a motion under Federal Rule of Criminal Procedure 29 for a judgment of acquittal, arguing that the evidence was insufficient to sustain a conviction for the six counts on which the ~~jury returned~~SED could issue a ~~guilty verdict. The court indicated that it will decide on this motion based on briefs filed by the parties, without oral argument.~~penalty of up to $8 million per violation. The Utility ~~is not able to predict when the court will decide on the motion. A sentencing hearing is currently scheduled for January 23, 2017.~~

The maximum statutory fine for each felony count is $500,000, for total potential maximum statutory fines of $3 million. At September 30, 2016, the Utility’s Condensed Consolidated Balance Sheets include a $3 million accrual in connection with the jury verdict. The Utility also couldmay incur material costs, not recoverable through rates, to implement remedial and other measures that could be imposed, such as a requirement that the Utility’s natural gas operations and/or compliance and ethics programs be supervised by an independent third-party monitor. If appointed, the Utility expects a monitor would serve for a period of time and report periodically to the court or a department or agency of the government.

~~Other Federal Matters~~

In July 2014, the Utility was informed that the U.S. Attorney’s Office is investigating a natural gas explosion that occurred in Carmel, California on March 3, 2014. The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the criminal trial discussed above. 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 Utilityincluding as a result of these ~~investigations.~~

~~Other 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, and destroyed 549 homes, 368 outbuildings and four commercial properties. Cal Fire’s report concludedinvestigations or any proceedings 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 its vegetation management contractors to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree. In a press release also issued on April 28, 2016, Cal Fire indicated that it will seek to recover firefighting costs in excess of $90 million from the Utility.

On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its 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 September 30, 2016, approximately 50 complaints have been filed against the Utility and its vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador involving approximately 1,850 individual plaintiffs representing approximately 800 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 preference cases (presented by individuals who due to their age and/or physical condition are not likely to meaningfully participate in a trial under normal scheduling). The Utility also has begun scheduling mediation of other cases. Case management conferences were held on July 14, 2016 and September 1, 2016. The next case management conference is scheduled for December 1, 2016.

~~In connection with this matter, the Utility may~~could 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 it was not negligent; however, there can be no assurance that a court or jury would agree with the Utility.

Based on the evidence described in the Cal Fire report that the Gray Pine tree contacted an electric line of the Utility, the Utility believes that it is probable that it will incur a loss of $350 million for property damages (including estimated damages to structures and their contents, and to trees)commenced in connection with this matter, which corresponds to the lower end of the range of its reasonably estimable losses. This amount is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the extent of damage to such structures and contents, and other property damage. The estimate does not include fire suppression costs, personal injury damages and other damages that the Utility could be liable for if it were found to have been negligent.incident.

The Utility believes that it is reasonably possible that it will incur losses related to Butte fire claims in excess of the $350 million accrued through September 30, 2016. The Utility believes that $90 million is a reasonable estimate of fire suppression costs (this amount is not included in the $350 million accrued through September 30, 2016). The Utility currently is unable to reasonably estimate the upper end of the range because it is still at 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, including for estimated property damages, requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including 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 change, including management’s ability to reasonably estimate a range of loss.

The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Butte fire. 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. In the second quarter of 2016, the Utility recorded $260 million for probable insurance recoveries in connection with recovery of losses related to the Butte fire, included in Other accounts receivable in the Condensed Consolidated Balance Sheets. The Utility plans to seek recovery of all insured losses, and while the Utility believes that a significant portion of costs incurred for third-party claims (and associated legal expenses) relating to Butte fire will ultimately be recovered through its insurance, it is unable to predict the amount and timing of such insurance recoveries.

~~Other Contingencies~~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 ~~$84~~$39 million at September 30, ~~2016~~2017, and ~~$63~~$45 million at December 31, ~~2015.~~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

In May 2017, the Utility filed a settlement agreement with the CPUC related to the recovery of license renewal costs and cancelled project costs within its pending application to retire Diablo Canyon Power Plant. The settlement agreement allows for recovery from customers of $18.6 million of the total license renewal project cost of $53 million evenly over an 8-year period beginning January 1, 2018. Related to cancelled project costs, the settlement allows for recovery from customers of 100% of the direct costs incurred prior to June 30, 2016 and 25% recovery of direct costs incurred after June 30, 2016. During the nine months ended September 30, 2017, the Utility incurred charges of $47 million related to settlement agreement, of which $24 million is for cancelled projects and $23 million is for disallowed license renewal costs.

In addition, 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. ~~Disallowances as a result~~For more information, see Note 13 “Contingencies and Commitments” of the ~~CPUC’s June 23, 2016 final phase one decision~~Notes to the Consolidated Financial Statements in the ~~Utility’s 2015 GT&S rate case, the April 9, 2015 Penalty Decision and the Utility’s Pipeline Safety Enhancement Plan are discussed below.~~2016 Form 10-K.

~~2015 GT&S Rate Case Disallowance of Capital Expenditures~~

On June 23, 2016, the CPUC approved a final decision in phase one of the Utility’s 2015 GT&S rate case. The decision permanently disallowed a portion of the 2011 through 2014 capital spending in excess of the amount adopted and established various cost caps that will increase the risk of overspend over the current rate case cycle, including new one-way capital balancing accounts. As a result, in the second quarter of 2016, the Utility incurred charges of $190 million for capital expenditures that the Utility believes are probable of disallowance based on the decision. This included $134 million to the net plant balance for 2011 through 2014 capital expenditures in excess of adopted amounts and $56 million for the Utility’s estimate of 2015 through 2018 capital expenditures that are probable of exceeding authorized amounts. Additional charges may be required in the future based on the Utility’s ability to manage its capital spending and on the outcome of the third party audit of 2011 through 2014 capital spending.

~~Penalty Decision’s Disallowance of Natural Gas Capital Expenditures~~

On April 9, 2015, the CPUC issued a decision in its investigative enforcement proceedings pending against the Utility to impose total penalties of $1.6 billion on the Utility after determining that the Utility had committed numerous violations of laws and regulations related to its natural gas transmission operations (the “Penalty Decision”). In January 2016, the CPUC closed the investigative proceedings. The total penalty includes (1) a $300 million fine, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million.

On November 1, 2016, the assigned ALJ issued a phase two proposed decision in the Utility’s 2015 GT&S rate case, which applies $689 million of the $850 million penalty to capital expenditures. The decision also approves the Utility’s list of programs and projects that meet the CPUC’s definition of “safety related,” the costs of which are to be funded through the $850 million penalty. The Utility expects a final CPUC decision to be voted in December 2016.

For the three and nine months ended September 30, 2016, the Utility recorded charges for disallowed capital spending of $51 million and $286 million, respectively, as a result of the Penalty Decision. The cumulative charges at September 30, 2016, and the additional future charges to reach the $1.6 billion total are shown in the following table:

Nine Months

Cumulative

Future

Ended

Charges

Charges

September 30,

September 30,

and

Total
(in millions)
2016

2016

Costs

Amount
Fine paid to the state
$
-

$
300

$
-

$
300
Customer bill credit paid

-

400

-

400
Charge for disallowed capital (1)

286

692

-

692
Disallowed revenue for pipeline safety

expenses (2)

8

8

150

158
CPUC estimated cost of other remedies (3)

-

-

-

50
Total Penalty Decision fines and remedies
$
294

$
1,400

$
150

$
1,600

~~(1)~~The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related projects and programs that the CPUC will finalize in a final phase two decision to be issued in the Utility’s 2015 GT&S rate case. The CPUC recommended in its May 5, 2016 phase one proposed decision in the Utility’s 2015 GT&S rate case that at least $692 million of the $850 million cost disallowance be allocated to capital expenditures. On November 1, 2016, the CPUC issued a phase two proposed decision in the 2015 GT&S rate case which allocates $689 million to capital expenditures.

~~(2)~~ ~~Future GT&S revenues will be reduced for these unrecovered expenses.~~

~~(3)~~In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in the Penalty Decision. This table does not reflect the Utility’s remedy-related costs already incurred nor the Utility’s estimated future remedy-related costs. These costs would be expensed as incurred.

~~Capital Expenditures Relating to Pipeline Safety Enhancement Plan~~

The CPUC has authorized the Utility to collect $766 million for recovery of PSEP capital costs. As of September 30, 2016, the Utility has spent $1.3 billion on PSEP-related capital costs, of which $665 million was expensed in previous years for costs that are expected to exceed the authorized amount. The Utility expects the remaining PSEP work to continue beyond 2016. The Utility would be required to record charges in future periods to the extent PSEP-related capital costs are higher than currently expected.

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				Balance at
	September 30,		December 31,		September 30,		December 31,
(in millions)	2016		2015		2017		2016
Topock natural gas compressor station (1)	$	300	$	300	$	310	$	299
Hinkley natural gas compressor station (1)		140		140		147		135
Former manufactured gas plant sites owned by the Utility or third parties		305		271		306		285
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites		143		164		124		131
Fossil fuel-fired generation facilities and sites		104		94		131		108
Total environmental remediation liability	$	992	$	969	$	1,018	$	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 Environmental Protection Agency under the federal Resource Conservation and Recovery Act and/or 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 records an environmental remediation liability when site assessments indicate remediation is probable and the Utility can reasonably estimate the loss or a range of possible losses. Key factors in estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. The Utility’s environmental remediation liability at September 30, ~~2016~~2017 reflects its best estimate of probable future costs associated with its ~~final~~ remediation ~~plan.~~plans. Future costs will depend on many factors, including the extent of work necessary 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 the Utility’s future financial condition and cash flows.

At September 30, ~~2016,~~2017, the Utility expected to recover ~~$704~~$698 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. Some of the Utility’s environmental remediation ~~liability,~~costs, such as the ~~environmental~~ remediation costs associated with the Hinkley natural gas compressor site, ~~discussed below, will~~fossil fuel-fired generation sites, and certain facilities formerly owned by the Utility, are not ~~be recovered~~recoverable through rates.

For more information, see Note 13 of the Notes to the Consolidated Financial Statements in ~~rates.~~Item 8 of the 2016 Form 10-K.

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.” ~~Another station is located near Needles, California and is referred to below as the “Topock site.”~~ The Utility is also is 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 by the end of 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 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 California Regional ~~Board. On~~Water Quality Control Board, Lahontan Region. In November 4, 2015, the California Regional Water Quality Control Board, Lahontan Region 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.

~~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 is conducting an additional environmental review of the proposed design, and the Utility anticipates that the DTSC’s draft environmental impact report will be issued for public comment in early 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.

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 toby as much as ~~$2.0~~$1.0 billion (including amounts related to the ~~Hinkley~~Topock and ~~Topock~~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

~~In addition to the nuclear insurance the~~The Utility maintains multiple insurance policies through NEIL and the ~~NEIL, the Utility also is a member of the EMANI, which provides excess insurance coverage~~European Mutual Association for ~~property damages and business interruption losses incurred by the Utility if a~~Nuclear Insurance, covering nuclear or non- nuclear ~~event were to occur~~events at the Utility’s two nuclear generating units at Diablo ~~Canyon.~~

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, the current~~ maximum aggregate annual retrospective premium obligation of approximately $58 million. The European Mutual Association for ~~the Utility is approximately $60 million. EMANI~~Nuclear Insurance 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 $2.1 million.~~ For more information about the Utility’s ~~NEIL~~nuclear insurance coverage, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the ~~2015~~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.

On September 2, 2016, the Utility’s settlement became effective resolving, among other matters, the Utility’s claim against the CAISO for $165 million, which includes receivables and interest. Additionally, the Utility agreed to release $66 million of cash from escrow to the California Power Exchange. The settlement resulted in a $231 million reduction to the Disputed claims and customer refunds balance onthe Condensed Consolidated Balance Sheets. The settlement agreement did not result in a refund to customers or an impact to net income.

At ~~September 30, 2016 and~~ December 31, ~~2015, respectively,~~2016, the Consolidated Balance Sheets reflected ~~$233 million and $454~~$236 million in net claims within Disputed claims and customer ~~refunds as well as $161 million and $228 million of cash in escrow within Restricted cash. On October 13, 2016,~~refunds. There were no significant changes to this balance during the nine months ended September 30, 2017. The Utility ~~received approval from the bankruptcy court to release~~is uncertain when or how the remaining ~~cash held in escrow to unrestricted cash for use by the Utility.~~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 ~~several matters, including~~ audits. As of September 30, ~~2016,~~2017, it is reasonably possible that unrecognized tax benefits will decrease by approximately $70 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

San Bruno Derivative Litigation

On July 18, 2017, the Superior Court of California, County of San Mateo (the “Court”) approved the settlement agreement reached by the parties in the San Bruno Fire Derivative Cases to resolve the consolidated shareholder derivative lawsuit and certain additional claims against certain current and former officers and directors (the “Individual Defendants”). Also, as of July 19, 2017, the three cases, 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”) were dismissed. The settlement will become effective when all procedural conditions specified in the settlement stipulation are satisfied. PG&E Corporation recorded $65 million in proceeds from insurance, net of plaintiff costs to its Condensed Consolidated Income Statement for the three and nine months ended September 30, 2017.

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.

In addition, pursuant to the settlement agreement, PG&E Corporation and the Utility will implement certain corporate governance therapeutics for five years, and 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. The Court also directed PG&E Corporation to provide at least quarterly reports to the Court and to the City of San Bruno summarizing the progress of the implementation of the corporate governance and gas operations therapeutics.

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, ~~2015,~~2016, the Utility ~~hadundiscounted~~had undiscounted future expected obligations of approximately ~~$50~~$47 billion. (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the ~~2015~~2016 Form 10-K.) ~~During~~The Utility has not entered into any new material commitments during the nine months ended September 30, 2016, the Utility entered into several renewable energy power purchase agreements that were approved by the CPUC and completed major milestones with respect to construction, resulting in additional commitments of approximately $406 million over the next 20 years.2017.

NOTE 10: SUBSEQUENT EVENTS

Investigation of Recent Northern California wildfires

The causes of these fires are being investigated by Cal Fire and the CPUC, including the possible role of the Utility’s power lines and other facilities. The Utility expects that Cal Fire will issue a report or reports stating its conclusions as to the sources of ignition of the fires and the way that they progressed. The CPUC’s SED is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in fire impacted areas. According to information made available by the CPUC, investigation topics include, but are not limited to, maintenance of facilities, vegetation management, and emergency preparedness and response. It is uncertain when the investigations will be complete and whether Cal Fire will release preliminary findings before its investigation is complete.

As of October 31, 2017, the Utility had submitted 20 electric incident reports to the CPUC involving the Utility’s facilities in and around the areas impacted by the Northern California wildfires. Electric utilities must report to the CPUC incidents that are attributable or allegedly attributable to utility-owned facilities and (1) result in fatality or personal injury rising to the level of in-patient hospitalization; or (2) are the subject of significant public attention or media coverage; or (3) involve damage to property of the Utility or others estimated to exceed $50,000. The information contained in these reports is factual and does not include a determination of the causes of the fires. The investigations into the causes of the fires are ongoing.

The Utility estimates that it will incur costs in the range of $160 million to $200 million for service restoration and repairs to the Utility’s facilities (including an estimated $60 million to $80 million in capital expenditures) in connection with these fires. While the Utility believes that such costs are recoverable through CEMA, its CEMA requests are subject to CPUC approval. The Utility’s financial condition, results of operations, liquidity, and cash flows could be materially adversely affected if the Utility were unable to recover such costs.

If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the cause of one or more fires, and the theory of inverse condemnation applies, the Utility could be liable for property damages, interest, and attorneys’ fees without having been found negligent, which liability, in the aggregate, could be substantial. Courts have imposed liability under inverse condemnation policy to actions by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefitted from such undertaking and based on the assumption that utilities have the ability to recover these costs from their customers. In addition to such claims for property damage, interest and attorneys’ fees, as well as claims under other theories of liability, the Utility could be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent, which liability, in the aggregate, could be substantial. The Utility also could be subject to material fines or penalties if the CPUC or any other law enforcement agency brought an enforcement action and determined that the Utility failed to comply with applicable laws and regulations. PG&E Corporation and the Utility are unable to reasonably estimate the amount of possible losses (or range of amounts) given the preliminary stages of the investigations and uncertainty as to the causes of the fires and the extent and magnitude of damages.

As of October 31, 2017, the Utility is aware of nine lawsuits, one of which seeks to be designated as a class action, that have been filed against PG&E Corporation and the Utility in Sonoma, Napa and San Francisco Counties' Superior Courts. The lawsuits allege, among other things, negligence, inverse condemnation, trespass, and private nuisance. They principally assert that PG&E Corporation and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the cause of the fires. The plaintiffs seek damages that include personal injury, property damage, evacuation costs, medical expenses, and other damages. PG&E Corporation and the Utility may be subject of additional lawsuits in connection with the Northern California wildfires.

The Utility has approximately $800 million in liability insurance for potential losses that may result from the Northern California wildfires. If the Utility were held liable for one or more fires and the Utility’s insurance were insufficient to cover that liability or the Utility were unable to recover costs in excess of insurance through regulatory mechanisms, either of which could take a number of years to resolve, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially adversely affected.

Following the Northern California wildfires, PG&E Corporation reinstated its liability insurance in the amount of approximately $630 million for any potential future event.

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

RESULTS OF OPERATIONS

OVERVIEW

The Utility is regulated primarily by the CPUC and the FERC. The CPUC has jurisdiction over the rates, 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 ~~alsosubject~~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 ~~also~~ be read in conjunction with the ~~2015~~2016 Form 10-K.

The causes of these fires are being investigated by Cal Fire and the CPUC, including the possible role of the Utility's power lines and other facilities. The Utility expects that Cal Fire will issue a report or reports stating its conclusions as to the sources of ignition of the fires and the way that they progressed. The CPUC’s SED is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in fire impacted areas. According to information made available by the CPUC, investigation topics include, but are not limited to, maintenance of facilities, vegetation management, and emergency preparedness and response. It is uncertain when the investigations will be complete and whether Cal Fire will release preliminary findings before its investigation is complete.

PG&E Corporation and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially adversely affected by potential losses resulting from the impact of the Northern California wildfires. See Item 1A. Risk Factors in this Form 10-Q.

Summary of Changes in Net Income and Earnings per Share

The ~~following table is~~tables below include a summary reconciliation of ~~the key changes, after-tax, in~~ PG&E Corporation’s consolidated income available for common shareholders and EPS ~~(as well as~~to earnings from operations and EPS based on an earnings from operations ~~basis)~~for three and nine months ended September 30, 2017 as compared to the same ~~period~~periods in 2016 and a summary reconciliation of the ~~prior year (see “Results~~key drivers of ~~Operations” below).~~PG&E Corporation’s earnings from operations and EPS based on earnings from operations for the three and nine months ended September 30, 2017 as compared to the same periods in 2016. “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, including certain pipeline related expenses, certain legal and regulatory related expenses, fines and penalties, Butte fire related costs, and impacts of the 2015 GT&S rate case.~~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 ~~planning,~~plans, and employee incentive compensation. PG&E Corporation believes that earnings from operations provide additional insight into the underlying trends of the business allowing for a better comparison against historical results and expectations for future performance. Earnings from operations are not a substitute or alternative for GAAP measures such as income available for common shareholders and may not be comparable to similarly titled measures used by other companies.

Three Months Ended

Nine Months Ended

September 30,

September 30,

EPS

EPS
(in millions, except per share amounts)
Earnings (1)

(Diluted)

Earnings (1)

(Diluted)
Income Available for Common Shareholders - September 30, 2015
$
307

$
0.63

$
740

$
1.53
Fines and penalties

84

0.16

497

1.03
Pipeline-related expenses

19

0.04

38

0.08
Legal and regulatory related expenses

8

0.02

26

0.05
Natural gas matters insurance recoveries

(6)

(0.01)

(29)

(0.06)
Earnings from Operations - September 30, 2015 (2)
$
412

$
0.84

$
1,272

$
2.63
Timing of 2015 GT&S revenue collection (3)

58

0.11

58

0.11
Growth in rate base earnings

25

0.05

76

0.15
Timing of taxes (4)

(22)

(0.04)

(103)

(0.20)
Nuclear refueling outage

-

-

(30)

(0.06)
Regulatory and legal matters

23

0.05

-

-
Gain on disposition of SolarCity stock (5)

-

-

(14)

(0.03)
Increase in shares outstanding

-

(0.03)

-

(0.08)
Miscellaneous

(25)

(0.04)

(50)

(0.10)
Earnings from Operations - September 30, 2016 (2)
$
471

$
0.94

$
1,209

$
2.42
Butte fire related costs (net of insurance) (6)

(9)

(0.02)

(110)

(0.22)
Fines and penalties (7)

(42)

(0.08)

(206)

(0.41)
Pipeline-related expenses (8)

(18)

(0.04)

(47)

(0.10)
Legal and regulatory related expenses (9)

(14)

(0.03)

(32)

(0.06)
GT&S capital disallowance (10)

-

-

(113)

(0.23)
Income Available for Common Shareholders - September 30, 2016
$
388

$
0.77

$
701

$
1.40

	Three Months Ended September 30,								Nine Months Ended September 30,
					Earnings per								Earnings per
					Common Share								Common Share
(in millions,	Earnings				(Diluted)				Earnings				(Diluted)
except per share amounts)	2017		2016		2017		2016		2017		2016		2017		2016
PG&E Corporation’s
Earnings on a GAAP basis	$	550	$	388	$	1.07	$	0.77	$	1,532	$	701	$	2.98		$	1.40
Items Impacting
Comparability: (1)
Pipeline related expenses (2)		12		18		0.02		0.04		45		47		0.09			0.10
Legal and regulatory
related expenses (3)		1		14		-		0.03		5		32		0.01			0.06
Fines and penalties (4)		11		42		0.02		0.08		47		206		0.09			0.41
Butte fire-related costs,
net of insurance (5)		42		9		0.08		0.02		27		110		0.05			0.22
Net benefit from derivative
litigation settlement (6)		(38)		-		(0.07)		-		(38)		-		(0.07)			-
GT&S revenue timing impact (7)		-		-		-		-		(88)		-		(0.17)			-
Diablo Canyon settlement-related
disallowance (8)		-		-		-		-		32		-		0.06			-
GT&S capital disallowance		-		-		-		-		-		113		-			0.23
PG&E Corporation’s
Earnings from Operations (9)	$	578	$	471	$	1.12	$	0.94	$	1,562	$	1,209	$	3.04		$	2.42

~~(1)~~

All amounts presented in the table above are ~~tax-adjusted~~tax adjusted at PG&E Corporation’s statutory tax rate of ~~40.75%~~40.75 percent, except ~~for fines, which are~~as indicated below.

(1) “Items impacting comparability” represent items that management does not ~~tax deductible. See footnote (7) below.~~consider part of the normal course of operations and affect comparability of financial results between periods.

(2) ~~“Earnings from operations” is not calculated in accordance with GAAP and excludes the items impacting comparability shown in footnotes (6) through (10).~~

~~(3)~~ Represents the incremental authorized revenue collected through rates beginning August 1, 2016 in accordance with the final phase one decision in the Utility’s 2015 GT&S rate case during the three and nine months ended September 30, 2016.

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

~~(5)~~ ~~Represents the gain recognized during the nine months ended September 30, 2015. No comparable gain was recognized in 2016.~~

~~(6)~~The Utility ~~accrued charges~~incurred costs of ~~$350~~$20 million (before the tax impact of ~~$143~~$8 million) ~~for the nine months ended September 30, 2016, related to estimated property damages in connection with the Butte fire, partially offset by $260~~and $76 million (before the tax impact of $106 million) recorded as probable insurance recoveries recognized during the nine months ended September 30, 2016. No additional charges or recoveries were recognized in the three months ended September 30, 2016 related to third-party claims. The Utility also incurred charges of $16 million (before the tax impact of $7 million) and $96 million (before the tax impact of $39 million) for the three and nine months ended September 30, 2016, respectively, for Utility clean-up, repair, and legal costs associated with the Butte fire.

~~(7)~~ Represents the impact of the Penalty Decision and other enforcement and litigation matters (see Note 9 of the Notes to the Condensed Consolidated Financial Statements). For the three and nine months ended September 30, 2016, the Utility incurred costs of $59 million (before the tax impact of $23 million) and $294 million (before the tax impact of $119 million), respectively, associated with estimated safety-related cost disallowances imposed by the CPUC in its April 9, 2015 decision in the gas transmission pipeline investigations. Specific projects to be disallowed will be determined in the phase two decision of the 2015 GT&S rate case. In addition, for the three and nine months ended September 30, 2016, the Utility accrued fines, which are not deductible for tax purposes, of $1 million and $26 million, respectively, in connection with the MOD POD in the CPUC’s investigation regarding natural gas distribution facilities record-keeping practices and of $3 million for the three and nine months ended September 30, 2016 as a result of the federal criminal trial. In the three and nine months ended September 30, 2016, the Utility also recorded $4 million (before the tax impact of $2 million), for probable disallowance that will be imposed for prohibited ex parte communications.

~~(8)The Utility incurred costs of~~ $31 ~~million (before the tax impact of $13 million) and $80 million (before the tax impact of $33~~ million) during the three and nine months ended September 30, ~~2016,~~2017, respectively, for pipeline related expenses incurred in connection with the multi-year effort to identify and remove encroachments from transmission pipeline ~~rights of way.~~ rights-of-way.

~~(9)~~(3) The Utility incurred costs of ~~$23~~$2 million (before the tax impact of $9$1 million) and ~~$54~~$9 million (before the tax impact of ~~$22~~$4 million) during the three and nine months ended September 30, ~~2016,~~2017, respectively, for legal and regulatory related expenses incurred in connection with various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.

(4) ~~Represents charges~~The Utility incurred costs of ~~$190~~$11 million (not tax deductible) and $71 million (before the tax impact of ~~$77~~$24 million) during the three and nine months ended September 30, 2017, respectively, for fines and penalties. This includes disallowed expenses of ~~probablecapitaldisallowancesas a result~~$32 million (before the tax impact of ~~the finalphase one 2015 GT&S rate case decision that the Utility incurred in~~$13 million) during the nine months ended September 30, ~~2016, including $134~~2017, associated with safety-related cost disallowances imposed by the CPUC in its April 9, 2015 decision (“San Bruno Penalty Decision”) in the gas transmission pipeline investigations. The Utility also recorded $15 million (before the tax impact of ~~$54~~$6 million) during the nine months ended September 30, 2017, for ~~2011 through 2014 capital expenditures~~disallowances imposed by the CPUC in ~~excess~~its final phase two decision of ~~adopted amounts~~the 2015 GT&S rate case for prohibited ex parte communications. In addition, the Utility recorded $11 million (not tax deductible) and ~~$56~~$24 million (before the tax impact of ~~$23~~$5 million) during the three and nine months ended September 30, 2017, respectively, in connection with the proposed decision and the settlement in 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 regulatory communications.

(5) The Utility incurred costs of $71 million (before the tax impact of $29 million) and $46 million (before the tax impact of $19 million), during the three and nine months ended September 30, 2017, respectively, associated with the Butte fire, net of insurance. This includes accrued charges of $350 million (before the tax impact of $143 million), during the three and nine months ended September 30, 2017, related to estimated third-party claims. The Utility also incurred charges of $18 million (before the tax impact of $7 million) and $46 million (before the tax impact of $19 million), during the three and nine months ended September 30, 2017, respectively, for legal costs. These costs were partially offset by insurance recoveries of $297 million (before the tax impact of $121 million) and $350 million (before the tax impact of $143 million) recorded during the three and nine months ended September 30, 2017, respectively.

(6) PG&E Corporation recorded proceeds from insurance, net of plaintiff payments, of $65 million (before the tax impact of $27 million) during the three and nine months ended September 30, 2017, associated with the settlement agreement in connection with the shareholder derivative litigation that was approved by the Superior Court of California, County of San Mateo on July 18, 2017. This includes $90 million (before the tax impact of $37 million) during the three and nine months ended September 30, 2017, for proceeds from insurance partially offset by $25 million (before the tax impact of $10 million) during the three and nine months ended September 30, 2017, for plaintiff legal fees paid in connection with the settlement.

(7) As a result of the CPUC’s final phase two decision in the 2015 GT&S rate case, during the nine months ended September 30, 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) As a result of the settlement agreement submitted to the CPUC in connection with the Utility’s ~~estimate~~pending joint proposal to retire the Diablo Canyon Power Plant, the Utility recorded a total disallowance of ~~2015 through 2018 capital expenditures that~~$47 million (before the tax impact of $15 million) during the nine months ended September 30, 2017, comprised of cancelled projects of $24 million (before the tax impact of $6 million) and disallowed license renewal costs of $23 million (before the tax impact of $9 million), with no corresponding charges during the same periods in 2016. A portion of the cancelled projects and disallowed license renewal costs currently is not tax deductible.

(9) “Earnings from operations” is a non-GAAP financial measure.

Reconciliation of Key Drivers of PG&E Corporation’s EPS from Operations (Non-GAAP):

	Three Months Ended September 30,				Nine Months Ended September 30,
				Earnings per				Earnings per
				Common Share				Common Share
(in millions, except per share amounts)		Earnings		(Diluted)		Earnings		(Diluted)
2016 Earnings from Operations (1)	$	471	$	0.94	$	1,209	$	2.42
Timing of taxes (2)		42		0.08		90		0.18
Timing of operational spend (3)		31		0.06		31		0.06
Growth in rate base earnings (4)		27		0.05		78		0.15
Timing of 2015 GT&S revenue impact (5)		22		0.04		172		0.33
Tax benefit on stock compensation (6)		-		-		31		0.06
Miscellaneous		41		0.07		43		0.08
Impact of 2017 GRC decision (7)		(56)		(0.10)		(92)		(0.18)
Increase in shares outstanding		-		(0.02)		-		(0.06)
2017 Earnings from Operations (1)	$	578	$	1.12	$	1,562	$	3.04

(1) See first table above for a reconciliation of EPS on a GAAP basis to EPS from Operations. All amounts presented in the table above are ~~probable~~tax adjusted at PG&E Corporation’s statutory tax rate of ~~exceeding authorized amounts. No additional charges or recoveries were recognized~~40.75 percent, except for tax benefits on stock compensation. See Footnote 6 below.

(2) Represents the timing of taxes reportable in quarterly statements in accordance with Accounting Standards Codification 740 and results from variance in percentage of quarterly earnings to annual earnings.

(3) Represents the timing of operational expense spending during the three months ended September 30, 2017 as compared to the same period in 2016. ~~(See “Regulatory Matters” below for more information.)~~

(4) Represents the impact of the increase in rate base as authorized in various rate cases, including the 2017 GRC, during the three and nine months ended September 30, 2017 as compared to the same periods in 2016.

(5) 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.

(6) Represents the incremental tax benefit related to share-based compensation awards that vested during the nine months ended September 30, 2017. Pursuant to ASU 2016-09, Compensation – Stock Compensation (Topic 718), which PG&E Corporation and the Utility adopted in 2016, excess tax benefits associated with vested awards are reflected in net income.

(7) Represents the impact of lower tax repair benefits as a result of the CPUC’s final decision in the 2017 GRC proceeding.

Key Factors Affecting Financial Results

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

The Impact of the Northern California Wildfires. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially adversely affected by potential losses resulting from the impact of the Northern California wildfires. The Utility estimates that it will incur costs in the range of $160 million to $200 million for service restoration and repairs to the Utility’s facilities (including an estimated $60 million to $80 million in capital expenditures) in connection with these fires. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially adversely affected if the Utility were unable to recover such costs through CEMA. If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the cause of one or more fires, and the theory of inverse condemnation applies, the Utility could be liable for property damages, interest, and attorneys’ fees without having been found negligent, which liability, in the aggregate, could be substantial. In addition to such claims, as well as claims under other theories of liability, the Utility could be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent, which liability, in the aggregate, could be substantial. The Utility also could be subject to material fines or penalties if the CPUC or any other law enforcement agency brought an enforcement action and determined that the Utility failed to comply with applicable laws and regulations. If the Utility were to determine that it is both probable that a material loss has occurred and the amount of loss can be reasonably estimated, a liability would be recorded consistent with the principles discussed in Note 9 to Notes to the Condensed Consolidated Financial Statements. To the extent not offset by insurance recoveries determined to be similarly probable and estimable, the liability would affect the balance sheet equity of PG&E Corporation and the Utility. (See Note 10 to Notes to the Condensed Consolidated Financial Statements and Item 1A. Risk Factors in this Form 10-Q.)

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 impact of the Butte fire, the safety culture OII and ~~their outcome,~~any related fines, penalties, or other ratemaking tools that could be imposed by the CPUC, including ~~potential remedial and other measures or designation of one or more independent third-party monitor(s)~~as a result of the phase two of the proceeding, the ex parte OII and the related proposed decision, the potential recommendations that the third-party monitor (appointed in the first quarter of 2017 as a result of the Utility’s conviction in the federal criminal trial) may make related to the Utility’s conviction in the federal criminal trial, and ~~debarment proceeding,~~ potential fines associated with the alleged violations of the CPUC’s ex parte communication rules, litigation claims related to the Butte fire, and a number of investigations and/or requests for information by government agencies, includingpenalties in connection with the Utility’s ~~self-report related to its atmospheric corrosion inspections.~~safety and other self-reports. (See ~~Note 9 of~~Item 1A. Risk Factors in the ~~Notes to the Condensed Consolidated Financial Statements~~2016 Form 10-K and Item 1A. in ~~Item 1.~~this Form 10-Q.)

The Timing and Outcome of Ratemaking Proceedings. ~~There are several~~The Utility’s future results may be impacted by the timing and outcome of its FERC TO18 and TO19 rate cases that are currently pending at the CPUC and the FERC.The CPUC approved 2015 GT&S “interim” revenue requirements in its final phase one decision dated June 23, 2016. The authorized revenue requirements are effective retroactive to January 1, 2015. However, the Utility will not be able to record the full revenue requirement increase since January 1, 2015 until after the final phase two decision is issued. On November 1, 2016, the assigned ALJ issued a phase two proposed decision in the 2015 GT&S rate case that applies $689 million of the $850 million San Bruno Penalty disallowance to capital expenditures.cases. (See “Regulatory Matters – 2015 Gas Transmission and Storage Rate Case” below for more information.) Additionally, on August 3, 2016, the Utility and other intervening parties filed a motion with the CPUC seeking approval of a settlement agreement in the Utility’s 2017 GRC. The settlement agreement proposes a revenue requirement increase of $88 million for 2017. Under the current schedule, a final CPUC decision is expected in February 2017. (See “Regulatory Matters − 2017 General Rate Case” below for more information.) In addition, on July 29, 2016, the Utility filed a rate case at the FERC requesting a 2017 retail electric transmission revenue requirement. The FERC accepted the Utility’s filing on September 30, 2016 and set the proceeding for settlement negotiations. (See “Regulatory Matters−FERC Transmission“Transmission Owner Rate Cases” in “Regulatory Matters” below for more information.) The outcome of regulatory proceedings can be affected by many factors, including ~~the level of opposition by~~ intervening ~~parties,~~parties’ testimonies, 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. 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 also forecasts that in 2017 it will incur unrecovered pipeline-related expenses of approximately $90 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 “Disallowance of Plant Costs” in Note 9 of the Notes to the Condensed Consolidated Financial Statements.)

The Amount and Timing of the Utility's Financing Needs. PG&E Corporation’s and the Utility’s ability to access the capital markets, to borrow under its loan financing arrangements and the terms and rates of future financings could be materially adversely affected by the outcome of or market perception of the matters discussed in Note 9 and Note 10 of the Notes to the Condensed Consolidated Financial Statements, including liabilities, if any, incurred in relation to the recent Northern California wildfires, adverse effects on their ability to comply with consolidated debt to total capitalization ratio covenants in their financing arrangements and regulatory capital structure requirements resulting therefrom, adverse changes in their respective credit ratings, general economic and market conditions, and other factors. PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure. For the nine months ended September 30, 2017, PG&E Corporation issued $361 million of common stock and made equity contributions of $405 million to the Utility. PG&E Corporation forecasts that it will need to continue to issue a material amount of equity in future years, primarily to support the Utility’s capital expenditures. PG&E Corporation may seek to issue additional equity to fund unrecoverable pipeline-related expenses and to pay claims, losses, fines and penalties that may be required by the outcome of litigation and enforcement matters. Additional issuances of equity, if any, could have a material dilutive impact on PG&E Corporation’s EPS.

Changes in the Utility Industry.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 while continuing to provide customers with safe, reliable, and affordable service. The utility industry is also undergoing a transformative change driven by technological advancements enabling customer choice (for example, customer-owned generation and energy storage) and state climate policy supporting a decarbonized economy. California’s environmental policy objectives are accelerating the pace and scope of the industry change. The electric grid is a critical enabler of the adoption of new energy technologies that support California's climate change and GHG reduction objectives, which continue to be publicly supported by California policy makers notwithstanding a recent change in the federal approach to such matters. In order to ~~maintain~~enable 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~~California clean energy economy, sustained investments are required in ~~rate case decisions.~~grid modernization, renewable integration projects, energy efficiency programs, energy storage options, EV infrastructure and State infrastructure modernization (e.g. rail and water projects). The Utility forecasts over $1 billion in grid investments through 2020, that ~~in 2016 it will incur unrecovered pipeline-related expenses ranging from $100 million to $150 million which primarily relate to costs to identify~~would include increased remote control and remove encroachments from transmission pipeline rights-of-way. Also, the June 23, 2016 final phase one 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. The ultimate amount of unrecovered costs also could be affected by how the CPUC determines in its final phase two decisionsensor technology of the ~~2015 GT&S rate case which~~grid, integration investments in connection with DER bi-directional energy flows and voltage fluctuations, advanced grid data analytics, grid storage that enables renewable integration, expanded infrastructure for light, medium, and heavy-duty EVs, transmission integration for renewables, and energy efficiency and demand response programs. In addition, these changes brought about by technological advancements and climate policy may cause a reduction in natural gas usage and increase natural gas costs. The combination of reduced natural gas load and increased costs ~~are included~~could result in ~~determining whether the $850 million shareholder-funded obligation under the Penalty Decision has been met. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)~~

~~The Amount~~higher natural gas customer bills and ~~Timing of the Utility’s Financing Needs~~. PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure. For the nine months ended September 30, 2016, PG&E Corporation issued $742 million of common stock and used $740 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 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 would 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, Financial Statements and Supplementary Data, changes in their respective credit ratings, general economic and market conditions, and other factors. potential cost recovery risk.

For more information about the factors and risks that could affect ~~future~~PG&E Corporation’s and the Utility’s financial condition, results of operations, ~~financial condition,~~liquidity, and cash flows, or that could cause future results to differ from historical results, see “Item 1A. Risk Factors”in the ~~2015~~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 ~~which~~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.

RESULTS OF OPERATIONS

PG&E Corporation

The consolidated results of operations consist primarily of ~~balances~~results related to the Utility, which are discussed in the “Utility” section below. The following table provides a summary of net income available for common shareholders for the three and nine months ended September 30, ~~2016~~2017 and ~~2015:~~2016:

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2016		2015		2016		2015		2017		2016		2017		2016
Consolidated Total	$	388	$	307	$	701	$	740	$	550	$	388	$	1,532	$	701
PG&E Corporation		2		5		5		35		40		2		51		5
Utility	$	386	$	302	$	696	$	705	$	510	$	386	$	1,481	$	696

PG&E Corporation’s net income primarily consists of income taxes and interest expense on long-term ~~debt,~~debt. The increase in PG&E Corporation’s net income ~~taxes, and other income from investments. Results~~ for the three and nine months ended September 30, ~~2015 include approximately $30 million of realized gains and associated tax benefits related~~2017, respectively, as compared to ~~an investment in SolarCity Corporation with no corresponding gains for~~ the same ~~period~~periods in ~~2016.~~2016 is primarily due to the impact of the San Bruno Derivative Litigation, partially offset by additional income tax expense and interest expense.

Utility

The tables below ~~shows~~show certain items from the Utility’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, ~~2016~~2017 and ~~2015.~~2016. The tables separately identify the revenues and costs that impacted earnings from those that did not impact earnings. In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs), and the corresponding amount of revenues collected to recover those pass-through costs, do not impact earnings. In addition, expenses that have been specifically authorized (such as the payment of pension costs) and the corresponding revenues the Utility is authorized to collect to recover such costs do not impact earnings.

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

Three Months Ended September 30, 2016

Three Months Ended September 30, 2015

Revenues/Costs:

Revenues/Costs:

(in millions)
That Impacted Earnings
That Did Not Impact Earnings
Total Utility

That Impacted Earnings
That Did Not Impact Earnings
Total Utility
Electric operating revenues
$
2,086
$
1,907
$
3,993

$
1,907
$
1,961
$
3,868
Natural gas operating revenues

621

195

816

516

166

682
Total operating revenues

2,707

2,102

4,809

2,423

2,127

4,550
Cost of electricity

-

1,613

1,613

-

1,681

1,681
Cost of natural gas

-

80

80

-

50

50
Operating and maintenance

1,373

409

1,782

1,226

396

1,622
Depreciation, amortization, and decommissioning

694

-

694

653

-

653
Total operating expenses

2,067

2,102

4,169

1,879

2,127

4,006
Operating income

640

-

640

544

-

544
Interest income (1)

8

2
Interest expense (1)

(209)

(191)
Other income, net (1)

23

22
Income before income taxes

462

377
Income tax provision (1)

73

72
Net income

389

305
Preferred stock dividend requirement (1)

3

3
Income Available for Common Stock

$
386

$
302

	Three Months Ended September 30, 2017						Three Months Ended September 30, 2016
	Revenues/Costs:						Revenues/Costs:
(in millions)	That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility
Electric operating revenues	$	2,002	$	1,645	$	3,647	$	2,086	$	1,907	$	3,993
Natural gas operating revenues		722		147		869		621		195		816
Total operating revenues		2,724		1,792		4,516		2,707		2,102		4,809
Cost of electricity		-		1,466		1,466		-		1,613		1,613
Cost of natural gas		-		78		78		-		80		80
Operating and maintenance		1,180		248		1,428		1,373		409		1,782
Depreciation, amortization, and decommissioning		710		-		710		694		-		694
Total operating expenses		1,890		1,792		3,682		2,067		2,102		4,169
Operating income		834		-		834		640		-		640
Interest income (1)						10						8
Interest expense (1)						(217)						(209)
Other income, net (1)						24						23
Income before income taxes						651						462
Income tax provision (1)						138						73
Net income						513						389
Preferred stock dividend requirement (1)						3						3
Income Available for Common Stock					$	510					$	386

(1) These items impacted earnings for the three months ended September 30, ~~2016~~2017 and ~~2015.~~2016.

	Nine Months Ended September 30, 2016						Nine Months Ended September 30, 2015						Nine Months Ended September 30, 2017						Nine Months Ended September 30, 2016
	Revenues/Costs:						Revenues/Costs:						Revenues/Costs:						Revenues/Costs:
(in millions)	That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility
Electric operating revenues	$	5,996	$	4,594	$	10,590	$	5,569	$	4,775	$	10,344	$	5,933	$	4,105	$	10,038	$	5,996	$	4,594	$	10,590
Natural gas operating revenues		1,670		693		2,363		1,547		775		2,322		2,261		738		2,999		1,670		693		2,363
Total operating revenues		7,666		5,287		12,953		7,116		5,550		12,666		8,194		4,843		13,037		7,666		5,287		12,953
Cost of electricity		-		3,719		3,719		-		3,958		3,958		-		3,436		3,436		-		3,719		3,719
Cost of natural gas		-		377		377		-		442		442		-		524		524		-		377		377
Operating and maintenance		4,439		1,191		5,630		3,878		1,150		5,028		3,594		883		4,477		4,439		1,191		5,630
Depreciation, amortization, and decommissioning		2,090		-		2,090		1,935		-		1,935		2,134		-		2,134		2,090		-		2,090
Total operating expenses		6,529		5,287		11,816		5,813		5,550		11,363		5,728		4,843		10,571		6,529		5,287		11,816
Operating income		1,137		-		1,137		1,303		-		1,303		2,466		-		2,466		1,137		-		1,137
Interest income (1)						16						6						22						16
Interest expense (1)						(614)						(567)						(655)						(614)
Other income, net (1)						68						68						52						68
Income before income taxes						607						810						1,885						607
Income tax (benefit) provision (1)						(99)						95
Income tax provision (benefit) (1)																		394						(99)
Net income						706						715						1,491						706
Preferred stock dividend requirement (1)						10						10						10						10
Income Available for Common Stock					$	696					$	705					$	1,481					$	696

(1)These items impacted earnings for the nine months ended September 30, ~~2016~~2017 and ~~2015.~~2016.

Utility Revenues and Costs that Impacted Earnings

The following discussion presents the Utility’s operating results for the three and nine months ended September 30, ~~2016~~2017 and ~~2015,~~2016, focusing on revenues and expenses that impacted earnings for these periods.

Operating Revenues

The ~~Utility has received a final phase one decision~~Utility’s electric and natural gas operating revenues that impacted earnings increased by $17 million, or 1%, and by $528 million, or 7%, in ~~its 2015 GT&S rate case. This decision~~the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016 primarily due to additional base revenues authorized by the ~~revenue requirements that the Utility began to collect through rates beginning August 1, 2016 for~~CPUC in the 2015 GT&S rate case ~~period.~~ and the 2017 GRC, and by the FERC in the TO rate case.

The final 2015 GT&S rate case decision authorized the Utility ~~will~~to collect, over a ~~36 month~~36-month period, the difference between adopted revenue requirements and amounts previously collected in rates, retroactive to January 1, ~~2015. However,~~2015, beginning August 1, 2016. Accounting rules allow the Utility ~~will not be able~~ to recognize revenues in a given year only if they will be collected from customers within 24 months of the ~~full impact~~end of ~~revenues retroactive to January 1, 2015 until the CPUC issues~~that year. As a ~~final phase two decision in this rate case. In addition, accounting rules preclude~~result, the Utility ~~from recording the full amount of the revenue requirement increase until 2017. (See “Regulatory Matters” below.)~~

~~Operating Revenues~~

~~The Utility’s electric and natural gas operating~~recognized $102 million in January 2017 related to remaining retroactive revenues that ~~impacted earnings increased by $284 million, or 12%, and by $550 million, or 8%, in the three and nine months ended September 30, 2016, compared to the same periods in 2015~~ ~~primarily due to additional base revenues authorized by the CPUC in the 2014 GRC decision and in the 2015 GT&S rate case as discussed above, and by the FERC in the TO rate case.~~ ~~(See “Regulatory Matters” below.)~~had not previously been recognized.

Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings ~~increased~~decreased by ~~$147~~$193 million, or ~~12%~~14%, in the three months ended September 30, ~~2016~~2017 compared to the same period in ~~2015 primarily due to escalation~~2016. During the three months ended September 30, 2016, the Utility recorded $241 million in disallowed charges related to ~~labor, benefits,~~the 2015 GT&S rate case and ~~service contracts, and accelerated transmission and distribution project work. In addition,~~ the San Bruno Penalty Decision with no similar charges in the same period of 2017. The Utility ~~incurred $16~~also recorded $297 million in insurance recoveries for the three months ended September 30, 2017 related to the Butte fire, with no similar recoveries for the same period in 2016. These decreases were partially offset by $352 million in higher charges related to the Butte fire ~~and $4 million in charges recorded in connection with the MOD POD related to the natural gas distribution facilities record-keeping investigation and the federal criminal trial during~~(in the three months ended September 30, 2017, the Utility recorded $368 million in charges as compared to $16 million in the same period in 2016).

The Utility’s operating and maintenance expenses that impacted earnings decreased by $845 million, or 19%, in the nine months ended September 30, 2017 compared to the same period in 2016. ~~These increases were partially offset by approximately $90~~For the nine months ended September 30, 2017, the Utility recorded $429 million fewer disallowed charges (in the nine months ended September 30, 2017, the Utility incurred a $47 million disallowance related to the Diablo Canyon settlement as compared to $476 million of ~~lower~~ disallowed capital charges related to the San Bruno Penalty Decision ~~compared to~~and 2015 GT&S rate case decision during the same period in ~~2015. (See~~2016) and $51 million in lower charges related to the Butte fire (in the nine months ended September 30, 2017, the Utility recorded $395 million in charges as compared to $446 million in the same period in 2016) (see Note 9 of the Notes to the Condensed Consolidated Financial ~~Statements.)~~

The Utility’s operating and maintenance expenses that impacted earnings increased by $561 million, or 14%, in the nine months ended September 30, 2016 compared to the same period in 2015 primarily due to escalation related to labor, benefits, and service contracts, and accelerated transmission and distribution project work. In addition, the Utility incurred $446 million in charges related to the Butte fire, $190 million in permanently disallowed capital spending (see “Regulatory Matters” below), $50 million in costs related to a scheduled nuclear refueling outage at Diablo Canyon, and $29 million in charges recorded in connection with the MOD POD related to the natural gas distribution facilities record-keeping investigation and the federal criminal trial during the nine months ended September 30, 2016. These increases were partially offset by $500 million in charges associated with the Penalty Decision for fines and customer refunds incurred in the first nine months of 2015 with no corresponding charges in 2016.Statements). Additionally, ~~the Utility recorded approximately $260 million in probable~~ insurance recoveries related to the Butte fire inincreased by approximately $90 million (in the nine months ended September 30, ~~2016~~2017, the Utility recorded $350 million in insurance recoveries as compared to ~~$49~~approximately $260 million ~~of insurance recoveries for third-party claims related to the San Bruno accident for~~in the same period in ~~2015. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements.)~~2016).

The Utility’s future financial statements will continue to be impacted by ~~additional charges associated with~~unrecoverable pipeline-related expenses. Additionally, the ~~Penalty Decision,~~Utility expects to incur approximately $100 million in 2017 related to reinstatement of a portion of its liability insurance and legal costs related to the ~~Butte fire, and unrecoverable pipeline-related expenses.~~Northern California wildfires. (See “Key Factors Affecting Financial Results” above and Note 9 of the Notes to the Condensed ~~Consolidated~~Consolidated Financial Statements.) Additionally, the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially adversely affected by potential losses resulting from the impact of the Northern California wildfires (See Item 1A. Risk Factors below and Note 10 of the Notes to the Condensed Consolidated Financial Statements) and any additional charges associated with the costs related to the Butte fire.

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning expenses increased by ~~$41~~$16 million, or 6%2%, and by ~~$155~~$44 million, or 8%2%, in the three and nine months ended September 30, ~~2016~~2017 compared to the same periods in ~~2015. These~~ ~~increases were~~2016 primarily due to ~~the impact of capital additions~~higher depreciation rates as authorized ~~by the CPUC~~ in the ~~2014~~2017 GRC ~~decision.~~and capital additions.

Interest Expense

The Utility’s interest ~~expenseincreased~~expense for the periods presented increased by ~~$18~~$8 million, or 9%4%, and by ~~$47~~$41 million, or 8%7%, in the three and nine months ended September 30, ~~2016~~2017, respectively, as compared to the same periods in ~~2015.~~2016. These increases were primarily ~~driven by~~due to higher levels of long term debt and short term borrowings in ~~2016~~2017 compared to ~~the same periods in 2015.~~2016.

Interest Income, and Other Income, Net

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

Income Tax Provision

The income tax provision increased by ~~$1 millionin~~$65 million in the three months ended September 30, ~~2016 and decreased by $194 million in the nine months ended September 30, 2016~~2017 as compared to the same ~~periods~~period in ~~2015. The following describes the changes in the Utility’s effective tax rate for the three and nine months ended September 30, 2016 as compared to the same periods in 2015:~~

2016. The effective tax rates for the three months ended September 30, 2017 and 2016 were 21% and ~~2015 were~~ 16% ~~and 19%~~, respectively. The ~~decrease~~increases in the income tax provision and the effective tax rate ~~was~~ primarily ~~due~~resulted from higher pre-tax income in 2017 as compared to ~~higherbenefits resulting from various property-related tax~~2016 and lower repairs deductions ~~recorded during~~in the three months ended September 30, ~~2016 with lower comparable amounts~~2017 compared to the same period in 2016.

The income tax provision increased by $493 million in the ~~three month period ending~~nine months ended September 30, ~~2015.~~

2017 as compared to the same period in 2016. The effective tax rates for the nine months ended September 30, 2017 and 2016 were 21% and ~~2015 were (16)% and 12%~~(16%), respectively. The ~~decrease~~increase in the income tax provision and the effective tax rate ~~was~~ primarily ~~due~~resulted from higher pre-tax income in 2017 as compared to ~~higherbenefits resulting from various property-related tax deductions recorded during~~2016 and the ~~nine months ended September 30, 2016 with lower comparable amounts in the nine month period ending September 30, 2015, as well asbenefits resulting from various tax~~impact of audit ~~results recorded~~settlements during the nine months ended September 30, 2016 with no ~~comparable amounts~~similar settlements during the same period in ~~the nine month period ending September 30, 2015.~~2017.

Utility Revenues and Costs that did not Impact Earnings

Fluctuations in revenues that did not impact earnings are primarily driven by electricity and natural gas procurement costs. See below for more information.

Cost of Electricity

~~TheUtility’s~~The Utility’s cost of electricity includes the ~~costs~~cost of power purchased from third parties (including renewable energy resources), transmission, fuel used in its own generation facilities, fuel supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.)

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2016		2015		2016		2015		2017		2016		2017		2016
Cost of purchased power	$	1,541	$	1,605	$	3,540	$	3,734	$	1,392	$	1,541	$	3,255	$	3,540
Fuel used in own generation facilities		72		76		179		224		74		72		181		179
Total cost of electricity	$	1,613	$	1,681	$	3,719	$	3,958	$	1,466	$	1,613	$	3,436	$	3,719
Average cost of purchased power per kWh (1)	$	0.123	$	0.111	$	0.110	$	0.105	$	0.151	$	0.123	$	0.126	$	0.110
Total purchased power (in millions of kWh) (2)		12,560		14,424		32,327		35,462		9,189		12,560		25,905		32,327

(1)Average cost of purchased power ~~for the three~~was impacted primarily by lower Utility electric customer demand due to their departure to CCAs or direct access providers and ~~nine months ended September 30, 2016 increased compared~~a larger percentage of higher cost renewable energy resources being allocated to the ~~same periods~~fewer remaining Utility electric customers. See further discussion in ~~2015 primarily due to a higher percentage of renewable energy resources.~~MD&A, “Regulatory Matters - Power Charge Indifference Adjustment OIR”, below.

(2) The decrease in purchased power for the three and nine months ended September 30, 2016 resulted from an increase year-to-date in generation from the Utility’s own generation facilities and lower electric customer demand. Hydroelectric generation increased during the three and nine months ended September 30, 2016 as2017 compared to the same periods in ~~2015.~~2016 was primarily due to lower Utility electric customer demand and an increase in generation from hydroelectric facilities.

The Utility’s total purchased power is driven by customer demand, the availability of the Utility’s own generation facilities (including ~~the~~ Diablo Canyon ~~nuclear generation power plant~~ and its hydroelectric plants), regulatory requirements to procure certain types of energy, and the cost-effectiveness of each source of electricity.

Cost of Natural Gas

The Utility’s cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. (See Note 7 of the Notes to the Condensed Consolidated Financial Statements.) The Utility’s cost of natural gas is impacted by the market price of natural gas, changes in the cost of ~~transportation~~storage and ~~storage,~~transportation, and changes in customer demand.

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2016		2015		2016		2015		2017		2016		2017		2016
Cost of natural gas sold	$	50	$	18	$	275	$	335	$	50	$	50	$	436	$	275
Transportation cost of natural gas sold		30		32		102		107		28		30		88		102
Total cost of natural gas	$	80	$	50	$	377	$	442	$	78	$	80	$	524	$	377
Average cost per Mcf (1) of natural gas sold ~~(2)~~	$	1.79	$	0.69	$	1.88	$	2.46	$	1.85	$	1.79	$	2.71	$	1.88
Total natural gas sold (in millions of Mcf) ~~(1)~~(2)		28		26		146		136		27		28		161		146

(1) One thousand cubic feet

(1) One thousand cubic feet

(2) ~~Average cost of~~The increase in natural gas sold ~~was primarily impacted by fluctuations in~~for the ~~market price of natural gas in the three and~~ nine months ended September 30, ~~2016~~2017, compared to the same ~~periods~~period in ~~2015.~~2016, was primarily due to cooler temperatures and resulted in additional customer heating demand.

Operating and Maintenance Expenses

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

LIQUIDITY AND FINANCIAL RESOURCES

Overview

The Utility’s ability to fund operations, finance capital expenditures, and make distributions to PG&E Corporation depends on the levels of its operating cash flows and access to the capital and credit markets. The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of capital. The Utility generally utilizes equity contributions from PG&E Corporation and long-term senior unsecured debt issuances to maintain its CPUC-authorized capital structure consisting of 52% equity and 48% debt and preferred stock. The Utility relies on short-term debt, including commercial paper, to fund temporary financing needs.

PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, fund equity contributions to the Utility, and declare and pay dividends primarily depends on the level of cash distributions received from the ~~Utility’s~~Utility and PG&E Corporation’s access to the capital and credit markets. PG&E Corporation has material stand-alone cash flows related to the issuance of equity and long-term debt, dividend payments, and issuances and repayments under its revolving credit facility and commercial paper program. PG&E Corporation relies on short-term debt, including commercial paper, to fund temporary financing needs.

PG&E Corporation’s equity contributions to the Utility are funded primarily through common stock issuances. PG&E Corporation forecasts that it will ~~issue approximately $800~~have issued between $400 million and $500 million in common stock ~~during 2016 and between $400 million and $600 million during~~by the end of 2017, primarily to fund equity contributions to the Utility. The Utility’s equity needs will continue to be affected by the timing and outcome of ~~the final phase two decision in the 2015 GT&S rate case, by~~ unrecoverable pipeline-related expenses, and by fines, penalties and claims that may be imposed in connection with the matters described in “Enforcement and Litigation Matters” below. ~~Common stock issuances by PG&E Corporation to fund these needs would have a material dilutive impact on~~In addition, PG&E Corporation’s ~~EPS.~~and the Utility’s equity needs could be materially increased and its liquidity and cash flows materially adversely affected by potential costs and other liabilities in connection with the Northern California wildfires. PG&E Corporation’s and the Utility’s ability to access the capital markets in a manner consistent with its past practices, if at all, could be adversely affected by such matters. (See Item 1A. Risk Factors in this Form 10-Q.)

Cash and Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to cash and cash equivalents, the Utility holds restricted cash that primarily consists of cash held in escrow pending the resolution of the remaining disputed claims that were filed in the Utility’s reorganization proceedings under Chapter 11 of the U.S. Bankruptcy Code. As part of the settlement approved in the third quarter of 2016, the Utility agreed to release $66 million of cash from escrow to the California Power Exchange. Additionally, on October 13, 2016, the Utility received approval from the bankruptcy court to release the remaining $161 million of cash held in escrow to unrestricted cash for use by the Utility. (See “Resolution of Remaining Chapter 11 Disputed Claims” in Note 9 of the Notes to the Condensed Consolidated Financial Statements.)

Financial Resources

Debt and Equity Financings

In February 2017, PG&E Corporation amended its February 2015 EDA providing for the sale of PG&E Corporation common stock having an aggregate gross price of up to $275 million. During the ~~three and~~ nine months ended September 30, ~~2016,~~2017, PG&E Corporation sold 0.4 ~~million and 2.6~~ million shares of its common stock under the February ~~2015 equity distribution agreement~~2017 EDA for cash proceeds of ~~$26~~$28.4 million, ~~and $149 million, respectively,~~ net of commissions paid of $0.2 ~~million and $1.3 million, respectively.~~million. There were no issuances under the February 2017 EDA for the three months ended September 30, 2017. As of September 30, ~~2016,~~2017, the remaining gross sales available under this agreement were ~~$275 million.~~

~~In August 2016, PG&E Corporation sold 4.9 million shares of its common stock in an underwritten public offering for net cash proceeds of $309~~$246.3 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 nine months ended September 30, ~~2016, 5.7million~~2017, 6.4 million shares were issued for cash proceeds of ~~$269~~$316 million under these plans.

The proceeds from these sales were used for general corporate purposes, including the contribution of equity to the Utility. For the nine months ended September 30, ~~2016,~~2017, PG&E Corporation made equity contributions to the Utility of ~~$740~~$405 million.

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. In March ~~2016,~~2017, the Utility issued ~~$600~~$400 million principal amount of ~~2.95%~~3.30% Senior Notes due March 15, 2027 and $200 million principal amount of 4.00% Senior Notes due December 1, ~~2026.~~2046. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.

Pollution Control Bonds

In ~~addition, in March 2016,~~June 2017, the Utility ~~entered into a $250~~repurchased and retired $345 million ~~floating rate unsecured term loan that~~principal amount of pollution control bonds Series 2004 A through D. Additionally, in June 2017, the Utility remarketed three series of pollution control bonds, previously held in treasury, totaling $145 million in principal amount. Series 2008 F and 2010 E bear interest at 1.75% per annum and mature on November 1, 2026. Series 2008 G bears interest at 1.05% per annum and matures on ~~February 2, 2017. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.~~December 1, 2018.

Revolving Credit Facilities and Commercial Paper ~~Program~~Programs

In ~~June 2016,~~May 2017, PG&E Corporation and the Utility each extended the termination dates of their existing revolving credit facilities by one year from April 27, ~~2020~~2021 to April 27, ~~2021.~~2022. At September 30, ~~2016,~~2017, PG&E Corporation and the Utility had ~~$135~~$300 million and ~~$2.2~~$2.6 billion available under their respective $300 million and $3.0 billion revolving credit facilities. (See Note 4 of the Notes to the Condensed Consolidated Financial Statements.)

PG&E Corporation and the Utility ~~can~~are permitted under the terms of its facilities to issue commercial paper up to the maximum amounts of $300 million and ~~$1.75~~$2.5 billion, respectively. For the nine months ended September 30, ~~2016,~~2017, PG&E Corporation and the Utility had an average outstanding commercial paper balance of ~~$76~~$70 million and ~~$869~~$552 million, and a maximum outstanding balance of ~~$176~~$161 million and ~~$1.4~~$1.1 billion, respectively. At September 30, ~~2016, PG&E Corporation and~~2017, the Utility had an outstanding commercial paper balance of ~~$165~~$369 million and ~~$731 million, respectively.~~PG&E Corporation did not have any commercial paper outstanding.

The revolving credit facilities require that PG&E Corporation and the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% as of the end of each fiscal quarter. At September 30, ~~2016,~~2017, PG&E Corporation’s and the Utility’s total consolidated debt to total consolidated capitalization was ~~51%~~49% and ~~49%~~48%, respectively. PG&E Corporation’s revolving credit facility agreement also requires that PG&E Corporation own, directly or indirectly, at least 80% of the common stock and at least 70% of the voting capital stock of the Utility. In addition, the revolving credit facilities include usual and customary provisions regarding events of default and covenants including covenants limiting liens to those permitted under PG&E Corporation’s and the Utility’s senior note indentures, mergers, and imposing conditions on the sale of all or substantially all of PG&E Corporation’s and the Utility’s assets and other fundamental changes. At September 30, ~~2016,~~2017, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

Dividends

In May ~~2016,~~2017, the Board of Directors of PG&E Corporation ~~and the Utility each adopted~~approved a new ~~target~~annual common stock cash dividend ~~payout ratio range~~ of ~~55% to 65%~~$2.12 per share ($0.53 per share quarterly), an increase from the previous annual cash dividend of ~~earnings, with a target to reach a payout ratio of approximately 60% by 2019. Each~~$1.96 per share ($0.49 per share quarterly), and the Board of Directors ~~retains authority to change~~of the ~~respective~~Utility approved a new annual common stock cash dividend ~~policy and~~of $1.08 billion ($270 million quarterly), an increase from the previous annual cash dividend ~~payout ratio at any time, especially if unexpected events occur that would change its view as to the prudent level~~ of ~~cash conservation. No dividend is payable unless and until declared by the applicable Board of Directors.~~$976 million ($244 million quarterly).

In September ~~2016,~~2017, the Board of Directors of PG&E Corporation declared quarterly dividends of ~~$0.49~~$0.53 per share, totaling ~~$248~~$272 million, of which approximately ~~$243~~$267 million was paid on October 15, ~~2016,~~2017, to shareholders of record on September ~~30, 2016.~~29, 2017.

InAdditionally, in September ~~2016,~~2017, the Board of Directors of the Utility declared a common stock dividend of ~~$244~~$270 million that was paid to PG&E Corporation on ~~October 3, 2016.~~

In September ~~2016, the Board of Directors of the Utility~~21, 2017 and declared dividends on its outstanding series of preferred stock, payable on November 15, ~~2016,~~2017, to shareholders of record on October 31, ~~2016.~~2017.

Utility Cash Flows

The Utility’s cash flows were as follows:

	Nine Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2016		2015		2017		2016
Net cash provided by operating activities	$	3,206	$	2,932	$	4,692	$	3,241
Net cash used in investing activities		(4,083)		(3,734)		(3,950)		(4,083)
Net cash provided by financing activities		886		809
Net cash provided by (used in) financing activities						(743)		851
Net change in cash and cash equivalents	$	9	$	7	$	(1)	$	9

Operating Activities

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash. These items fluctuate within the normal course of business due to the timing and amount of customer billings and collections and vendor billings and payments.

During the nine months ended September 30, ~~2016,~~2017, net cash provided by operating activities increased by ~~$274 million~~$1.5 billion compared to the same period in ~~2015.~~2016. This increase was primarily due to ~~tax refunds~~additional electric and natural gas operating revenues collected as authorized by the CPUC in the 2015 GT&S rate case and by the FERC in the TO rate case and the $400 million refund to natural gas customers in the second quarter of ~~$151 million received during~~ 2016, ~~compared to~~as required by the San Bruno Penalty Decision, with no ~~tax refunds received or tax payments made during 2015.~~corresponding activity in 2017. The remaining increase was primarily due to fluctuations in activities within the normal course of business such as the timing and amount of customer billings and collections and vendor billings and payments.

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

•	the timing and amounts of costs that may be incurred in connection with potential remedial and other measures that may be imposed on the Utility as a result of the jury’s verdict in the federal criminal trial and in connection with the DOI debarment proceeding, and fines or penalties that may be imposed in connection with the remaining investigations and other enforcement and litigation matters and the timing and amount of related insurance recoveries (see Note 9 of the Notes to the Condensed Consolidated Financial Statements);
the timing and amount of costs in connection with the Northern California wildfires, including costs in connection with restoration of service to customers and repairs of the Utility’s facilities, as well as potential liabilities in connection with third-party claims and fines or penalties that could be imposed on the Utility if the CPUC or any other law enforcement agency brought an enforcement action and determined that the Utility failed to comply with applicable laws and regulations; the timing and amounts of costs, including fines and penalties, that may be incurred in connection with the current and future enforcement, litigation, and regulatory matters, including the impact of the Butte fire and the timing and amount of related insurance recoveries, the safety culture OII, including other ratemaking tools that could be imposed by the CPUC as a result of the phase two of the proceeding, the ex parte OII and the related proposed decision, costs associated with potential recommendations that the third-party monitor may make related to the Utility’s conviction in the federal criminal trial, and potential penalties in connection with the Utility’s safety and other self-reports; the timing and outcomes of the TO18 and TO19 rate cases and other ratemaking and regulatory proceedings; the timing and amount of costs the Utility incurs, but does not recover, associated with its electric and natural gas systems, including amounts related to cancelled projects and relicensing; the timing and amount of tax payments (including the bonus depreciation), tax refunds, net collateral payments, and interest payments, as well as changes in tax regulations that could be adopted by Congress as a result of the new federal administration and other proposals; and the timing of the resolution of the Chapter 11 disputed claims and the amount of principal and interest on these claims that the Utility will be required to pay.
•	~~the timing and outcome of ratemaking proceedings, including of a final phase two decision in the 2015 GT&S rate case, the 2017 GRC, and the TO rate cases;~~

•	~~the timing and amount of costs the Utility incurs, but does not recover, associated with its natural gas system;~~

•	~~the timing and amount of tax payments (including the bonus depreciation), tax refunds, net collateral payments, and interest payments; and~~

•	~~the timing of the resolution of the Chapter 11 disputed claims and the amount of principal and interest on these claims that the Utility will be required to pay.~~

Investing Activities

~~Net cash used in investing activities increased by $349 million during~~During the nine months ended September 30, ~~2016 as~~2017, net cash used in investing activities decreased by $133 million compared to the same period in ~~2015.~~2016. The Utility’s investing activities primarily consist of construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility estimates that it will incur ~~approximately$5.7~~approximately $5.7 billion in capital expenditures in ~~2016 and approximately $6.0~~2017, $6.3 billion in ~~each of the years 2017,~~ 2018 and $6.0 billion 2019.

Financing Activities

~~During~~Net cash provided by financing activities decreased by $1.6 billion from $851 million for the nine months ended September 30, 2016 to $743 million of net cash ~~provided by~~used in financing activities ~~increased by $77 million compared to~~for the ~~same period in 2015.~~nine months ended September 30, 2017. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date of existing debt instruments. The Utility generally utilizes long-term debt issuances and equity contributions from PG&E Corporation to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.

ENFORCEMENT AND LITIGATION MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in Note 9 and subsequent events described in Note 10 of the Notes to the Condensed Consolidated Financial Statements. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s future financial results. In addition, PG&E Corporation and the Utility are involved in other enforcement and litigation matters described in the ~~2015~~2016 Form 10-K and “Part II. Other Information, Item 1. Legal Proceedings.” ~~Significant regulatory developments that have occurred since the 2015 Form 10-K was filed with the SEC are discussed below.~~

Department of Interior Inquiry

In September 2015, the Utility was notified that the DOI had initiated an inquiry into whether the Utility should be suspended or debarred from entering into federal procurement and non-procurement contracts and programs citing the San Bruno explosion and indicating, as the basis for the inquiry, alleged poor record-keeping, poor identification and evaluation of threats to gas lines and obstruction of the ~~NTSB’s~~National Transportation Safety Board’s investigation. The Utility filed its initial response on November 2, 2015, to demonstrate that it is a “presently responsible” contractor under federal procurement regulations and that it believes suspension or debarment is not appropriate.

On ~~April 8,~~December 21, 2016, the Utility ~~received~~and the DOI entered into an interim administrative agreement that reflects the DOI’s determination that the Utility remains eligible to contract with federal government agencies while the DOI determines whether any further action is necessary to protect the federal government’s business interests. On May 8, 2017, DOI sent a series of follow-up questions ~~from the DOI regarding its November 2015 submission. The Utility continues~~ to ~~fully cooperate with the DOI and is addressing its questions.~~

~~As a result of the August 9, 2016 jury’s verdict in the federal criminal trial,~~ the Utility ~~updated its registration on~~seeking clarification regarding gas operational matters, the federal government’s System for Award Management (SAM), a federal procurement database, to reflect the verdict. (The federal criminal trial is discussed in Note 9 of the Notes to the Condensed Consolidated Financial Statements and in Item 1 Legal Proceedings.) The Utility does not believe that the updated registration will affect its existing contracts with the federal government, but it does affect execution of new contracts with the federal government. Under federal law, the government may not enter into a contract with any corporation that was convicted of a felony criminal violation under any federal law within the preceding 24 months, where the awarding agency is aware of the conviction, unless an agency has considered suspension or debarment of the corporation and made a determination that this action is not necessary to protect the interests of the government.

~~Following the update of the SAM, the Utility~~Utility’s risk assessment process, and the DOI have been in discussions regarding such a determination and a possible interim administrative agreement that would allow the federal government agencies to contract with the Utility while the DOI is completing its debarment inquiry. It is uncertain when and if the Utility and the DOI will enter into an interim administrative agreement. It is also uncertain when or if further action will be taken by the DOI. The DOI debarment inquiry could result in the Utility’s ~~suspension or debarment from future federal government contracts for a fixed, specified time period or entering into an administrative agreement with the DOI to resolve debarment matters.~~

As a result of the DOI inquiry and/or of the August 9, 2016 jury’s guilty verdict on six felony counts in the federal criminal trial, the Utility may be required to implement remedial and other measures, such as a requirement that the Utility’s natural gas operations and/or compliance and ethics ~~programs be supervised by one or more independent third party monitor(s). If appointed, the~~framework. The Utility ~~expects a monitor or monitors would serve for a period of time and report periodically~~responded to the ~~court or a department or agency of~~questions on August 18, 2017. DOI also has indicated that before making any final determination in its debarment inquiry it will meet in person with Utility executives to discuss the ~~government.~~Utility’s compliance and ethics programs. That meeting has not yet been scheduled. The Utility could incur material costs, not recoverable through rates, to implement any remedial and other measures that could be imposed, the amount of which the Utility is currently unable to estimate.

~~Litigation Related to the San Bruno Accident and Natural Gas Spending~~

~~As of September 30, 2016, there were seven purported derivative lawsuits seeking recovery on behalf of~~For more information, see PG&E ~~Corporation~~Corporation’s and the ~~Utility for alleged breaches of fiduciary duty by officers and directors, among other claims.~~

~~Four of the complaints were consolidated as the~~ ~~San Bruno Fire Derivative Cases~~ ~~and are pending in the Superior Court of California, County of San Mateo. The remaining three cases are~~ ~~Tellardin v. PG&E Corp. et al., Iron Workers Mid-South Pension Fund v. Johns, et al.,~~ ~~and~~ ~~Bushkin v. Rambo et al~~.

~~On December 8, 2015, the California Court of Appeal issued a writ of mandate to the Superior Court of California, San Mateo County, ordering the court to stay all proceedings in the four consolidated~~ ~~San Bruno Fire Derivative Cases~~ ~~pending conclusion of the federal criminal proceedings against the Utility. On September 16,~~Utility’s 2016 ~~the San Mateo Superior Court requested that all counsel appear for a status conference in the consolidated matter. The date of the conference has been set for November 16, 2016.~~Form 10-K.

~~Bushkin v. Rambo et al., pending in the United States District Court for the Northern District of California, has been designated by the plaintiff as related to the pending shareholder derivative suit~~ ~~Iron Workers Mid-South Pension Fund v. Johns, et al., discussed below. The plaintiff in the~~ ~~Bushkin~~ lawsuit has agreed that this case should be stayed pending conclusion of the federal criminal trial against the Utility and, on May 3, 2016, the judge entered a stipulated order staying the case. The order also provides that the parties should meet and confer within 30 days after the criminal trial concludes and provide the court a status update. Despite the stay of his complaint, on June 20, 2016 the ~~Bushkin~~ plaintiff filed a petition in the Superior Court of California, San Francisco County, seeking to enforce the plaintiff’s claimed right as a shareholder to inspect certain PG&E Corporation accounting books and records pursuant to section 1601 of the California Corporations Code. On July 25, 2016, PG&E Corporation filed a motion to stay plaintiff’s petition until the appellate stay of the San Bruno Fire Derivative Cases has been lifted, or, in the alternative, a demurrer asking the Court to dismiss plaintiff’s petition. On August 29, 2016, the San Francisco Superior Court granted PG&E Corporation’s motion, and indicated that plaintiff’s petition was stayed pending resolution of the criminal matter against the Utility.

~~The~~ ~~Iron Workers~~ ~~action pending in the United States District Court for the Northern District of California has been stayed pending the resolution of the~~ ~~San Bruno Fire Derivative Cases~~. On May 5, 2016, the court ordered the parties to meet and confer within 30 days after the criminal trial concludes and provide the court a status update. At the court’s request, on August 22, 2016, the parties filed a statement requesting that the case continue to be stayed until resolution of the ~~San Bruno Fire Derivative Cases~~. On August 31, 2016, the court set a case management conference for September 30, 2016, and requested the parties to file a joint case management conference statement by September 23, 2016. On September 30, 2016, the court decided to continue the stay pending the resolution of the criminal proceedings against the Utility and ordered the parties to submit a joint status report on or before March 15, 2017.

~~A case management conference in the action entitled~~ ~~Tellardin v. PG&E Corp. et al.,~~ also pending in the Superior Court of California, San Mateo County, had been scheduled for August 9, 2016. On July 19, 2016, plaintiff requested that the court vacate the August 9, 2016 conference because, pursuant to the parties’ agreement, defendants are not required to respond to the complaint in this action until 30 days after an order lifting the stay in the ~~San Bruno Fire Derivative Cases. On August 2, 2016, the court vacated the August 9, 2016 conference.~~

The federal criminal proceeding is still pending. For more information about the federal criminal proceeding, see Note 9 of the Notes to the Condensed Consolidated Financial Statements and Item 1 Legal Proceedings.

~~PG&E Corporation and the Utility are uncertain when and how the above lawsuits will be resolved.~~

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC and other federal and state regulatory agencies. Significant regulatory developments that have occurred since the ~~2015~~2016 Form 10-K was filed with the ~~SECare~~SEC are discussed below.

2017 General Rate Case

On ~~August 3, 2016, the Utility, together with ORA, TURN, and 12 other intervening parties filed a motion with~~May 11, 2017, the CPUC ~~seeking approval of~~issued a ~~settlement agreement that resolves nearly all of the issues raised by the parties~~final decision in the Utility’s 2017 ~~GRC. All parties who filed testimony in the case joined the settlement agreement,~~GRC, which was the subject of a one-day workshop overseen by the assigned commissioner and ALJ. The settlement agreement will ultimately be considered by the full commission. In the GRC proceeding, the CPUC will determinedetermined the annual amount of base revenues (or “revenue requirements”) that the Utility ~~will be~~is authorized to collect from customers from 2017 through 2019 to recover its anticipated costs for electric distribution, natural gas distribution, and electric generation operations and to provide the Utility an opportunity to earn its authorized rate of return. ~~(The Utility’s revenue requirements for~~The final decision approved, with certain modifications, the settlement agreement that the Utility, the ORA, TURN, and 12 other ~~portions~~intervening parties jointly submitted to the CPUC on August 3, 2016 (the “settlement agreement”). Modifications from the settlement agreement to the final decision included a tax memorandum account and approval of ~~its operations, such as electric transmission, natural gas transmission and storage services, and electricity and natural gas purchases, are authorized in other regulatory proceedings overseen by~~a stand-alone application with the CPUC or a filing in the ~~FERC.) In its~~CPUC’s ongoing residential rate reform proceeding to recover customer outreach and other costs incurred as a result of residential rate reform implementation. The new tax memorandum account will track any revenue differences resulting from changes in income tax expense caused by net revenue changes, mandatory or elective tax law changes, tax accounting changes, tax procedural changes, or tax policy changes during the 2017 through 2019 GRC ~~application,~~period. The account will remain open and the ~~Utility requested an overall increase~~balance in ~~electric distribution, natural gas distribution, and utility-owned electric generation revenue requirements of $319 million over currently authorized amounts (as updated through~~ the ~~Utility’s May 27, 2016 rebuttal testimony), effective January 1, 2017.~~account will be reviewed in every subsequent GRC proceeding until a CPUC decision closes the account.

~~Revenue Requirements and Attrition Year Revenues~~

The ~~settlement agreement proposes that the Utility’s 2016 authorized~~final decision approved a revenue requirement increase of ~~$7.9 billion be increased by~~ $88 million ~~effective January 1, 2017. The settlement agreement further provides~~ for ~~an increase to the authorized~~ 2017, ~~revenues~~with additional increases of $444 million in 2018 and ~~an additional increase of~~ $361 million in 2019, ~~as shown~~ in ~~the table below.~~

The settlement agreement identifies two contested issues. First, the parties were unable to agree on whether there should be a third post-test year or “attrition” year for this GRC cycle. ORA and the Utility recommend a third post-test year for this cycle that would provide for an additional increase of $361 million. TURN and certain other settling parties oppose the third post-test year. The other contested issue concerns whether the Utility should be authorized to establish a new balancing account for costs arising from the CPUC’s rulemaking on natural gas leak abatement. The Utility and certain settling parties support the balancing account. TURN and certain other settling parties do not. ORA does not oppose it. Interested parties filed comments and reply comments on the contested issues and these issues were also discussed at the one-day workshop.

The table below summarizes the differences between the amount of revenue requirement increases included in the Utility’s request, as updated in the Utility’s supplemental testimony filed on February 22, 2016 and its May 27, 2016 rebuttal testimony, and the amount proposed in the settlement agreement:

Year

Increase Requested in GRC Application
(in millions)

Increase Proposed in Settlement Agreement
(in millions)

Difference(1)
(Decrease from GRC Application)
(in millions)
2017
$
319

$
88

$
(231)
2018

467

444

(23)
2019

368

361

(7)
2020(2)

N/A

361

N/A

~~(1)~~ ~~Rounded for presentation purposes.~~

~~(2)~~ ~~Whether or not revenues should be authorized for 2020 is a contested issue.~~

~~The following table shows the difference between the Utility’s requested increases in 2017 revenue requirements by~~ line ~~of business and~~with the amounts proposed in the settlement ~~agreement:~~

Increase/(Decrease) Proposed in Settlement Agreement

Difference(1) (Decrease from GRC Application)
(in millions)

Increase Requested in GRC Application

Line of Business:

Electric distribution
$
67

1.6
%

$
(62)

(1.5)
%

$
(128)
Gas distribution

59

3.4

(3)

(0.2)

(62)
Electric generation

193

9.9

153

7.8

(40)
2017 revenue requirement increases
$
319

4.0
%

$
88

1.1
%

$
(231)

~~(1)~~ ~~Rounded for presentation purposes.~~

agreement. The following table shows the ~~differences, by~~revenue requirement amounts approved in the final decision based on line of business and cost category ~~between the amount of revenue requirements included in the GRC application and the amount proposed in the settlement agreement,~~ as well as the differences between the 2016 authorized revenue requirements and ~~(i) the GRC application and (ii)~~ the amounts approved in the final decision:


				Increase/
		Amounts		(Decrease)
(in millions)		Approved in		2016 vs.
Line of Business:		Final Decision (1)		Final Decision
Electric distribution	$	4,151	$	(62)
Gas distribution		1,738		(3)
Electric generation		2,115		153
Total revenue requirements	$	8,004	$	88

Cost Category:
(in millions)
Operations and maintenance	$	1,794	$	131
Customer services		334		15
Administrative and general		912		(99)
Less: Revenue credits		(152)		(21)
Franchise fees, taxes other than income, and other adjustments		170		132
Depreciation (including costs of asset removal), return, and
income taxes		4,946		(70)
Total revenue requirements	$	8,004	$	88

(1) Amounts approved in the final decision are the same as the amounts that were proposed in the settlement ~~agreement:~~

Increase/

Increase/

Amounts

Amounts

(Decrease)

(Decrease)

Requested in

Proposed in

2016 Amounts

2016 Amounts
(in millions) (1)
2017 GRC

Settlement

Difference

vs. 2017 GRC

vs. Settlement
Line of Business:
Application

Agreement

(Decrease)

Application

Agreement
Electric distribution
$
4,279

$
4,151

$
(128)

$
67

$
(62)
Gas distribution

1,801

1,738

(62)

59

(3)
Electric generation

2,155

2,115

(40)

193

153
Total revenue requirements
$
8,235

$
8,004

$
(231)

$
319

$
88

Cost Category:

(in millions) (1)

Operations and maintenance
$
1,825

$
1,794

$
(31)

161

131
Customer services

361

334

(27)

42

15
Administrative and general

975

912

(62)

(36)

(99)
Less: Revenue credits

(140)

(152)

(12)

(9)

(21)
Franchise fees, taxes other than

income, and other adjustments

184

170

(14)

146

132
Depreciation (including costs of asset

removal), return, and income taxes

5,030

4,946

(84)

15

(70)
Total revenue requirements
$
8,235

$
8,004

$
(231)

$
319

$
88

~~(1)~~ ~~Rounded for presentation purposes.~~agreement.

~~The settlement agreement proposes reductions in~~As required by the following areas forecast in the GRC application. For gas distribution, reductions are proposed for corrosion control, leak management, gas operations technology, and new business. For electric distribution, reductions are proposed for overhead maintenance, capacity, technology, mapping and records, reliability, substation management, new business, and undergrounding work. For electric distribution, the capital-related reductions are offset in part by increases in the replacement and installation of additional units in specific asset areas. For electric generation, the settlement agreement proposes to move costs related to Diablo Canyon seismic studies from the GRC to the Utility’s Energy Resource Recovery Account proceeding. Proposed reductions in the customer service area largely relate to the removal of certain costs from the forecast related to residential rate reform implementation. Some of these costs would be recoverable through the existing Residential Rates Reform Memorandum Account, andfinal decision, the Utility ~~could seek recovery~~has submitted a variety of compliance filings, including a filing on June 12, 2017, which provides an accounting for the January 2017 $300 million expense reduction announcement and on July 10, 2017, providing an update of the remaining costs in a future filing with the CPUC. Additionally, a number of company-wide reductions, including reductions to the Short-Term Incentive Plan and certain employee benefits, are proposed in the settlement agreement.

~~Balancing Accounts~~

The settlement agreement proposes to retain certain existing balancing accounts, including the Tax Act Memo Account that was first established following the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, and to eliminate certain memorandum and balancing accounts that are no longer necessary. In addition to the contested balancing account for natural gas leak abatement mitigation costs, the settlement agreement proposes one new tax-related memorandum account to track the impact on the revenue requirement from certain types of changes in tax laws or regulations.

~~Capital Additions and Rate Base~~

~~The settlement agreement proposes capital expenditures of $3.9 billion for 2017~~cost effectiveness study for the portions of the Utility’s business addressed in the GRC. Proposed capital expenditures are lower than the amount included in the GRC application of $4.0 billion for 2017, consistent with the provisions of the settlement agreement. While the settlement agreement proposes overall revenue requirement increases for 2018 and 2019, it does not specify capital expenditures for those years.

The settlement agreement proposes a 2017 weighted average rate base of $24.3 billion for the portions of the Utility’s business reviewed in the GRC, compared with the Utility’s request of $24.5 billion. The $200 million difference is primarily due to the lower level of capital expenditures agreed to in the settlement.

On August 30, 2016, the CPUC held a workshop to allow the assigned CPUC commissioner, the assigned ALJ, and other interested parties to pose questions to the Utility and other settling parties regarding the settlement agreement. The Utility and the parties also discussed post-test years 2018 and 2019, including imputed capital additions and rate base amounts, and the two contested issues: a third post-test year or “attrition” year for this GRC cycle (i.e. for 2020) and whether the Utility should be authorized to establish a new balancing account for costs arising from the CPUC’s rulemaking on natural gas leak abatement. The Utility estimated authorized capital expenditures of $3.6 billion for 2018 and $3.5 billion for 2019, based on a calculation method that is subject to CPUC approval, as compared to its request of approximately $4.0 billion each year.SmartMeter™ Upgrade project. The Utility is unable to predict what, if any, actions the CPUC will approve its proposed calculation method. The Utility also estimateda weighted average rate base of $25.4 billion for 2018 and $26.3 billion for 2019, compared with the Utility’s request of $25.7 billion and $26.9 billion, respectively.

Evidentiary hearings were held on September 1, 2016. Under the current schedule, a proposed decision is expected to be released in January 2017, and a final CPUC decision is expected to be issued in February 2017. On March 17, 2016, the CPUC issued a decision to allow the authorized revenue requirement changes to become effective on January 1, 2017, even if the final decision is issued after that date.

~~PG&E Corporation and the Utility are unable to predict whether the CPUC will approve the settlement agreement.~~take regarding these submissions.

For more information, see ~~Item 4 of~~PG&E Corporation’s and the ~~2015~~Utility’s 2016 Form 10-K and ~~Item 2 of the 2016 Q1 Form 10-Q and the 2016 Q2~~its subsequent quarterly reports on Form 10-Q.

2015 Gas Transmission and Storage Rate Case

~~On June 23,~~During 2016, the CPUC ~~approved a~~issued final ~~decision~~decisions in phase one and phase two of the Utility’s 2015 GT&S rate case. The phase one decision ~~adopts~~adopted the ~~“interim”~~ revenue requirements that the Utility is authorized to collect through rates beginning August 1, 2016, to recover its costs of gas transmission and storage services for the 2015 GT&S rate case period ~~(see table below)~~(2015 through 2018). The decision authorizes the Utility to collect, over a 36-month period, the difference between adopted revenue requirements and amounts previously collected in rates, retroactive to January 1, 2015. The Utility will not be able to record the full revenue requirement increase since January 1, 2015 until after the final phase two decision ~~is issued. In addition, accounting rules allow~~determined the ~~Utility to recognize revenues in a given year only if they will be collected from customers within 24 months~~allocation of the ~~end of that year. As a result,~~$850 million penalty assessed in the ~~Utility will not be able to complete recording~~San Bruno Penalty Decision and the ~~full retroactive~~ revenue requirement ~~increase~~reduction for the five-month delay caused by the Utility’s violation of the CPUC ex parte communication rules in ~~2016.~~this proceeding.

The phase one decision ~~adopts capital expenditures of roughly $700 million to $800 million per year through 2018 and authorizes weighted average~~excluded from rate base of $2.9 billion in 2015, $3.3 billion in 2016, $3.6 billion in 2017, and $4.2 billion in 2018, before the application of the shareholder-funded safety work disallowance associated with the Penalty Decision. The authorized weighted average rate base excludes $696 million of capital spending in 2011 through 2014 in excess of the amount adopted. The decision permanently ~~disallows~~disallowed $120 million of that amount and ~~orders~~ordered that the remaining $576 million be subject to ~~a third party~~an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. A draft of the audit report is expected in the first quarter of 2018. The decision also ~~establishes~~established various cost caps that will increase the risk of overspend over the current rate case cycle including new one-way ~~capital~~ balancing accounts. As a result, in the second quarter of 2016, the Utility incurred charges of $190 million for capital expenditures that the Utility believes are probable of disallowance based on the decision. This includes $134 million to the net plant balance for 2011 through 2014 capital expenditures in excess of adopted amounts and $56 million for the Utility’s estimate of 2015 through 2018 capital expenditures that are probable of exceeding authorized amounts. Additional charges may be required in the future based on the Utility’s ability to manage its capital spending and on the outcome of the ~~third party~~CPUC’s audit of 2011 through 2014 capital spending.

The phase one decision denies the Utility’s request for full balancing account treatment for recovery of authorized transportation and storage revenue requirements, and instead continues the revenue sharing mechanism authorized in the 2011 GT&S rate case that subjects a portion of the Utility’s transportation and storage revenue requirement to market risk.

The phase one decision also authorizes the Utility’s request for cost recovery of up to $157 million for the construction of Line 407, a 25.5 mile, 30-inch pipeline in the Sacramento Valley expected to be built during this rate case period. The authorized revenue requirements will begin when Line 407 becomes operational, subject to refund upon a reasonableness review in the Utility’s next GT&S rate case. The decision authorizes the Utility to track costs exceeding $157 million and seek recovery in the next GT&S rate case, subject to a reasonableness review.

~~On November 1, 2016,~~ ~~the assigned ALJ issued a phase two proposed decision (“phase two PD”)~~ regarding the $850 million penalty assessed in the Penalty Decision. In accordance with the phase one decision, the phase two PD would first reduce the recommended revenue requirement by the $850 million San Bruno penalty to determine the revenue requirement to be collected from customers, and then apply the ex parte disallowance. The phase two PD would apply $689 million of the $850 million penalty (81 percent) to capital expenditures and the remaining $161 million (19 percent) to expenses, and then reduce the 2015 revenue requirement by $72 million for the 5-month delay caused by the Utility’s violation of the CPUC ex parte communication rules in this proceeding.

~~Accordingly, the~~The final phase two PD would adopt a 2015 revenue requirement of $815 million, a 2016 revenue requirement of $1.061 billion, a 2017 revenue requirement of $1.125 billion, and a 2018 revenue requirement of $1.230 billion. These amounts reflect attrition increases of $246 million in 2016, $64 million in 2017, and $105 million in 2018. Excluding the $161 million for the expense portion of the Penalty Decision disallowance and the $72 million ex parte disallowance, the attrition increase would be $13 million in 2016.

~~The following table shows the revenue requirement amounts requested by the Utility in the 2015 GT&S rate case, the “interim” revenue requirement amounts~~decision adopted ~~in the phase one decision, and the revenue requirement amounts recommended in the phase two PD, including adjustments for the $850 million Penalty Decision disallowance and the ex parte disallowance:~~

(in millions)
2015

2016

2017

2018
Utility Requested Revenue Requirement
$
1,263

$
1,346

$
1,488

$
N/A

Phase One Decision "Interim" Revenue Requirement

1,046

1,110

1,220

1,324
San Bruno Penalty Expense Allocation

(161)

San Bruno Penalty Capital Revenue Requirement Allocation

5

(47)

(93)

(93)
Other Expense Adjustments

(3)

(2)

(2)

(1)
Adjusted Ex Parte Penalty

(72)

Phase Two PD Revenue Requirement
$
815

$
1,061

$
1,125

$
1,230

~~The phase two PD also recommends weighted average rate base reductions of $99 million in 2015, $453 million in 2016, $670 million in 2017, and $658 million in 2018, resulting in~~ total weighted average rate base of $2.8 billion in 2015, $2.8 billion in 2016, $3.0 billion in 2017, and $3.5 billion in 2018. The ~~proposed~~final phase two decision ~~would reduce~~reduced rate base by the full amount of the disallowed capital expenditures but ~~would~~did not remove the associated deferred taxes, ~~resulting in~~which the Utility believes constitutes a ~~larger rate base reduction. It~~normalization violation. In the final decision, the CPUC authorized the Utility to establish a Tax Normalization Memorandum Account to track relevant costs and clarified that it is ~~unclear whether this treatment would apply beyond this rate case period.~~

~~In addition, the phase two PD would approve the Utility’s list of programs which meet~~ the CPUC’s ~~definition~~intention that the Utility comply with normalization rules and avoid the potential adverse consequences of ~~“safety related,”~~a normalization violation. The CPUC allowed the ~~costs of which are~~Utility to ~~be funded through~~seek a ruling from the ~~$850 million penalty.~~

~~Opening briefs~~IRS and the Utility filed the ruling request with the IRS on April 10, 2017. On October 5, 2017, the ~~phase two PD are due on November 21, 2016 and reply briefs are due on November 28, 2016. The~~IRS issued a private letter ruling indicating the final phase two decision rate base reduction was inconsistent with the IRS tax normalization requirements. As a result of the IRS private letter ruling, the Utility will file an advice letter with the CPUC in the fourth quarter of 2017, requesting a rate base adjustment of $7 million, $28 million, $49 million, and $61 million, in 2015, 2016, 2017, and 2018, respectively.

In August 2016 and January 2017, TURN, ORA and Indicated Shippers filed applications for rehearing of the phase one and phase two decisions, respectively. The Utility cannot predict when or if the CPUC will grant the rehearings or if it will adopt the parties’ recommendations. Additionally, in June 2017, the Utility filed a PFM of the phase one decision to eliminate the requirement that the Utility install new CP systems in 2018 because the Utility is ~~expected~~not in a position to identify the optimal location for such new systems in 2018. Instead, the Utility requested to be ~~issued within 30 days~~allowed to continue its current CP program. As directed by the CPUC, on August 23, 2017, the Utility provided supplemental information to the CPUC regarding the PFM. The Utility is unable to predict if and when the CPUC would adopt the PFM. In the event the PFM is not adopted and the Utility fails to perform the mandated new CP systems, the Utility could incur fines and penalties, the amount of which the ~~reply briefs.~~ Utility is unable to predict.

With the addition of a third attrition year, the Utility’s next GT&S cycle will begin in 2019. The ~~decision requires the~~ Utility is required to file its ~~next~~2019 GT&S ~~application~~rate case in 2017. The Utility plans to file its 2019 GT&S rate case with the CPUC in the fourth quarter of 2017.

~~FERC~~ Transmission Owner Rate Cases

On July 29, 2015, the Utility requested a 2016 retail electric transmission revenue requirement of $1.515 billion, a $314 million increase over the currently authorized revenue requirement of $1.201 billion. The Utility’s proposed rates went into effect on March 1, 2016, subject to refund, and pending a final decision by the FERC. On September 1, 2016, the Utility and other settling parties (including the CPUC) filed a motion at the FERCTransmission Owner Rate Case for approval of a settlement proposing that the Utility’s 2016 retail electric transmission revenue requirement be set at $1.331 billion, a $130 million increase over the currently authorized revenue requirement. The settlement is subject to the FERC’s approval. The Utility also filed a motion on September 1, 2016, requesting the implementation of interim rates that, as of result of the settlement, became effective for wholesale customers on September 1, 2016 and for retail customers on October 1, 2016, subject to refund and pending a final decision by the FERC. The FERC is expected to issue a decision in late 2016 or early 2017. 2017

On July 29, 2016, the Utility filed a rate case (the “TO18 rate case”) at the FERC requesting a 2017 retail electric transmission revenue requirement of $1.718 billion, a ~~$203~~$387 million increase over the 2016 ~~requested revenue requirement of $1.515 billion (and a $387 million increase over the pending settlement~~ revenue requirement of $1.331 ~~billion).~~billion. The forecasted network transmission rate base for 2017 is $6.7 ~~billion, compared to a forecasted rate base of $5.85 billion in 2016.~~billion. The Utility is also seeking a return on equity of 10.9%, which includes an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO. In the filing, the Utility forecasted that it will make investments of $1.296 billion in 2017 in various capital projects.

On September 30, 2016, the FERC issued an order accepting the Utility’s July 2016 filing and set it for hearing, but held the hearing procedures in abeyance for settlement ~~negotiations.~~procedures. The order set an effective date for rates of March 1, 2017, and made the rates subject to ~~hearing and refund. The first~~refund following resolution of the case. On March 17, 2017, the FERC chief judge issued an order terminating the settlement ~~conference took place on October 19, 2016. The next~~procedures due to an impasse in the settlement ~~conference is scheduled for February 7 and February 8, 2017.~~

~~CPUC Cost of Capital Decision~~negotiations reported by the parties.

On ~~February 25,~~August 22, 2017, the FERC trial staff submitted testimony. The table below summarizes the differences between the amount of revenue requirement increases included in the Utility’s request and the testimony submitted by the FERC trial staff:

		Amounts			Amounts
		requested by			proposed by the
(in millions)		the Utility			FERC trial staff
Revenue Requirement	$	1,718		$	1,353
Return on Equity		10.90	%		8.46	%
Composite Depreciation Rate		3.26	%		2.08	%

Additionally, intervenors provided testimony on July 5, 2017 and the Utility submitted rebuttal testimony on October 9, 2017. Hearings are scheduled to take place starting January 9, 2018, with an initial decision expected on or before June 1, 2018.

Also, on March 31, 2017, several of the parties that had already intervened in the TO18 rate case filed a complaint at the FERC, and requested that the complaint be consolidated with the rate case. The complaint asserts that the Utility’s revenue requirement request in TO18 is unreasonably high and should be reduced. The complaint asks that, if the outcome of the litigation in TO18 is that the Utility’s revenue requirement should be set at a lower level than the settled revenue requirement from the TO17 settlement, that the FERC order refunds to that lower level determined in TO18 litigation. On April 20, 2017, the Utility answered the complaint, requesting that FERC dismiss it. The Utility is unable to predict when and how the FERC will respond to the complaint.

Transmission Owner Rate Case for 2018

On July 27, 2017, the Utility filed a rate case (the “TO19 rate case”) at the FERC requesting a 2018 retail electric transmission revenue requirement of $1.792 billion, a $74 million increase over the proposed 2017 revenue requirement of $1.718 billion. The forecasted network transmission rate base for 2018 is $6.9 billion. The Utility is also seeking an ROE of 10.75%, which includes an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO. In the filing, the Utility forecasted capital expenditures of approximately $1.4 billion. On September 28, 2017, the FERC issued an order accepting the Utility’s July 2017 filing, subject to hearing and refund, and established March 1, 2018, as the effective date for rate changes. FERC also ordered that the hearings will be held in abeyance pending settlement discussion among the parties.

On September 29, 2017, several of the parties that have intervened in the TO18 rate case filed a complaint at the FERC, and requested that the complaint be consolidated with the TO19 rate case. The TO19 complaint asserts that the Utility’s revenue requirement request in TO19 is unreasonably high and should be reduced. The complaint asks that, if the outcome of the litigation in TO18 is that the Utility’s revenue requirement should be set at a lower level than the settled revenue requirement approved by FERC in TO17, FERC order refunds to that lower level determined in the TO18 litigation. On October 17, 2017, the Utility answered the complaint, requesting that FERC dismiss it. The Utility is unable to predict when and how the FERC will respond to the complaint.

For more information, see PG&E Corporation’s and the Utility’s 2016 Form 10-K and its subsequent quarterly reports on Form 10-Q.

Cost of Capital

On July 13, 2017, the CPUC issued a final decision ~~granting a petition for modification~~adopting, with no modifications, the PFM filed in February 2017 by San Diego Gas & Electric Company, Southern California Gas Company, Southern California Edison, the ~~Utility~~ORA, TURN, and the ~~other~~Utility.

The final decision extends the Utility’s next cost of capital application filing deadline by two ~~California investor-owned electric utilities~~years to ~~clarify that~~April 22, 2019, for the ~~CPUC’s previously adopted~~year 2020. The final decision also reduces the Utility’s authorized ROE from 10.40% to 10.25%, effective January 1, 2018, and resets the Utility’s authorized cost of long-term debt and preferred stock effective January 1, 2018. In addition, the decision suspends the cost of capital adjustment mechanism ~~would not be triggered before their 2018~~to adjust cost of capital ~~applications are due on April 20, 2017. As a result,~~for 2018, but allows the adjustment mechanism to operate for 2019 if triggered. The Utility’s ~~currently authorized return on equity of 10.40% and~~current capital structure ~~consisting~~ of 52% common equity, 47% long-term debt, and 1% preferred ~~stock,~~equity remains unchanged.

The final decision also leaves the proceeding open to facilitate gathering of information to inform the next cost of capital proceeding, as well as to provide a possible venue in which to consider whether the Utility’s ROE should be reduced until any recommendations that the CPUC may adopt in the second phase of its safety culture investigation are implemented, as described in the assigned Commissioner’s May 8, 2017 Scoping Memo and Ruling issued in the Safety Culture OII.

On September 29, 2017, the Utility submitted an advice letter to the CPUC, updating its cost of capital and the estimated revenue requirement impacts with an effective date of January 1, 2018. The long-term debt cost reset reflects actual embedded costs as of the end of August 2017 and forecasted interest rates for the new long-term debt expected to be issued for the remainder of 2017 and all of 2018. The Utility estimates that its annual revenue requirement will ~~remain~~be reduced by approximately $120 million, beginning in 2018. This estimate is based on the ~~same~~updated cost of capital in the September 29, 2017 advice letter and current rate base. In the fourth quarter of 2017, the Utility’s final advice letters for ~~2017.~~authorized 2018 revenue requirements will be filed using the cost of capital authorized pursuant to the September 29, 2017 advice letter. Changes in market interest rates may have material effects on the cost of the Utility’s future financings, but will not affect the authorized cost of capital in 2018.

For more information, see PG&E Corporation’s and the Utility’s 2016 Form 10-K and its subsequent quarterly reports on Form 10-Q.

Diablo Canyon Nuclear Power Plant

Joint Proposal for Plant Retirement

On August 11, 2016, the Utility submitted an application to the CPUC to retire Diablo Canyon at the expiration of its current operating licenses in 2024 and 2025 and replace it with a portfolio of energy efficiency and GHG-free resources. The application implements a joint proposal between the Utility and the Friends of the Earth, Natural Resources Defense Council, Environment California, International Brotherhood of Electrical Workers Local 1245, Coalition of California Utility Employees, and Alliance for Nuclear Responsibility.

~~The application and joint proposal include a voluntary increase in the Utility’s target for RPS-eligible resources~~ PG&E subsequently modified its testimony to ~~55%, effective in 2031 through 2045, as compared~~move consideration of two tranches of post-2025 replacement procurement to the ~~state’s goal of 50% renewables.~~ CPUC’s Integrated Resource Plan proceeding.The parties to the joint proposal proposed that the Utility be authorized to procure GHG-free replacement resources in three competitive procurement tranches: in Tranche 1, the Utility would be authorized to obtain 2,000 gross GWh of energy efficiency savings to be implemented over the 2018 to 2024 time period; in Tranche 2, the Utility would be authorized to procure through a solicitation 2,000 GWh of GHG-free energy resources that will commence energy deliveries or add energy efficiency projects to the system in the 2025 to 2030 time period; and in Tranche 3, the Utility would commit to a voluntary 55% RPS, and would maintain this voluntary commitment through 2045 or until superseded by action of the state legislature or the CPUC.The three tranches of resource procurement in the application and joint proposal are not intended to specify all energy resources that will be needed to ensure the orderly replacement of Diablo Canyon. Instead, the Utility expects that the full solution will be addressed in ongoing CPUC proceedings.

Costs associated with energy efficiency projects or programs in Tranche 1 and Tranche 2 would be recovered through the Utility’s electric public purpose program rates as non-bypassable charges, consistent with the existing recovery mechanisms for energy efficiency program costs. GHG-free energy resources costs from Tranche 2 are proposed to be recovered through a non-bypassable cost allocation mechanism called the Clean California Charge that (1) equitably allocates costs and benefits, such as RPS or Resource Adequacy credits, associated with the procurement among responsible load-serving entities, and (2) determines the net capacity costs of such procurement consistent with the methodology for the allocation of net capacity costs laid out by the CPUC. Costs associated with procurement for Tranche 3 would be recovered through a separate renewable non-bypassable charge.

The application seeks confirmation from the CPUC that the Utility’s full investment in Diablo Canyon and authorized rate of return will be recovered in rates by the time the facility ceases operations. Additionally, the Utility requests that the CPUC pre-approve the recovery of certain costs related to the closure of the Diablo Canyon. These include the non-bypassable cost allocation mechanism for procurement of GHG-free energy and the recovery of $1.3 billion for administration and acquisition of the new Tranche 1 energy efficiency procurement as authorized energy efficiency funding, subject to return of all unspent funds; the recovery of employee retention and retraining and development programs to continue safe and efficient operation of Diablo Canyon through the end of its license periods, estimated at approximately $350 million; and a community mitigation program to compensate San Luis Obispo County for the decline in local economic stimulus provided by Diablo Canyon through a transition period ending in 2025, estimated at approximately $50 million. The Utility also seeks cost recovery of approximately $50 million in costs related to the federal and state Diablo Canyon license renewal process.

More than 40 parties have submitted responses and protests to the Utility’s application. ~~A prehearing conference~~Rebuttal testimony and comments on the ~~application~~community impact mitigation program settlement agreement were submitted to the CPUC on March 17, 2017. Evidentiary hearings took place in April 2017. Certain intervenors argued that a portion of or the entire community impact mitigation program and employee retention plan be funded by shareholders.

On May 23, 2017, the Utility filed a settlement agreement that was ~~held on October 6,~~reached with the parties listed above as well as TURN, ORA, and San Luis Obispo Mothers for Peace, related to the recovery of license renewal costs and cancelled project costs. The settlement agreement would allow for recovery from customers of $18.6 million of the total license renewal project cost of $53 million evenly over an 8-year period beginning January 1, 2018. Related to cancelled project costs, the settlement agreement would allow for recovery from customers of 100% of the direct costs incurred prior to June 30, 2016, and 25% recovery of direct costs incurred after June 30, 2016. ~~The ALJ heard arguments~~On June 22, 2017, the Green Power Institute filed comments on the ~~scope~~settlement agreement recommending that only $9.3 million of the license renewal project costs be recovered from customers. During the nine months ended September 30, 2017, the Utility incurred charges of $47 million related to the settlement agreement, of which $24 million is for cancelled projects and $23 million is for disallowed license renewal costs.

Opening and reply briefs were filed on May 26, 2017, and June 16, 2017, respectively, in which no new issues ~~to be addressed in~~were raised. On September 14, 2017, the ~~proceeding and stated he would issue a scoping order after the~~CPUC hosted two public participation hearings ~~that were held~~ in San Luis Obispo, California. Final oral arguments are scheduled to take place on ~~October 20, 2016. On October 27, 2016, the ALJ issued a ruling requiring the Utility to submit supplemental testimony related to Diablo Canyon land ownership no later than~~ November ~~18, 2016.~~28, 2017. The Utility expects that a final decision will be issued by the end of 2017. Upon CPUC approval of the application and such approval becoming final and non-appealable, the Utility will withdraw its license renewal application currently pending before the ~~NRC when such approval has become final and non-appealable.~~NRC. PG&E Corporation and the Utility are unable to predict whether the CPUC will approve the application.

California State Lands Commission Lands Lease

On June 28, 2016, California State Lands Commission approved a new lands lease for the intake and discharge structures at Diablo Canyon to run concurrently with Diablo Canyon’s current operating licenses, until Diablo Canyon Unit 2 ceases operations in August 2025. The Utility believes that the approval of the new lease will ensure sufficient time for the Utility to identify and bring online a portfolio of GHG-free replacement resources. The Utility will submit a future lease extension request to address the period of time required for plant decommissioning, which under NRC regulations can take as long as 2060 years. On August 28, 2016, the World Business Academy ~~(WBA)~~ filed a writ in the Los Angeles Superior ~~Court. WBA asserts~~Court asserting that the State Lands Commission committed legal error when it determined that the short term lease extension for an existing facility was exempt from review under the California Environmental Quality ~~Act. If the petitioner prevails in its challenge,~~Act and alleging that the State Lands Commission ~~could~~should be required to perform an environmental review of the new lands lease. ~~No schedule has been set for consideration~~The trial took place on July 11, 2017, in Los Angeles Superior Court and the judge dismissed the petition on all grounds, ruling that the State Lands Commission properly determined the short term lease extension was subject to the existing facilities exemption under the California Environmental Quality Act. World Business Academy had 60 days from entry of judgement to appeal the ~~writ at this time but~~decision to the ~~Utility expects a ruling in the first half~~California Court of ~~2017.~~Appeals.

Asset Retirement Obligations

~~The Utility expects that the decommissioning of Diablo Canyon will take many years after the expiration of its current operating licenses.~~ Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the NDCTP. ~~Actual decommissioning costs may vary from these estimates as~~On May 25, 2017, the CPUC issued a ~~result of changes~~final decision in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers throughthe 2015 NDCTP adopting a ~~non-bypassable charge that the Utility expects will continue until those costs are fully recovered.~~

~~On March 1, 2016, the Utility submitted its updated~~nuclear decommissioning cost estimate ~~with~~of $1.1 billion for Humboldt Bay, corresponding to the ~~CPUC. The~~Utility’s request, and $2.4 billion for Diablo Canyon, compared to the Utility’s request of $3.8 billion, or 64 percent of its request. On an aggregate basis, the final decision adopted a $3.5 billion total nuclear decommissioning cost estimate, compared to $4.8 billion requested by the Utility. Compared to the Utility’s estimated ~~undiscounted~~ cost to decommission the Utility’s nuclear power plants increased by approximately $1.4 billion, for a total estimated cost of $4.8 billion, due to increased estimated costs related to spent fuel storage, staffing, and out-of-state waste disposal. The Utility requested that the CPUC authorize the collection of increased annual revenue requirements beginning on January 1, 2017 based on these updated cost estimates. Additionally, as a result of the joint proposal discussed above, an increase of $115 million to the ARO was recognized on the Utility’s Condensed Consolidated Balance Sheetsin the second quarter of 2016.

While the NDCTP forecast includes employee severance program estimates, it does not include estimated costs related to the joint proposal’s employee retention and retraining and development programs, and the San Luis Obispo County community mitigation program described above. The Utility intends to conduct a site-specific decommissioning study to update the 2015 NDCTP forecast and to submit the study to the CPUC by mid-2019.

On July 15, 2016, the assigned CPUC commissioner and ALJ issued a scoping memo for the Utility’s 2015 NDCTP and excluded from the scope of the proceeding the issue on whether the Utility should be required to present additional analysis for a license extension scenario for Diablo Canyon, ~~as a result of~~ the ~~Utility’s announcement of its plan to not seek relicensing of Diablo Canyon beyond its current operating authority. The scoping memo also~~final decision adopts within the scope of the proceeding a reasonableness review of the Utility’s estimated updated cost to decommission the Utility’s nuclear power plants and of the forecasts of certain expenses and the decommissioning trust funds’ rates of return. Evidentiary hearings took place in September 2016 and opening briefs were submitted on October 14, 2016. Intervenor parties proposed several major recommendations including a reduction to the total spent nuclear fuel storage forecast, a reduction to the large component (reactor vessels, steam generators, and other large plant components) removal cost estimate, and a reduction to the waste disposal estimate. Additionally, intervenors asserted that the CPUC should not permit the Utility to increase its Diablo Canyon-related revenue requirement at this time as it has not demonstrated its current estimate is reasonable. Parties also claimed that the Utility has not justified its increase to securityassumptions which lower costs and decommissioning oversight contractor staff costs. No party challenged the Utility’s decommissioning trust funds rates of return or cost escalation assumptions. Reply briefs were submitted on October 31, 2016. Intervenor parties reiterated that the Utility has not justified increases in costs due tofor large component removal, site security, decommissioning contractor staff, spent nuclear fuel storage, and waste disposal. The Utility ~~confirmed that~~can seek recovery of these costs in the ~~testimony and work papers support~~2018 NDCTP. The CPUC’s final decision resulted in a $66 million reduction to the ~~cost increases as well as~~ARO on the ~~total estimate~~Condensed Consolidated Balance Sheets related to ~~decommission Diablo Canyon.~~the assumed length of the wet cooling period of spent nuclear fuel after plant shut-down.

The estimated nuclear decommissioning cost is discounted for GAAP purposes and recognized as an ARO on the Condensed Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued in accordance with GAAP was ~~$3.5~~$3.4 billion at September 30, ~~2016, which includes an $818 million adjustment to reflect the increased cost estimates~~2017, and ~~the $115 million increase resulting from the joint proposal described above, and $2.5~~$3.5 billion at December 31, ~~2015.~~2016. These estimates are based on decommissioning cost studies, prepared in accordance with the CPUC requirements. Changes in these estimates could materially affect the amount of the recorded ARO for these assets.

As of September 30, ~~2016,~~2017, the nuclear decommissioning trust accounts’ total fair value was ~~$2.9~~$3.2 billion. Changes in the estimated costs, the timing of decommissioning or the assumptions underlying these estimates could cause material revisions to the estimated total cost to decommission.

The Utility expects to file its 2018 NDCTP application in late 2018 or early 2019.

For ~~additional~~more information, see PG&E Corporation’s and the ~~2015~~Utility’s 2016 Form 10-K ~~the 2016 Q1 Form 10-Q,~~ and ~~the 2016 Q2~~its subsequent quarterly reports on Form 10-Q.

~~CPUC Investigation of the Utility’s Safety Culture~~Application to Establish a Wildfire Expense Memorandum Account

On ~~August 27, 2015,~~July 26, 2017, the Utility filed an application with the CPUC ~~began~~requesting to establish a ~~formal investigation into whether~~WEMA to track wildfire expenses and to preserve the ~~organizational culture and governance of PG&E Corporation and~~opportunity for the Utility ~~prioritize safety~~to request recovery of wildfire costs in excess of insurance at a future date. Concurrently with this application, the Utility also submitted a motion to the CPUC requesting that the WEMA be deemed effective as of July 26, 2017, such that the Utility may begin recording costs to the account while the application is pending before the CPUC.

Under the WEMA as proposed, the Utility would record incremental costs related to wildfire, including: (1) payments to satisfy wildfire claims, including any deductibles, co-insurance and ~~adequately direct resources~~other insurance expense paid by the Utility but excluding costs that have already been authorized in the Utility’s GRC; (2) outside legal costs incurred in the defense of wildfire claims; (3) premium costs not in rates; and (4) the cost of financing these amounts. Insurance proceeds, as well as any payments received from third parties, would be credited to ~~promote accountability~~the WEMA as they are received. The WEMA would not include the Utility’s costs for fire response and ~~achieve safety goals and standards.~~infrastructure costs which are tracked in CEMA. The Utility would be required to file an application to seek approval to recover costs tracked in WEMA. The CPUC ~~directed~~has set a prehearing conference on this matter for December 8, 2017. The Utility cannot predict the outcome of this proceeding.

Gas and Electric Safety Citation Program

~~The CPUC stated~~daily basis, or on less than a daily basis, for violations that the initial phase of the proceeding was categorized as rate setting because it will consider issues both of fact and policy and because the Utility and PG&E Corporation do not face the prospect of fines, penalties, or remedies in this phase. Upon completion of the consultant’s report, the assigned commissioner will determine the scope of and next actions in the proceeding. The timing, scope and potential outcome of the investigation are uncertain.

~~Rehearing of CPUC Decisions Approving 2006 – 2008 Energy Efficiency Incentive Awards~~continued for more than one day.

On September ~~17, 2015,~~29, 2016, the CPUC ~~granted TURN’s~~issued a final decision adopting improvements and ~~ORA’s long-standing applications~~refinements to its gas and electric safety citation programs. Specifically, the final decision refines the criteria for ~~rehearing~~the SED to use in determining whether to issue a citation and the amount of penalty, sets an administrative limit of $8 million per citation issued, makes self-reporting voluntary in both gas and electric programs, adopts detailed criteria for the utilities to use to voluntarily self-report a potential violation, and refines other issues in the programs. The decision also merges the rules applicable to its gas and electric safety citation programs into a single set of rules that replace the previous safety citation programs and adopts non-substantive changes to these programs so that the programs can be similar in structure and process where appropriate.

On February 21, 2017, California State Senator Jerry Hill filed a petition for modification of the CPUC’s September 29, 2016 decision regarding the safety citation program. The petition for modification requests that the decision be modified to reinstate mandatory self-reporting for gas safety potential violations and require gas utilities to notify local governments within 30 days when a self-report is submitted to SED. Under the request, electric utilities would keep the voluntary self-reporting regime and would not be required to notify local governments, but the CPUC ~~decisions that awarded energy efficiency incentive payments~~has discretion to direct notification within ten days on a case-by-case basis. The CPUC’s Office of Safety Advocates filed a response suggesting additional potential modification to the gas and electric safety citation programs. The Utility cannot predict when or how the CPUC will act on the petition of modification.

Other Regulatory Proceedings and Initiatives

Power Charge Indifference Adjustment OIR

On April 25, 2017, the Utility, along with Southern California ~~IOUs~~Edison Company and San Diego Gas & Electric Company, filed a joint application with the CPUC on how to allocate costs associated with long-term power commitments in a manner that ensures all customers are treated equally. At issue is how customers within communities that choose to implement CCA power arrangements and those served under direct access pay for their share of the ~~2006-2008 energy efficiency program cycle. Under~~costs. The utilities believe that these customers are not paying their full share of costs associated with the ~~incentive ratemaking mechanism applicable~~long-term commitments, which results in other customers paying more, which is inconsistent with state law. The Utility is committed to helping create a cost allocation method that treats all customers fairly and equally, whether they continue to receive service from the Utility or choose a CCA or direct access provider. The Utility projects that approximately 50 percent of its customers will purchase electricity from a CCA or direct access provider by 2020. Without changes to the ~~2006-2008 program cycle,~~current cost allocation system, a portion of the contract and facilities costs will be shifted to customers who remain with the Utility ~~could~~or live in areas that do not have ~~earned incentive revenues up~~access to ~~a maximum of $180 million, depending on~~alternative electricity providers. The utilities’ joint proposed approach would replace the ~~extent to~~current system, which is known as the ~~Utility achieved~~PCIA, with an updated system known as the energy savings targets. Conversely, to the extent the Utility failed to achieve the targets, the Utility could have been required to offset future incentive earnings claims by amounts previously awarded, and, in addition, could have incurred penalties of up to $180 million. The Utility was awarded a total of $104 million for the 2006-2008 program cycle.Portfolio Allocation Methodology.

On September 15, 2016, the CPUC approved a settlement agreement filed by the Utility, ORA, and TURN to resolve all issues related to the 2006-2008 customer energy efficiency shareholder incentives. The final decision requires the Utility to reduce future energy efficiency shareholder incentives by $29.1 million. The reduction of the shareholder incentive award will be applied in installments of $5.8 million per year for five years, provided that the Utility has sufficient energy efficiency incentive awards to offset that amount. If shareholder incentives are insufficient to offset this amount, the offset in the following year will be increased by the shortfall. At its discretion, the Utility may increase the amount of the offset to reduce the $29.1 million more quickly. If the amount has not been fully offset at the end of five years, the balance will be credited against future energy efficiency program spending. The first offset was requested by the Utility in the September 1, 2016 shareholder incentive advice letter related to the 2014-2015 Energy Efficiency Incentive Awards (see below).

~~2014–2015 Energy Efficiency Incentive Awards~~

On June 29, 2017, the CPUC dismissed the Utility’s joint Portfolio Allocation Methodology application without prejudice and instead approved an OIR to review, revise, and consider alternatives to the PCIA. The OIR will focus on PCIA within the larger context of consumer choice in energy services, and should not be considered a follow-up to the CPUC and Energy Commission Joint En Banc on Customer Choice in California. On September ~~1, 2016,~~25, 2017, the CPUC issued a scoping memo and ruling establishing a procedural schedule and a new overall goal to mitigate cost increases for both bundled and departing load customers. Testimony is scheduled for the first quarter of 2018. Evidentiary hearings are scheduled for the second quarter of 2018 and a proposed decision is expected by the third quarter of 2018.

Customer Choice

On May 19, 2017, California energy companies, along with other stakeholders discussed customer choice and the future of California’s electric industry at a CPUC “en banc” meeting. Specifically, the goal of the meeting was to frame a discussion on the trends that are driving change within California’s electricity sector and overall clean-energy economy and to lay out elements of a path forward to ensure that California achieves its reliability, affordability, equity, and carbon reduction imperatives while recognizing the important role that technology and customer preferences will play in shaping this future.

On October 11, 2017, the CPUC announced the formation of the California Customer Choice Project to examine the issues and produce a report evaluating regulatory framework options in early 2018. The Commission held an informal public workshop on October 31, 2017, to gather stakeholder input on global and national electric market choice models, including California’s 2020 market. The project will produce a white paper that will provide a framework to evaluate customer choice models. The white paper will not present a recommendation nor is it intended to provide the basis for instituting a rulemaking. The white paper is expected in early 2018 with a final version expected by the second quarter of 2018. While the CPUC had indicated intent to open an OIR related to customer choice, the Utility ~~filed an advice letter with~~is unable to predict if and when the CPUC requesting a shareholder incentive award for a portion of the energy savings it achieved through its energy efficiency programs in the 2014 and 2015 program years. The Utility requested $24.9 million, and further requested that this amount be reduced by $5.8 million as a result of the settlement agreement related to the 2006-2008 energy efficiency awards, for a total award of $19.1 million. As indicated above, on September 15, 2016, the CPUC approved the settlement agreement. On October 7, 2016, the Utility submitted a supplemental shareholder incentive advice letter reflecting the approval by the CPUC of the settlement agreement and other minor modifications to its September 1, 2016 incentive award request. The advice letter requires CPUC approval in a resolution, which the Utility anticipates receiving during the fourth quarter of 2016.

~~Utility-Owned PV Generation Cost Savings Incentive Award~~

In April 2010, the CPUC authorized the Utility to develop, own, and operate PV facilities and established a cost savings incentive mechanism which states that shareholders are eligible to retain ten percent of the difference between the actual average cost per unit and the threshold set by the CPUC. From 2011 – 2013, the Utility constructed nine PV projects with a total capacity of 150 MW and the weighted average unit capital cost came in below the CPUC specified threshold. In July 2016, the CPUC approved the recovery of $16 million in shareholder incentives related to these projects under the PV capital cost savings incentive mechanism.

LEGISLATIVE AND REGULATORY INITIATIVES

The California Legislature and the CPUC have adopted requirements, policies and decisions to improve and refine gas and electric safety citation programs, accommodate the growth in distributed electric generation resources (including solar installations), increase the amount of renewable energy delivered to customers, foster the development of a state-wide electric vehicle charging infrastructure to encourage the use of electric vehicles, promote customer energy efficiency and demand response programs, and implement new state law requirements applicable to natural gas storage facilities. In addition, the CPUC continues to implement state law requirements to reform electric rates to more closely reflect the utilities’ actual costs of service, reduce cross-subsidization among customer rate classes, implement new rules and rates for net energy metering (which currently allow certain self-generating customers to receive bill credits for surplus power at the full retail rate), and allow customers to have greater control over their energy use. Significant developments that have occurred since the 2015 Form 10-K was filed with the SEC are discussed below.

The Utility’s ability to recover its costs, including investments associated with legislative and regulatory initiatives, as well as its electricity procurement and other operating costs, will, in large part, depend on the final form of legislative or regulatory requirements, and whether the associated ratemaking mechanisms can be timely adjusted to reflect changes in customer demand for the Utility’s electricity and natural gas service. may open an OIR.

Electric Distribution Resources Plan

As required by California law, on July 1, 2015, the Utility filed its proposed ~~electric distribution resources plan~~DRP for approval by the CPUC. The Utility’s plan identifies optimal locations on its electric distribution system for deployment of DERs. The Utility’s proposal is designed to allow energy technologies to be ~~interconnected with each other and~~ integrated into the larger grid while continuing to provide customers with safe, reliable, and affordable electric service. ~~The Utility envisions~~

On February 27, 2017, the CPUC issued a ~~future electric grid, titled~~ruling that seeks the ~~Grid~~development of ~~Things™,~~a process for incorporating DER forecasts into the DRP that ~~would allow customers to choose new advanced energy supply technologies~~takes into consideration the coordination with other statewide planning and ~~services to meet their needs consistent with safe, reliable and affordable electric service.~~

~~In August 2016,~~forecasting processes such as ~~part of~~ the ~~CPUC’s consideration of the Utility’s electric distribution resources plan, hearings were held on field demonstration projects proposed by~~CEC’s Integrated Energy Policy Report. This ruling mandated the Utility, along with the other California IOUs, to ~~test various distribution-related services that DERs might provide~~develop a draft joint proposal for the CPUC and stakeholder consideration on the process for developing DER forecasts. On June 9, 2017, the utilities submitted a draft joint proposal for CPUC and stakeholder consideration. Comments were submitted by stakeholders on the draft proposal on July 10, 2017. On August 9, 2017, the CPUC issued a ruling directing all California IOUs to use the ~~Utility. A~~CEC’s Integrated Energy Policy report forecast for the 2017-2018 distribution planning cycle. The August 9, 2017 ruling also requires the Energy Division to work with the CEC to develop a preliminary proposal for DER growth scenarios. The CPUC will begin workshops to discuss the proposals in the fourth quarter of 2017 and a final decision is expected ~~later this year on~~by the ~~field demonstration projects.~~ end of the first quarter of 2018.

~~Additionally,~~On May 16, 2017, the CPUC issued a ruling requiring stakeholder responses to questions posed in a CPUC staff white paper on grid modernization. The white paper is aimed at informing the development of a CPUC framework to evaluate grid-modernization investments. A workshop took place and comments were submitted by stakeholders in June 2017.

On June 30, 2017, the CPUC issued another ruling soliciting stakeholder responses on questions set forth in a CPUC staff white paper on proposing a DIDF. The DIDF aims to establish a future process for identifying distribution deferral opportunities for DERs. Stakeholder comments on DIDF were submitted on August ~~22, 2016,~~7, 2017, with reply comments submitted on August 18, 2017. The CPUC may issue a combined proposed decision on DIDF and grid-modernization in the fourth quarter of 2017. The Utility ~~filed comments generally supporting a CPUC ruling proposing a revised scope and schedule for the proceeding. At this time, it~~ is ~~uncertain~~unable to predict when a final CPUC decision approving, disapproving, or modifying the Utility’s ~~electric distribution resources plan~~DRP will be issued.

Integrated Distributed Energy Resources Proceeding – Regulatory Incentives Pilot Program

On April 4, 2016, the ~~assigned~~ CPUC ~~commissioner and ALJ~~ issued a ruling proposing to establish, on a pilot basis, an interim program offering regulatory incentives to the Utility and the other two large California IOUs for the deployment of cost-effective DERs. The ruling assumes that the incentive would take the form of an additional payment to the Utility of 3.5% (grossed up for taxes) of the payments made to the DER provider(s). The exact figure would be determined later if the proposal or a similar alternative is adopted by the CPUC. The ruling also statesstated that it ~~does~~did not intend for this phase to adopt a new regulatory framework or business model for the California electric utilities. On December 22, 2016, the CPUC issued a final decision in the proceeding which authorizes a pilot to test a regulatory incentive mechanism through which the Utility will earn a 4% pre-tax incentive on annual payments for DERs, as well as test a regulatory process that will allow the Utility to competitively solicit DER services to defer distribution infrastructure. Each utility is required to conduct at least one pilot, but may conduct up to three additional pilots.

In June 2017, the Utility submitted a pilot project proposal to the CPUC for approval to begin solicitations. The pilot aims to evaluate the effectiveness of an earnings opportunity in motivating utilities to source DERs. On October 17, 2017, the Utility notified the CPUC of potential changes to its pilot project proposal due to the uncertain condition of the Utility’s facilities in the area of the Northern California wildfires. On October 27, 2017, the CPUC issued a draft resolution that proposed modifications to the Utility’s pilot program. The CPUC is expected to issue a final resolution by the end of 2017.

Transportation Electrification Application

California Law (Senate Bill 350) requires the CPUC, in consultation with the CARB and the CEC, to direct the Utility and electrical corporations to file applications for programs and investments to accelerate widespread TE. In September 2016, the CPUC directed the Utility and the other large IOUs to file TE applications which include both short-term projects (of up to $20 million in total) and two- to five-year programs with a requested revenue requirement determined by the Utility. On January 20, 2017, the Utility filed its TE application with the CPUC requesting a total of up to $253 million (approximately $211 million in capital expenditures) in program funding over five years (2018 - 2022) primarily related to make-ready infrastructure for TE in medium to heavy-duty vehicle sectors. The CPUC may issue a proposed decision on this request in the first quarter of 2018.

FEDERAL INITIATIVES

Strengthening the Cybersecurity of Federal Networks and Critical Infrastructure Executive Order

On May 911, 2017, President Donald J. Trump signed Executive Order “Strengthening the Cybersecurity of Federal Networks and ~~May 23, 2016,~~Critical Infrastructure” that includes provisions, among other things, for the executive branch to use its authorities and capabilities to support the cybersecurity risk management efforts of the owners and operators of critical infrastructure. Among other things, it requires heads of appropriate sector-specific agencies to identify authorities and capabilities that agencies could employ to support the cybersecurity efforts of critical infrastructure entities identified to be at greatest risk of attacks that could reasonably result in catastrophic regional or national effects on public health or safety, economic security, or national security. It also requires within 180 days of the cybersecurity order, before November 7, 2017, a classified report detailing the findings and recommendations for better supporting the cybersecurity risk management efforts of such entities. The Utility is unable to predict the impact that the executive order will have on the Utility two other California utilities (the “Joint Utilities”) and other parties filed their comments. The Joint Utilities indicate that providing a regulatory incentive to utilities to deploy DERs in place of distribution investment is premature until the ~~operating~~report is released and performance characteristics of DERs are better understood and evaluated as part of pilot projects. The Joint Utilities instead propose initiating DER pilots that would advance understanding of distribution deferral and DER procurement processes.

~~On September 1, 2016,~~ the ~~assigned CPUC commissioner and ALJ issued an amended scoping memo and ruling that re-categorized~~federal administration takes steps to implement some or all activities in the proceeding as rate-setting, consolidated remaining issues into one phase, and proposed a revised regulatory incentive pilot to test how an earnings opportunity affects DER sourcing. On September 15 and September 22, 2016, the Joint Utilities and other parties filed comments on the revised regulatory incentive pilot. The Joint Utilities support piloting different earnings mechanisms to better compare advantages and disadvantages of different alternatives and repeated their recommendation that the CPUC enable a broader dialogue on utility compensation mechanisms, rather than narrowly focusing on regulatory incentives for DER deployment. A proposed CPUC decision is expected later this year.

~~Electric Rate Reform and Net Energy Metering~~

On July 3, 2015, the CPUC approved a final decision to authorize the California IOUs to gradually flatten their tiered residential electric rate structures from four tiers to two tiers by January 1, 2019. The decision approved higher minimum bill charges for residential customers and also allows the imposition of a surcharge on customers with extremely high electricity use beginning in 2017. The decision requires the Utility to file a proposal by January 1, 2018, to charge residential electric customers based on time-of-use rates (known as “default time-of-use rates”) unless customers elect otherwise. The Utility also may propose to impose a fixed charge on residential electric customers. Under the CPUC’s decision, default time-of-use rates must be implemented before the CPUC will permit the imposition of a fixed charge in electric rates.

In January 2016, the CPUC adopted new NEM rules and rates. The new rules and rates are expected to become effective for new NEM customers later in 2016, when the Utility is expected to reach its current NEM cap. The CPUC indicated that it may revisit the NEM successor tariff in 2019. After the current NEM cap is reached, new NEM customers will be required to pay an interconnection fee, will be charged for energy use on time-of-use rates, and will be required to pay non-bypassable charges to help fund some of the costs of low-income, energy efficiency, and other programs that other customers pay. Unlike the initial NEM tariff, there is no cap on the total capacity of distributed generation that can be installed under the new rules. On March 7, 2016, the Utility and certain other parties, including TURN and CUE, filed applications for rehearing. The Utility requested that the CPUC vacate its January 2016 decision that the Utility asserts contains legal and factual errors. Many parties argued that the CPUC failed to complete its duties under AB 327, which required the CPUC to evaluate the costs and benefits of NEM. On September 15, 2016, the CPUC voted to deny the applications for rehearing, concluding that good cause had not been established to grant a rehearing and that the NEM decision adopted a successor tariff as required.

~~Electric Vehicle (EV) Infrastructure Development~~

In December 2014, the CPUC issued a decision adopting a policy to expand the California utilities’ role in developing EV charging infrastructure to support California’s climate goals. On February 9, 2015, the Utility filed an application requesting that the CPUC approve the Utility’s proposal to deploy, own, and maintain more than 25,000 EV charging stations and the associated infrastructure. The Utility proposed to engage with third-party EV service providers to operate and maintain the charging stations. The Utility requested that the CPUC approve forecasted capital expenditures of $551 million over the five-year deployment period.

On September 4, 2015, the assigned CPUC commissioner and the ALJ issued a scoping memo and procedural schedule that required the Utility to supplement its application by submitting a more phased deployment approach that will be considered in a first phase of the proceeding. On October 12, 2015, the Utility submitted supplemental testimony presenting two separate proposals, with the first proposal including capital expenditures of $70 million for approximately 2,500 charging stations and the second proposal comprising $187 million for approximately 7,500 charging stations.

After discussions with a number of parties about the two proposals, the Utility filed with the CPUC a settlement agreement on March 21, 2016 that it entered into with environmental advocates, automakers, electric vehicle drivers, labor, and environmental justice advocates, to deploy about 7,500 charging stations over three years with forecasted capital expenditures of $132 million. (TURN, ORA, and certain equipment suppliers are not parties to the settlement agreementand filed responses on April 12, 2016, generally opposing the settlement agreement.) The settlement agreement is subject to approval by the CPUC. Hearings were held in April 2016 and a proposed decision for the first phase of the proceeding is expected to be issued in the fourth quarter of 2016. Further deployment of EV charging stations would be considered in a second phase of the proceeding depending on the outcome of the first phase. report’s recommendations.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous ~~wastes, such as groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations;~~wastes; the reporting and reduction of ~~carbon dioxide~~CO2 and other ~~greenhouse gas~~GHG emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements, as well as “Item 1A. Risk Factors” and Note 13 of the Notes to the Consolidated Financial Statements in the ~~2015~~2016 Form 10-K.)

CONTRACTUAL COMMITMENTS

PG&E Corporation and the Utility enter into contractual commitments in connection with future obligations that relate to purchases of electricity and natural gas for customers, purchases of transportation capacity, purchases of renewable energy, and purchases of fuel and transportation to support the Utility’s generation activities. (See “Purchase Commitments” in Note 9 of the Notes to the Condensed Consolidated Financial Statements). Contractual commitments that relate to financing arrangements include long-term debt, preferred stock, and certain forms of regulatory financing. For more in-depth discussion about PG&E Corporation’s and the Utility’s contractual commitments, see “Liquidity and Financial Resources” above and Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Commitments in the ~~2015~~2016 Form 10-K.

Off-Balance Sheet Arrangements

PG&E Corporation and the Utility do not have ~~anyoff-balance~~any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed in Note 13 of the Notes to the Consolidated Financial Statements in the ~~2015~~2016 Form 10-K (the Utility’s commodity purchase agreements).

RISK MANAGEMENT ACTIVITIES

PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. PG&E Corporation and the Utility face market risk associated with their operations; their financing arrangements; the marketplace for electricity, natural gas, electric transmission, natural gas transportation, and ~~storage;~~storage, emissions allowances and offset credits, other goods and ~~services;~~services, and other aspects of their businesses. PG&E Corporation and the Utility categorize market risks as ~~“price~~“commodity price risk” and “interest rate risk.” The Utility is also exposed to “credit risk,” the risk that counterparties fail to perform their contractual obligations.

The Utility actively manages market risk through risk management programs designed to support business objectives, discourage unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only for ~~non-trading~~risk mitigation purposes ~~(i.e., risk mitigation)~~ and not for speculative purposes. The Utility’s risk management activities include the use of physical and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases. The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored periodically. These activities ~~arediscussed~~are discussed in detail in the ~~2015~~2016 Form 10-K. There were no significant developments to the Utility’s and PG&E Corporation’s risk management activities during the nine months ended September 30, ~~2016.~~2017.

CRITICAL ACCOUNTING POLICIES

The preparation of the Condensed Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. PG&E Corporation and the Utility consider their accounting policies for regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal and regulatory matters, ~~asset retirement obligations,~~accounting policies for insurance recoveries, AROs, and pension and other postretirement benefits plans to be critical accounting policies. These policies are considered critical accounting policies due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ materially from these estimates. These accounting policies and their key characteristics are discussed in detail in the ~~2015Form~~2016 Form 10-K.

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

See the discussion above in Note 2 of the Notes to the Condensed Consolidated Financial Statements.

FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions which are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management's knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines, associated with various investigations and proceedings; forecasts of pipeline-related expenses that the Utility will not recover through rates; forecasts of capital expenditures; estimates and assumptions used in critical accounting policies, including those relating to regulatory assets and liabilities, environmental remediation, litigation, third-party claims, and other liabilities; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “may,” “should,” “would,” “could,” “potential” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

Ÿ	~~the timing and outcomes of the final phase two CPUC decision in the 2015 GT&S rate case, the 2017 GRC, the TO rate cases, and other ratemaking and regulatory proceedings;~~
the impact of the Northern California wildfires, including the costs of restoration of service to customers and repairs to the Utility’s facilities, and whether the Utility is able to recover such costs through CEMA; the timing and outcome of the investigations by Cal Fire and the CPUC, including into the causes of the wildfires; and whether the Utility may have liability associated with these fires; and, if liable for one or more fires, whether the Utility would be able to recover all or part of such costs through insurance or through regulatory mechanisms, to the extent insurance is not available or exhausted; as well as potential liabilities in connection with fines or penalties that could be imposed on the Utility if the CPUC or any other law enforcement agency brought an enforcement action and determined that the Utility failed to comply with applicable laws and regulations;
Ÿ	the timing and outcomes of the debarment proceeding and potential remedial and other measures that may be imposed on the Utility as a result of the debarment proceeding and the jury’s verdict in the federal criminal trial of the Utility (including a potential appointment of one or more independent third-party monitor(s)), the Utility’s motion for judgment of acquittal, the SED’s unresolved enforcement matters relating to the Utility’s compliance with natural gas-related laws and regulations, and other investigations that have been or may be commenced relating to the Utility’s compliance with natural gas-related laws and regulations, including the U.S. Attorney’s Office investigation in connection with the natural gas explosion that occurred in Carmel, California on March 3, 2014 and the U.S. Attorney’s Office in San Francisco investigation in connection with matters relating to the federal criminal trial discussed above, and the ultimate amount of fines, penalties, and remedial costs that the Utility may incur in connection with the outcomes;

Ÿ	the timing and outcomes of the CPUC’s investigation of communications between the Utility and the CPUC that may have violated the CPUC’s rules regarding ex parte communications or are otherwise alleged to be improper, and of the U.S. Attorney’s Office in San Francisco and the California Attorney General’s office investigations in connection with communications between the Utility’s personnel and CPUC officials, whether additional criminal or regulatory investigations or enforcement actions are commenced with respect to allegedly improper communications, and the extent to which such matters negatively affect the final decisions to be issued in the Utility’s ratemaking proceedings;
Ÿ	the timing and outcomes of the Butte fire litigation, and whether the Utility’s insurance is sufficient to cover the Utility’s liability resulting therefrom or whether insurance is otherwise available; and whether additional investigations and proceedings in connection with the Butte fire will be opened;

Ÿ	whether PG&E Corporation and the Utility are able to repair the harm to their reputations caused by the jury’s verdict in the federal criminal trial and a possible conviction of the Utility, the state and federal investigations of natural gas incidents, matters relating to the criminal federal trial, improper communications between the CPUC and the Utility, and the Utility’s ongoing work to remove encroachments from transmission pipeline rights-of-way;

Ÿ	whether the Utility can control its costs within the authorized levels of spending, the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs, and changes in cost forecasts or the scope and timing of planned work resulting from changes in customer demand for electricity and natural gas or other reasons;

Ÿ	the amount and timing of additional common stock and debt issuances by PG&E Corporation, including the dilutive impact of common stock issuances to fund PG&E Corporation’s equity contributions to the Utility as the Utility incurs charges and costs, including fines, that it cannot recover through rates;

Ÿ	the outcome of the CPUC’s investigation into the Utility’s safety culture, and future legislative or regulatory actions that may be taken to require the Utility to separate its electric and natural gas businesses, restructure into separate entities, undertake some other corporate restructuring, or implement corporate governance changes;
Ÿ	the outcomes of the SED’s investigations of potential violations identified though audits, investigations, or self-reports, including in connection with the Utility’s September 2016 self-report related to atmospheric corrosion inspections; the Utility’s ability to efficiently manage capital expenditures and its operating and maintenance expenses within the authorized levels of spending and timely recover its costs through rates, and the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; the timing and outcomes of the TO18 and TO19 rate cases and other ratemaking and regulatory proceedings; the timing and outcome of the Butte fire litigation, the timing and outcome of any proceeding to recover costs in excess of insurance from customers, if any; the effect, if any, that the SED’s $8.3 million citations issued in connection with the Butte fire may have on Butte fire litigation; and whether additional investigations and proceedings in connection with the Butte fire will be opened and any additional fines or penalties imposed on the Utility; whether the CPUC approves the Utility’s application to establish a WEMA to track wildfire expenses and to preserve the opportunity for the Utility to request recovery of wildfire costs in excess of insurance at a future date, and the outcome of any potential request to recover such costs. While the CPUC previously approved WEMA tracking accounts for San Diego Gas & Electric Company in 2010, the CPUC currently is considering whether to approve recovery of costs recorded by San Diego Gas & Electric Company in its WEMA. On August 22, 2017, the CPUC issued a PD denying San Diego Gas & Electric Company’s cost recovery request; the outcome of the probation and the monitorship imposed as a result of the Utility’s conviction in the federal criminal trial, the timing and outcomes of the debarment proceeding, the SED’s unresolved enforcement matters relating to the Utility’s compliance with natural gas-related laws and regulations, and other investigations that have been or may be commenced relating to the Utility’s compliance with natural gas- and electric- related laws and regulations and ex parte communications, and the ultimate amount of fines, penalties, and remedial costs that the Utility may incur in connection with the outcomes; the timing and outcomes of the U.S. Attorney’s Office in San Francisco and the California Attorney General’s office investigations in connection with communications between the Utility’s personnel and CPUC officials, whether additional criminal or regulatory investigations or enforcement actions are commenced with respect to allegedly improper communications, and the extent to which such matters negatively affect the final decisions to be issued in the Utility’s ratemaking proceedings, and the timing and outcome of the federal investigation regarding possible criminal violations of the Migratory Bird Treaty Act and conspiracy to violate the act; 66 the effects on PG&E Corporation and the Utility’s reputations caused by the Utility’s conviction in the federal criminal trial, the state and federal investigations of natural gas incidents, matters relating to the criminal federal trial, improper communications between the CPUC and the Utility, and the Utility’s ongoing work to remove encroachments from transmission pipeline rights-of-way; whether the Utility can control its costs within the authorized levels of spending, and successfully implement a streamlined organizational structure and achieve project savings, the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs, and changes in cost forecasts or the scope and timing of planned work resulting from changes in customer demand for electricity and natural gas or other reasons; whether the Utility is able to successfully adapt its business model to significant change that the electric industry is undergoing and the impact such change will have on the natural gas industry; the impact of increased costs to comply with natural gas regulations, including the Senate Bill 887 directing DOGGR and CARB to develop permanent regulations for gas storage facility operations in California to comply with new safety and reliability measures, the PHMSA rules effective January 18, 2017 regulating gas storage facilities at the federal level; and the CPUC General Order 112-F that went into effect on January 1, 2017, that requires additional expenditures in the areas of gas leak repair, leak survey, high consequences area identification, and operator qualifications, and could impact the Utility’s ability to timely recover such costs; whether the Utility and its third-party vendors and contractors are able to protect the Utility’s operational networks and information technology systems from cyber- and physical attacks, or other internal or external hazards; the timing and outcome of the complaint filed by the CPUC and certain other parties with the FERC on February 2, 2017 that requests that the Utility provide an open and transparent planning process for its capital transmission projects that do not go through the CAISO’s Transmission Planning Process in order to allow for participation and input from interested parties; the amount and timing of additional common stock and debt issuances by PG&E Corporation, including the dilutive impact of common stock issuances to fund PG&E Corporation’s equity contributions to the Utility as the Utility incurs charges and costs, including fines, that it cannot recover through rates; the outcome of the safety culture OII, including of its phase two proceeding opened on May 8, 2017 and future legislative or regulatory actions that may be taken to require the Utility to separate its electric and natural gas businesses, restructure into separate entities, undertake some other corporate restructuring, or implement corporate governance changes; the outcome of current and future self-reports, investigations or other enforcement proceedings that could be commenced or notices of violation that could be issued relating to the Utility’s compliance with laws, rules, regulations, or orders applicable to its operations, including the construction, expansion or replacement of its electric and gas facilities, electric grid reliability, inspection and maintenance practices, customer billing and privacy, physical and cyber security, environmental laws and regulations; and the timing and outcome of notices of violations in connection with the Yuba City incident; the outcomes of the CPUC’s data requests, including in connection with the Utility’s SmartMeter™ cost-benefit analysis, and of the Utility’s PFMs, including in connection with the installation of new CP systems in 2018; the timing and outcomes of the “Ghost Ship” and Valero refinery outage lawsuits; the impact of environmental remediation laws, regulations, and orders; the ultimate amount of costs incurred to discharge the Utility’s known and unknown remediation obligations; and the extent to which the Utility is able to recover environmental costs in rates or from other sources; the ultimate amount of unrecoverable environmental costs the Utility incurs associated with the Utility’s natural gas compressor station site located near Hinkley, California;

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

Ÿ	the impact of environmental remediation laws, regulations, and orders; the ultimate amount of costs incurred to discharge the Utility’s known and unknown remediation obligations; and the extent to which the Utility is able to recover environmental costs in rates or from other sources;

Ÿ	~~the ultimate amount of unrecoverable environmental costs the Utility incurs associated with the Utility’s natural gas compressor station site located near Hinkley, California;~~

Ÿ	the impact of new legislation or NRC regulations, recommendations, policies, decisions, or orders relating to the nuclear industry, including operations, seismic design, security, safety, relicensing, the storage of spent nuclear fuel, decommissioning, cooling water intake, or other issues; the impact of actions taken by state agencies that may affect the Utility’s ability to continue operating Diablo Canyon; whether the CPUC approves the joint proposal that will phase out the Utility’s Diablo Canyon nuclear units at the expiration of their licenses in 2024 and 2025; whether the Utility obtains the approvals required to withdraw its NRC application to renew the two Diablo Canyon operating licenses; whether the State Lands Commission could be required to perform an environmental review of the new lands lease as a result of the WBA assertion that the State Lands Commission committed legal error when it determined that the short term lease extension for an existing facility was exempt from review under the California Environmental Quality Act; and whether the Utility will be able to successfully implement its retention and retraining and development programs for Diablo Canyon employees, and whether these programs will be recovered in rates;
Ÿ	whether the Utility is successful in ensuring physical security of its critical assets and whether the Utility’s information technology, operating systems and networks, including the advanced metering system infrastructure, customer billing, financial, records management, and other systems, can continue to function accurately while meeting regulatory requirements; whether the Utility and its third party vendors and contractors (who host, maintain, modify and update some of the Utility’s systems) are able to protect the Utility’s operating systems and networks from damage, disruption, or failure caused by cyber-attacks, computer viruses, or other hazards; whether the Utility’s security measures are sufficient to protect against unauthorized or inadvertent disclosure of information contained in such systems and networks, including confidential proprietary information and the personal information of customers; and whether the Utility can continue to rely on third-party vendors and contractors that maintain and support some of the Utility’s information technology and operating systems;
Ÿ	the impact of droughts or other weather-related conditions or events, wildfires (such as the Butte fire), climate change, natural disasters, acts of terrorism, war, vandalism (including cyber-attacks), and other events, that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies; whether the Utility incurs liability to third parties for property damage or personal injury caused by such events; whether the Utility is subject to civil, criminal, or regulatory penalties in connection with such events; and whether the Utility’s insurance coverage is available for these types of claims and sufficient to cover the Utility’s liability;

Ÿ	how the CPUC and the CARB implement state environmental laws relating to GHG, renewable energy targets, energy efficiency standards, DERs, electric vehicles, and similar matters, including whether the Utility is able to continue recovering associated compliance costs, such as the cost of emission allowances and offsets under cap-and-trade regulations; and whether the Utility is able to timely recover its associated investment costs;

Ÿ	~~whether the Utility’s climate change adaptation strategies are successful;~~

Ÿ	the impact that reductions in customer demand for electricity and natural gas have on the Utility’s ability to make and recover its investments through rates and earn its authorized return on equity, and whether the Utility is successful in addressing the impact of growing distributed and renewable generation resources and changing customer demand for natural gas and electric services;

the impact of new legislation or NRC regulations, recommendations, policies, decisions, or orders relating to the nuclear industry, including operations, seismic design, security, safety, relicensing, the storage of spent nuclear fuel, decommissioning, cooling water intake, or other issues; the impact of actions taken by state agencies that may affect the Utility’s ability to continue operating Diablo Canyon; whether the CPUC approves the joint proposal that will phase out the Utility’s Diablo Canyon nuclear units at the expiration of their licenses in 2024 and 2025; and whether the Utility will be able to successfully implement its retention and retraining and development programs for Diablo Canyon employees, and whether these programs will be recovered in rates;

the impact of wildfires, droughts, floods, or other weather-related conditions or events, climate change, natural disasters, acts of terrorism, war, vandalism (including cyber-attacks), downed power lines, and other events, that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies, and the reparation and other costs that the Utility may incur in connection with such conditions or events; the impact of the potential inadequacy of the Utility’s emergency preparedness; whether the Utility incurs liability to third parties for property damage or personal injury caused by such events; whether the Utility is subject to civil, criminal, or regulatory penalties in connection with such events; and whether the Utility’s insurance coverage is available for these types of claims and sufficient to cover the Utility’s liability;

the breakdown or failure of equipment that can cause fires and unplanned outages (such as the power outage on April 21, 2017 in San Francisco, that initial information suggests was due to an equipment failure that led to a fire at Larkin Street substation, and that impacted approximately 88,000 customers); and whether the Utility will be subject to investigations, penalties, and other costs in connection with such events;

how the CPUC and the CARB implement state environmental laws relating to GHG, renewable energy targets, energy efficiency standards, DERs, EVs, and similar matters, including whether the Utility is able to continue recovering associated compliance costs, such as the cost of emission allowances and offsets under cap-and-trade regulations; and whether the Utility is able to timely recover its associated investment costs;

whether the Utility’s climate change adaptation strategies are successful;

the impact that reductions in customer demand for electricity and natural gas have on the Utility’s ability to make and recover its investments through rates and earn its authorized return on equity, and whether the Utility is successful in addressing the impact of growing distributed and renewable generation resources, changing customer demand for natural gas and electric services, and an increasing number of customers departing PG&E’s procurement service for CCAs;

the supply and price of electricity, natural gas, and nuclear fuel; the extent to which the Utility can manage and respond to the volatility of energy commodity prices; the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and whether the Utility is able to recover timely its electric generation and energy commodity costs through rates, including its renewable energy procurement costs;

whether, as a result of Westinghouse’s Chapter 11 proceeding, the Utility will experience issues with nuclear fuel supply, nuclear fuel inventory, and related services and products that Westinghouse supplies, and whether such proceeding will affect the Utility’s contracts with Westinghouse;

the amount and timing of charges reflecting probable liabilities for third-party claims; the extent to which costs incurred in connection with third-party claims or litigation can be recovered through insurance, rates, or from other third parties; and whether the Utility can continue to obtain adequate insurance coverage for future losses or claims, especially following a major event that causes widespread third-party losses;

the ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing in a timely manner on acceptable terms;

changes in credit ratings which could result in increased borrowing costs especially if PG&E Corporation or the Utility were to lose their investment grade credit ratings;

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	the supply and price of electricity, natural gas, and nuclear fuel; the extent to which the Utility can manage and respond to the volatility of energy commodity prices; the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and whether the Utility is able to recover timely its electric generation and energy commodity costs through rates, including its renewable energy procurement costs;

Ÿ	the amount and timing of charges reflecting probable liabilities for third-party claims; the extent to which costs incurred in connection with third-party claims or litigation can be recovered through insurance, rates, or from other third parties; and whether the Utility can continue to obtain adequate insurance coverage for future losses or claims, especially following a major event that causes widespread third-party losses;

Ÿ	~~the ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing in a timely manner on acceptable terms;~~

Ÿ	~~changes in credit ratings which could result in increased borrowing costs especially if PG&E Corporation or the Utility were to lose its investment grade credit ratings;~~

Ÿ	the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies, including how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company, and whether the ultimate outcomes of the CPUC’s pending investigations, the jury’s verdict in the federal criminal trial of the Utility and its possible conviction, and other enforcement matters affect the Utility’s ability to make distributions to PG&E Corporation, and, in turn, PG&E Corporation’s ability to pay dividends;

Ÿ	~~the outcome of federal or state tax audits and the impact of any changes in federal or state tax laws, policies, regulations, or their interpretation; and~~

Ÿ	~~the impact of changes in GAAP, standards, rules, or policies, including those related to regulatory accounting, and the impact of changes in their interpretation or application.~~

~~For more information about~~ the ~~significant risks that could affect~~impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies, including how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company, and whether the ultimate outcomes of the CPUC’s pending investigations, the Utility’s conviction in the federal criminal trial, and other enforcement matters will impact the Utility’s ability to make distributions to PG&E Corporation, and, in turn, PG&E Corporation’s ability to pay dividends;

the impact of the corporate tax reform considered by the new federal administration and the outcome of ~~these forward-looking statements and PG&E Corporation’s~~federal or state tax audits and the ~~Utility’s future financial condition, results~~impact of ~~operations, and cash flows, see “Risk Factors”~~any changes in federal or state tax laws, policies, regulations, or their interpretation;

changes in the ~~2015 Form 10-K~~regulatory and economic environment, including potential changes affecting renewable energy sources and associated tax credits, as a result of the new federal administration; and

the impact of changes in ~~“ Item.~~GAAP, standards, rules, or policies, including those related to regulatory accounting, and the impact of changes in their interpretation or application.

Additional information about risks and uncertainties, including more detail about the factors described in this report, is included throughout MD&A, in “Item 1A. Risk Factors” ~~below.~~below, and in the 2016 Form 10-K, including the “Risk Factors” section. Forward-looking statements speak only as of the date they are made. PG&E Corporation and the Utility do not undertake any obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

Additionally, PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. It is possible that these regulatory filings or information included therein could be deemed to be material information. The information contained on this website is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC. PG&E Corporation and the Utility are providing the address to this website solely for the information of investors and do not intend the address to be an active link. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “News & Events: Events & Presentations” tab, in order to publicly disseminate such information.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PG&E Corporation’s and the Utility’s primary market risk results from changes in energy commodity prices. PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates. (See the section above entitled “Risk Management Activities” in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.)

ITEM 4. CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of September 30, ~~2016,~~ 2017, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures ~~were~~are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC rules and ~~forms. In addition, PG&E Corporation’s~~forms, and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the Securities Exchange Act of 1934 is(ii) accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal control over financial reporting that occurred during the quarter ended September 30, ~~2016,~~2017, that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In addition to the following legal proceedings, PG&E Corporation and the Utility are involved in various legal proceedings in the ordinary course of their business. For more information regarding PG&E Corporation’s and the Utility’s contingencies, see Note 9 of the Notes to the Condensed Consolidated Financial ~~Statement~~Statements and Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Enforcement and Litigation Matters.”

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

For a description of this matter, see “Part I, Item 3. Legal Proceedings” in the 2015 Form 10-K, the discussion of the Penalty Decision in Note 13 of the Notes to the Consolidated Financial Statements inthe 2015 Form 10-K, and the discussion included in Note 9 of the Notes to the Condensed Consolidated Financial Statements.

~~Federal Criminal Trial~~

On June 14, 2016, a federal criminal trial against the Utility began in the United States District Court for the Northern District of California, in San Francisco, on 12 felony counts alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record-keeping, pipeline integrity management, and identification of pipeline threats, and one felony count charging that the Utility illegally obstructed the NTSB investigation into the cause of the San Bruno accident. On July 26, 2016, the court granted the government’s motion to dismiss Count 13 alleging that the Utility knowingly and willfully failed to retain a strength test pressure record with respect to a distribution feeder main, thereby reducing the total number of counts from 13 to 12.

On August 16, 2016, the Utility filed a motion under Federal Rule of Criminal Procedure 29 for a judgment of acquittal, arguing that the evidence was insufficient to sustain a conviction for the six counts on which the jury returned a guilty verdict. The court indicated that it will decide on this motion based on briefs filed by the parties, without oral argument. The Utility is not able to predict when the court will decide on the motion. A sentencing hearing is currently scheduled for January 23, 2017.

For description of this matter, see “Part I, Item 3. Legal Proceedings” in the 2015 Form 10-K, the section entitled “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8 in the 2015 Form 10-K, and the section entitled “Enforcement and Litigation Matters” in Note 9 of the Notes to the Condensed Consolidated Financial Statements.

~~Litigation Related to the San Bruno Accident and Natural Gas Spending~~

As of September 30, 2016, there were seven purported derivative lawsuits seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims.

~~Four of the complaints were consolidated as the~~ ~~San Bruno Fire Derivative Cases~~ ~~and are pending in the Superior Court of California, County of San Mateo. The remaining three cases are~~ ~~Tellardin v. PG&E Corp. et al.,Iron Workers Mid-South Pension Fund v. Johns, et al.,~~ ~~and~~ ~~Bushkin v. Rambo et al~~.

~~On December 8, 2015, the California Court of Appeal issued a writ of mandate to the Superior Court of California, San Mateo County, ordering the court to stay all proceedings in the four consolidated~~ ~~San Bruno Fire Derivative Cases~~ pending conclusion of the federal criminal proceedings against the Utility. On September 16, 2016, the San Mateo Superior Court requested that all counsel appear for a status conference in the consolidated matter. The date of the conference has been set for November 16, 2016.

~~PG&E Corporation and the Utility are uncertain when and how the above lawsuits will be resolved.~~

For additional information regarding these matters, see the discussion entitled “Enforcement and Litigation Matters” above in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations. In addition, see “Part I, Item 3. Legal Proceedings” in the 2015 Form 10-K.

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, ~~and~~ destroyed 549 homes, 368 outbuildings and four commercial ~~properties.~~properties, and damaged 44 structures. Cal Fire’s report concluded that the wildfire was caused when a ~~Gray Pine~~gray pine tree contacted the Utility’s electric line which ignited portions of the tree, and determined that the failure by the Utility ~~and~~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 a press release also issued on April 28, 2016, Cal Fire indicated that it will seek to recover firefighting costs in excess of $90 million from the Utility.~~

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 September 30, ~~2016, approximately 50~~2017, 77 known 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~~Amador. The complaints involve approximately ~~1,850~~3,770 individual plaintiffs representing approximately ~~800~~2,080 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. Plaintiffs also seek punitive damages. The number of individual complaints and plaintiffs may increase in the future.

The Utility continues mediating and settling cases

In the third quarter of 2017, the Utility reached settlements with plaintiffs in the “preference” trial involving six households and with the plaintiffs in the representative trial that had been scheduled for August 2017 and October 2017, respectively. While there are no trials related to the Butte fire currently scheduled, one plaintiff has moved for a preference ~~cases (presented~~trial involving one household. The motion is set for hearing on December 1, 2017.

On October 25, 2017, the Utility filed a motion to stay the trial court proceedings pending a decision by ~~individuals who due to their age and/or physical condition are not likely to meaningfully participate in a trial under normal scheduling). The Utility also has begun scheduling mediation~~the Court of ~~other cases. Case management conferences were held~~Appeals on ~~July 14, 2016 and September 1, 2016. The next case management conference~~the pending writ of mandate regarding punitive damages. A hearing on the stay motion is ~~scheduled~~calendared for December 1, ~~2016.~~

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 it was not negligent; however, there can be no assurance that a court or a jury would agree with the Utility.2017.

For more information regarding the Butte fire, see Note 9 ~~“Contingencies~~of the Notes to the Condensed Consolidated Financial Statements.

San Bruno Derivative Litigation

As previously disclosed, on July 18, 2017, the Superior Court of California, County of San Mateo (the “Court”) approved the settlement agreement reached by the parties in the San Bruno Fire Derivative Cases to resolve the consolidated shareholder derivative lawsuit and ~~Commitments”~~certain additional claims against certain current and former officers and directors (the “Individual Defendants”). Also, as of July 19, 2017, the three cases, 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”) were dismissed. The settlement will become effective when all procedural conditions specified in the settlement stipulation are satisfied. PG&E Corporation recorded $65 million in proceeds from insurance, net of plaintiff costs to its Condensed Consolidated Income Statement for the three and nine months ended September 30, 2017.

For additional information regarding these matters, see “Part I, Item 3. Legal Proceedings” in the 2016 Form 10-K and subsequent quarterly reports on Form 10-Q and Note 9 of the Notes to the Condensed Consolidated Financial Statements.

Other Enforcement Matters

Fines may be imposed, or other regulatory or governmental enforcement action could be taken, with respect to the Utility’s self-reports of ~~noncompliance~~non-compliance with electric and natural gas safety regulations ~~prohibited ex parte communications between the Utility and CPUC personnel, investigations that were commenced after a pipeline explosion in Carmel, California on March 3, 2014,~~ and other enforcement matters. See the discussion entitled “Enforcement and Litigation Matters” above in Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 9 of the Notes to the Condensed Consolidated Financial Statements. In addition, see “Part I, Item 3. Legal Proceedings” in the ~~2015~~2016 Form 10-K.

Diablo Canyon Nuclear Power Plant

On June 20, 2016, the Utility entered into a joint proposal with certain parties to retire Diablo Canyon at the expiration of its current operating licenses in 2024 and 2025 and replace it with a GHG-free portfolio of energy efficiency, renewables and energy storage. The Utility expects that its decision to retire Diablo Canyon will affect the terms of the final settlement agreementbetween the Utility, the Central Coast Water Board and the California Attorney General’s Office. Also, as required under the California State Water Resources Control Board’s Once-Through Cooling Water Policy, beginning in 2016, the Utility will pay an annual interim mitigation fee until operations cease at the end of the current licenses.

~~PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material impact on the Utility’s financial condition or results of operations.~~

For more information regarding the 2003 settlement agreement between the Central Coast Regional Water Quality Control Board, the Utility, and the California Attorney General’s Office, see “Part I, Item 3. Legal Proceedings” in the ~~2015~~2016 Form 10-K.

~~Venting Incidents in San Benito County~~

As part of its regular maintenance and inspection practices for its natural gas transmission system, the Utility performs in-line inspections of pipelines using devices called “pigs” that travel through the pipeline to inspect and clean the walls of the pipe. When in-line inspections are performed, natural gas in the pipeline must be released or vented at the pipeline station where the device is removed. In February 2014, the Utility conducted an in-line inspection of a natural gas transmission pipeline that traverses San Benito County and vented the natural gas at the Utility’s transmission station located in Hollister, which is next to an elementary school. The Utility vented the natural gas during school hours on three occasions that month. After being informed of the venting by the local air district, the San Benito County District Attorney notified the Utility in December 2014 that it was contemplating bringing a civil legal action against the Utility for violation of Health and Safety Code section 41700, which prohibits discharges of air contaminants that cause a public nuisance. On October 28, 2015, the district attorney informed the Utility that it would seek civil penalties in excess of $100,000 but is willing to continue to explore settlement options with the Utility. The Utility remains in settlement discussions with the district attorney’s office.

~~For more information, see “Part I, Item 3. Legal Proceedings” in the 2015 Form 10-K.~~

~~Transformer Oil Release in Sonoma County~~

During a rain storm in February 2015, transformer oil was released into an underground vault in the City of Santa Rosa, in Sonoma County, while a Utility crew was replacing a broken transformer. Following further rains, the oil released from the vault and reached a nearby creek. The event was investigated by Santa Rosa Fire Department, the local environmental enforcement authority, and later referred to the Sonoma County District Attorney’s Office. In May 2016, the District Attorney informed the Utility that it would seek penalties and costs in excess of $100,000 for alleged violations of several sections of the California Health and Safety and California Government codes which prohibit unauthorized spills or releases of oil into waters of the state and require that releases be reported to the Office of Emergency Services. The Utility is in the process of settlement negotiations with the Sonoma County District Attorney’s Office.

ITEM 1A. RISK FACTORS

For information about the significant risks that could affect PG&E Corporation’s and the Utility’s ~~future~~ financial condition, results of operations, liquidity, and cash flows, see the section of the ~~2015~~2016 Form 10-K entitled “Risk Factors,” as supplemented below, and the section of this quarterly report entitled ~~“Forward-Looking~~“Cautionary Language Forward-Looking Statements.”

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially adversely affected by potential losses resulting from the impact of the Northern California wildfires. The Utility also could be the subject of lawsuits, additional investigations, citations, fines or enforcement actions.

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially adversely affected by potential losses resulting from the impact of the Northern California wildfires. The Utility estimates that it will incur costs in the range of $160 million to $200 million for service restoration and repairs to the Utility’s facilities (including an estimated $60 million to $80 million in capital expenditures) in connection with these fires. While the Utility believes that such costs are recoverable through CEMA, its CEMA requests are subject to CPUC approval. The Utility’s financial condition, results of operations, liquidity, and cash flows could be materially adversely affected if the Utility were unable to recover such costs.

As of October 31, 2017, the Utility is aware of nine lawsuits, one of which seeks to be designated as a class action, that have been filed against PG&E Corporation and the Utility in Sonoma, Napa and San Francisco Counties’ Superior Courts. The lawsuits allege, among other things, negligence, inverse condemnation, trespass, and private nuisance. They principally assert that PG&E Corporation and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the cause of the fires. The plaintiffs seek damages that include personal injury, property damage, evacuation costs, medical expenses, and other damages. PG&E Corporation and the Utility may ~~incur~~be subject of additional lawsuits in connection with the Northern California wildfires.

The Utility has approximately $800 million in liability insurance for potential losses that may result from these fires. If the Utility were held liable for one or more fires and the Utility’s insurance were insufficient to cover that liability or the Utility were unable to recover costs in excess of insurance through regulatory mechanisms, either of which could take a number of years to resolve, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, could be materially adversely affected. If the Utility were to determine that it is both probable that a material loss has occurred and the amount of loss can be reasonably estimated, a liability would be recorded consistent with the principles discussed in ~~connection~~Note 9 in the Notes to the Condensed Consolidated Financial Statements. To the extent not offset by insurance recoveries determined to be similarly probable and estimable, the liability would affect the balance sheet equity of PG&E Corporation and the Utility, which could adversely impact PG&E Corporation’s and the Utility’s credit ratings and their ability to declare and pay dividends, efficiently raise capital, comply with financial covenants, and meet financial obligations. (See “Risks Related to Liquidity and Capital Requirements” in the 2016 Form 10-K.)

Uncertainties relating to and market perception of these matters, and the disclosure of findings regarding these matters over time, also could lead to volatility in the market for PG&E Corporation’s common stock and other securities, and for the securities of the Utility, and could materially affect the price of such securities.

For additional information about risks that PG&E Corporation and the Utility face with respect to wildfires, see “The Utility’s electricity and natural gas operations are inherently hazardous and involve significant risks which, if they materialize, can adversely affect PG&E Corporation’s and the Utility’s financial results. The Utility’s insurance may not be sufficient to cover losses caused by an operating failure or catastrophic event, or may not become available at a reasonable cost, or available at all” in Item 1A. Risk Factors of the 2016 Form 10-K.

PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially affected by the ultimate amount of third-party liability that the Utility incurs in connections with the Butte fire.

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 the Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, and destroyed 549 homes, 368 outbuildings and four commercial properties.~~ Cal Fire’s report concluded that the wildfire was caused when a ~~Gray Pine~~gray pine tree contacted the Utility’s electric line which ignited portions of the tree, and determined that the failure by the Utility ~~and~~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 a press release also issued on April 28, 2016, Cal Fire indicated that it will seek to recover firefighting costs in excess of $90 million from the Utility.~~

On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its 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 September 30, ~~2016, approximately 50~~2017, 77 known 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~~Amador. The complaints involve approximately ~~1,850~~3,770 individual plaintiffs representing approximately ~~800~~2,080 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. Plaintiffs also seek punitive damages. The number of individual complaints and plaintiffs may increase in the future. The Utility continues mediating and settling cases.

In addition, on April 13, 2017, Cal Fire filed a complaint with the Superior Court of the State of California, County of Calaveras, seeking to recover $87 million for its costs incurred on the theory that the Utility and its vegetation management contractors were negligent, among other claims. Also, in May 2017, the OES indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $190 million. This claim would include costs incurred by the OES for tree and debris removal, infrastructure damage, erosion control, and other claims related to the Butte fire. Also, in June 2017, the County of Calaveras indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $85 million. This claim would include costs that the County of Calaveras incurred or expects to incur for infrastructure damage, erosion control, and other costs related to the Butte fire.

The Utility currently believes that it is probable that it will incur a loss of at least $1.1 billion, increased from the $750 million previously estimated as of December 31, 2016, 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.~~Butte fire. In addition, while this amount includes the ~~Utility may be liable for~~Utility’s early assumptions about fire suppression costs ~~personal injury damages,~~(including its assessment of the Cal Fire loss), it does not include any significant portion of the estimated claims from the OES and ~~other damages if~~ the County of Calaveras. The Utility ~~were found~~still does not have sufficient information to reasonably estimate any liability it may have ~~been negligent.~~for these additional claims.

The process for estimating costs associated with claims relating to the Butte fire ~~including for estimated property damages,~~ requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including ~~discoveries~~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 change. A change in management’s estimates or assumptions could result in an adjustment that could have a material impact on PG&E Corporation’s and the Utility’s financial condition and the results of operations during the period such change occurred.

IfThrough September 30, 2017, the ~~Utility records losses~~amounts accrued 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~~have exceeded 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 collectliability insurance ~~recoveries in amounts sufficient to offset such additional accruals during such reporting periods.~~

PG&E Corporation’s and the Utility’s future financial results could be materially affected by the jury’s verdict in the federal criminal trial and possible judgment of conviction of the Utility, the debarment proceeding and an increased number of government investigations and requests for information.

As previously disclosed, on August 9, 2016, the jury returned its verdict in the federal criminal trial against the Utility on 11 felony counts alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record-keeping, pipeline integrity management, and identification of pipeline threats, and one felony count charging that the Utility illegally obstructed the NTSB investigation into the cause of the San Bruno accident. The jury acquitted the Utility on all six of the record-keeping allegations but found the Utility guilty on six felony counts that include obstructing a federal agency proceeding and violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act. On August 16, 2016,coverage. While the Utility filed an application with the CPUC requesting approval to establish a ~~motion under Federal Criminal Procedure 29 for a judgment of acquittal, arguing that~~WEMA to track wildfire expenses and to preserve the ~~evidence was insufficient to sustain a conviction~~opportunity for the ~~six counts on which the jury returned a guilty verdict.~~

~~In September 2015,~~Utility to request recovery of wildfire costs that have not otherwise been recovered through in insurance or other mechanisms, the Utility was notified that the DOI had initiated an inquiry into whether the Utility should be suspended or debarred from entering into federal procurement and non-procurement contracts and programs citing the SanBruno explosion and indicating, as the basis for the inquiry, alleged poor record-keeping, poor identification and evaluation of threats to gas lines and obstruction of the NTSB’s investigation.

As a result of the August 9, 2016 jury’s verdict in the federal criminal trial, the Utility updated its registration on the federal government’s System for Award Management (SAM), a federal procurement database, to reflect the verdict. Under federal law, the government may not enter into a contract with any corporation that was convicted of a felony criminal violation under any federal law within the preceding 24 months, where the awarding agency is aware of the conviction, unless an agency has considered suspension or debarment of the corporation and made a determination that this action is not necessary to protect the interests of the government. Following the update of the SAM, the Utility and the DOI have been in discussions regarding such a determination and regarding a possible interim administrative agreement that would allow the federal government agencies to contract with the Utility while the DOI is completing its debarment inquiry. It is uncertain when and if the Utility and the DOI will enter into an interim administrative agreement. It is also uncertain when or if further action will be taken by the DOI. The DOI debarment inquiry could result in the Utility’s suspension or debarment from future federal government contracts for a fixed, specified time period or entering into an administrative agreement with the DOI to resolve debarment matters.

The jury’s verdict, a possible judgment of conviction of the Utility and the outcome of the debarment proceeding could harm the Utility’s relationships with regulators, legislators, communities, business partners, or other constituencies and make it more difficult to recruit qualified personnel and senior management. Further, they could negatively affect the outcome of future ratemaking and regulatory proceedings, for example by, enabling parties to argue that the Utility should not be allowed to recover costs that the parties allege are somehow related to the criminal charges on which the Utility was found guilty. They could also result in increased regulatory or legislative scrutiny with respect to various aspects of how the Utility’s business is conducted or organized. As discussed under the heading “Regulatory Matters” in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, the SED continues evaluating PG&E Corporation’s and the Utility’s organizational culture and governance in the CPUC’s pending investigation to examine the Utility’s safety culture. The Utility also could incur material costs, not recoverable through rates, to implement remedial and other measures that could be imposed.

The Utility is also a target of an increased number of investigations and government requests for information. As previously disclosed, the U.S. Attorney’s Office is investigating a natural gas explosion that occurred in Carmel, California on March 3, 2014. The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the criminal trial discussed above. The U.S. Attorney’s Office in San Francisco and the California Attorney General’s office also are investigating matters related to allegedly improper communication between the Utility and CPUC personnel. 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 Utility was also recently contacted by certain other federal agencies with requests for information. While the Utility believes that these requests for information are routine, theiroutcome is uncertain. The Utility also is unable tocannot predict the outcome of ~~pending investigations, including whether any charges will be brought against the Utility.~~ Any charges that could be brought against the Utility or proceedings that could result from the current and future government investigations and requests for information could result in material costs to PG&E Corporation and the Utility.

The Utility’s conviction, the outcome of the debarment proceeding and any proceedings that could result from the current and future government investigations and requests for information could harm its relationships with regulators, legislators, communities, business partners, or other constituencies and make it more difficult to recruit qualified personnel and senior management. Further, they could negatively affect the outcome of future ratemaking and regulatory proceedings, for example, by enabling parties to argue that the Utility should not be allowed to recover costs that the parties allege are somehow related to the criminal charges on which the Utility was found guilty.

They could also result in increased regulatory or legislative scrutiny with respect to various aspects of how the Utility’s business is conducted or organized. As discussed under the heading “Regulatory Matters” in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, the SED continues evaluating PG&E Corporation’s and the Utility’s organizational structure in the CPUC’s pending investigation to examine the Utility’s safety culture.

~~The Utility’s insurance may not be sufficient to cover losses caused by an operating failure or catastrophic event, or may not become available at a reasonable cost, or available at all.~~

The Utility’s ability to safely and reliably operate, maintain, construct and decommission its facilities is subject to numerous risks, many of which are beyond the Utility’s control. (See “Risks Related to Operations and Information Technology” in Item 1A Risk Factors of the 2015 Form 10-K.) Current insurance, equipment warranties, or other contractual indemnification requirements may not be sufficient or effective to provide full or even partial recovery under all circumstances or against all hazards or liabilities to which the Utility may become subject. (In particular, the Utility may incur material liability in connection with the Butte fire. See “PG&E Corporation and the Utility may incur material liability in connection with the Butte fire” above.)

In addition, California law includes a doctrine of inverse condemnation that is routinely invoked in California for wildfire damages. Inverse condemnation imposes strict liability (including liability for attorneys' fees) for damages and takings as a result of the design, construction and maintenance of utility facilities, including its electric transmission lines. As a result of the strict liability standard applied to wildfires, recent losses recorded by insurance companies, the risk of increase of wildfires including as a result of the ongoing drought, and the Butte fire, the Utility may not be able to obtain sufficient insurance coverage in the future at comparable cost and terms as the Utility’s current insurance coverage, or at all. In addition, the Utility is unable to predict whether it would be allowed to recover in rates the increased costs of insurance or the costs of any uninsured losses.

this proceeding. If ~~the amount of insurance is insufficient or otherwise unavailable, or if~~ the Utility is unable to recover ~~in rates the~~all or a significant portion of such excess costs, ~~of any uninsured losses,~~ PG&E Corporation’s and the Utility’s financial condition, results of operations, or cash flows could be materially affected.

The electric power industry is undergoing significant change driven by technological advancements and a decarbonized economy, which could materially impact the Utility’s operations, financial condition, and results of operations.

The electric power industry is undergoing a transformative change driven by technological advancements enabling customer choice (for example, customer-owned generation and energy storage) and state climate policy supporting a decarbonized economy. California's environmental policy objectives are accelerating the pace and scope of the industry change. The electric grid is a critical enabler of the adoption of new energy technologies that support California's climate change and GHG reduction objectives, which continue to be publicly supported by California policy makers notwithstanding a recent change in the federal approach to such matters. California utilities are experiencing increasing deployment by customers and third parties of DERs, such as on-site solar generation, energy storage, fuel cells, energy efficiency, and demand response technologies. This growth will require modernization of the electric distribution grid to, among other things, accommodate two-way flows of electricity, increase the grid's capacity, and interconnect DERs.

In order to enable the California clean energy economy, sustained investments are required in grid modernization, renewable integration projects, energy efficiency programs, energy storage options, EV infrastructure and State infrastructure modernization (e.g. rail and water projects).

To this end, the CPUC is conducting proceedings to: evaluate changes to the planning and operation of the electric distribution grid in order to prepare for higher penetration of DERs; consider future grid modernization and grid reinforcement investments; evaluate if traditional grid investments can be deferred by DERs, and if feasible, what, if any, compensation to utilities would be appropriate for enabling those investments; and clarify the role of the electric distribution grid operator. The CPUC has also recently opened proceedings regarding the creation of a shared database or statewide census of utility poles and conduits in California and increased access by communications providers to utility rights-of-way. This proceeding could require utilities to invest significant resources into inspecting poles and conduits, limit available capacity in existing rights-of-way, or impose other requirements on utilities facilities. The Utility is unable to predict the outcome of these proceedings.

In addition, the CPUC has recently opened discussions on potential changes to California’s electricity market. On May 19, 2017, California energy companies, along with other stakeholders discussed customer choice and the future of the state’s electricity industry at a CPUC “en banc” meeting. Specifically, the goal of the “en banc” was to frame a discussion on the trends that are driving change within California’s electricity sector and overall clean-energy economy and to lay out elements of a path forward to ensure that California achieves its reliability, affordability, equity, and carbon reduction imperatives while recognizing the important role that technology and customer preferences will play in shaping this future. While the CPUC had indicated intent to open an OIR related to customer choice, the Utility is unable to predict if and when the CPUC may open an OIR.

The industry change, costs associated with complying with new regulatory developments and initiatives and with technological advancements, or the Utility’s inability to successfully adapt to changes in the electric industry, could materially affect the Utility’s operations, financial condition, and results of operations.

State climate policy requires reductions in greenhouse gases of 40% by 2030 and 80% by 2050. Various proposals for addressing these reductions have the potential to reduce natural gas usage and increase natural gas costs. The future recovery of the increased costs associated with compliance is uncertain.

The CARB is the state’s primary regulator for GHG emission reduction programs. Natural gas providers have been subject to compliance with CARB’s Cap-and-Trade Program since 2015, and natural gas end-use customers have an increasing exposure to carbon costs under the Program through 2030 when the full cost will be reflected in customer bills. CARB’s Scoping Plan also proposes various methods of reducing GHG emissions from natural gas. These include more aggressive energy efficiency programs to reduce natural gas end use, increased renewable portfolio standards generation in the electric sector reducing noncore gas load, and replacement of natural gas appliances with electric appliances, leading to further reduced demand. These natural gas load reductions may be partially offset by CARB’s proposals to deploy natural gas to replace wood fuel in home heating and diesel in transportation applications. CARB also proposes a displacement of some conventional natural gas with above-market renewable natural gas. The combination of reduced load and increased costs could result in higher natural gas customer bills and a potential mandate to deliver renewable natural gas could lead to cost recovery risk.

A cyber incident, cyber security breach or physical attack on the Utility’s operational networks and information technology systems could ~~fail to function properly or be improperly accessed or damaged by third parties (including cyberand physical attacks) or damaged by severe weather, natural disasters, or other events. Any~~have a material effect on its business and results of ~~these events could disrupt the Utility’s operations and cause the Utility to incur unanticipated losses and expense or liability.~~operations.

Private and public entities, such as the NERC, and U.S. Government Departments, including the Departments of Defense, Homeland Security and Energy, and the White House, have noted that cyber-attacks targeting utility systems are increasing in sophistication, magnitude, and frequency. The ~~operation of the~~ Utility’s ~~extensive~~ electricity and natural gas systems ~~relies~~rely on ~~evolving~~a complex, interconnected network of generation, transmission, distribution, control, and ~~increasingly complex~~communication technologies, which can be damaged by natural events—such as severe weather or seismic events—and by malicious events, such as cyber and physical attacks. The Utility’s operational networks also may face new cyber security risks due to modernizing and ~~information technology systems~~interconnecting the existing infrastructure with new technologies and ~~network infrastructures that are interconnected with~~control systems. Any failure or decrease in the ~~systems and network infrastructure owned by third parties. All~~functionality of the Utility’s operational and technology systems and network infrastructure are vulnerable to disability or failures in the event of cyber and physical attacks. Cyberattacks are increasingly sophisticated and may include computer hacking, viruses, malware, social engineering, denial of service attacks, ransomware, destructive malware, or other means of disruption, destruction, or unauthorized access, acquisition or control. In addition, hardware, software, or applications the Utility develops or procures from third parties may contain defects in design or manufacture or other problems thatnetworks could unexpectedly compromise information security. Physical attacks may include acts of sabotage, acts of war, acts of terrorism, or other physical acts. The Utility’s operational and information technology systems and networks are deemed critical infrastructure, and any failure or decrease in their functionality could, among other things, cause harm to the public or employees, significantly disrupt operations,negatively impact the Utility’s ability to safely generate, transport, deliver and store energy and gas, or otherwise operate in the most safe and efficient manner or at all, ~~undermine the Utility’s performance of critical business functions,~~and damage the Utility’s assets or operations or those of third ~~parties,~~parties.

The Utility also relies on complex information technology systems that allow it to create, collect, use, disclose, store and lead to reputational harm. As a result, such events could subject the Utility to significant expenses, claims by customers or third parties, government inquiries, investigations, and regulatory actions that could result in fines and penalties, and loss of customers, any of which could have a material effect on PG&E Corporation’s andotherwise process sensitive information, including the Utility’s financial ~~condition and results of operations.~~

~~The Utility’s systems, including its financial~~ information, ~~operational systems, advanced metering,~~customer energy usage and billing ~~systems, require ongoing maintenance, modification,~~information, and ~~updating, which can be costly~~personal information regarding customers, employees and ~~increase~~their dependents, contractors, and other individuals. In addition, the ~~risk of errors and malfunction. The~~ Utility often relies on third-party vendors to host, maintain, modify, and update its systems and these third-party vendors could cease to exist,, fail to establish adequate processes to protect the Utility’s systems and information, or experience ~~internal or external~~ security incidents. Any incidents ~~disruptions or deficiencies in existing systems,~~ or disruptions ~~delays or deficiencies~~ in the ~~modification of existing systems or implementation of new~~Utility’s information technology systems could ~~result in increased costs, the inability~~impact our ability to track or collect revenues ~~or diversion of management’s~~ and ~~employees’ attention and resources, or negatively affect the Utility’s ability~~ to maintain effective internal controls over financial controls or timely file required regulatory reports. The Utility also could be subject to patent infringement claims arising from the use of third-party technology by the Utility or by a third-party vendor.reporting

In addition, the Utility’s information systems contain confidential information, including information about customers and employees. A data breach involving theft, improper disclosure, or other unauthorized access to or acquisition of confidential information could subject the Utility to penalties for violation of applicable privacy laws, claims by third parties, and enforcement actions by government agencies. It could also reduce the value of proprietary information, and harm the Utility’s reputation..

The Utility and its third party vendors have been subject to, and will likely continue to be subject to attempts to gain unauthorized access to the Utility’s information technology systems, or confidential data, or to disrupt the Utility’s operations. None of these attempts or breaches has individually or in the aggregate resulted in a security incident with a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations. Despite implementation of security and control measures, there can be no assurance that the Utility will be able to prevent the unauthorized access to its operational networks, information technology systems ~~infrastructure,~~ or data, or the disruption of its ~~operations, either~~operations. Such events could subject the Utility to significant expenses, claims by customers or third parties, government inquiries, investigations, and regulatory actions that could result in fines and penalties, and loss of customers, any of which could ~~materially affect~~have a material effect on PG&E Corporation’s and the Utility’s financial condition and results of operations.

~~While the~~The Utility maintains cyber liability insurance that covers certain damages caused by cyber ~~incidents,~~incidents. However, there is no guarantee that adequate insurance will continue to be available at rates the Utility believes are reasonable or that the costs of responding to and recovering from a cyber incident will be covered by insurance or recoverable in rates.

The ~~operation and decommissioning~~Utility purchases its nuclear fuel assemblies from a sole source, Westinghouse. If Westinghouse experiences business disruptions as a result of ~~the Utility’s nuclear power plants expose it to potentially significant liabilities and~~Chapter 11 proceedings, the Utility ~~may not be able to fully recover~~could experience disruptions in nuclear fuel supply, delays in connection with its ~~costs if regulatory requirements change or the plant ceases operations before the licenses expire.~~Diablo Canyon outages and refuelings, and rejection in bankruptcy of its contracts with Westinghouse.

The operation of the Utility’s nuclear generation facilities exposes it to potentially significant liabilities from environmental, health and financial risks, such as risks relating to the storage, handling and disposal of spentUtility purchases its nuclear fuel ~~and~~assemblies for Diablo Canyon from a sole source, Westinghouse. The Utility also stores nuclear fuel inventory at the ~~release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act. If~~Westinghouse fuel fabrication facility. In addition, Westinghouse provides the Utility incurs losses that are either not covered by insurance or exceed the amount of insurance available, such losses could have a material effect on PG&E Corporation’s and the Utility’s financial results. In addition, the Utility may be required under federal law to pay up to $255 million of liabilities arising out of each nuclear incident occurring not only at the Utility’swith Diablo Canyon ~~facility but at any other~~outage support services, nuclear ~~power plant~~fuel analysis, original equipment manufacturer engineering and parts support. On March 29, 2017, Westinghouse filed for Chapter 11 protection in the United ~~States. (See Note 13~~States Bankruptcy Court, Southern District of New York. In the ~~Notes to the Consolidated Financial Statements~~event that Westinghouse experiences business disruptions in ~~the 2015 Form 10-K.)~~

~~On June 20, 2016, the Utility entered into a proposal to retire Diablo Canyon at the expiration of~~ its ~~current operating licenses in 2024 and 2025, subject to certain regulatory approvals. However, the Utility continues to face public concern about the safety of~~ nuclear generation and nuclear fuel. Some of these nuclear opposition groups regularly file petitions at the NRC and in other forums challenging the actions of the NRC and urging governmental entities to adopt laws or policies in opposition to nuclear power. Although an action in opposition may ultimately fail, regulatory proceedings may take longer to conclude and be more costly to complete. It is also possible that public pressure could grow leading to adverse changes in legislation, regulations, orders, or their interpretation. Asfuel business as a result ~~operations at the Utility’s two nuclear generation units at Diablo Canyon could cease before the licenses expire in 2024 and 2025. In such an instance,~~of bankruptcy proceedings or otherwise, the Utility could experience issues with its nuclear fuel supply and delays in connection with Diablo Canyon refueling outages. The Utility also could experience losses in connection with its nuclear fuel inventory and Westinghouse could seek to reject in bankruptcy its contracts with the Utility. Diablo Canyon’s Unit 2 refueling outage is expected to occur in the first quarter of 2018. If Westinghouse were to reject the Utility’s contracts or fail to deliver nuclear fuel or provide outage support to the Utility, the Utility’s operation of Diablo Canyon would be ~~required to record a charge for the remaining amount of its unrecovered investment and such charge could have a material effect on~~ adversely affected. PG&E Corporation and the ~~Utility’s financial results.~~

~~The~~ Utility ~~has incurred, and may continue to incur, substantial~~also could experience additional costs, ~~to comply with NRC regulations and orders. (See “Regulatory Environment” in Item 1. Business~~including decreased electricity market revenues, in the ~~2015 Form 10-K.) If the Utility were~~event that one or both Diablo Canyon units are unable to ~~recover these~~operate. There can be no assurance that any such additional costs ~~PG&E Corporation’s and~~would be recoverable in the Utility’s financial results could be materially affected. The Utility may determine that it cannot comply with the new regulations or orders in a feasible and economic manner and voluntarily cease operations; alternatively, the NRC may order the Utility to cease operations until the Utility can comply with new regulations, orders, or decisions. The Utility may incur a material charge if it ceases operations at Diablo Canyon before the licenses expire in 2024 and 2025. At September 30, 2016, the Utility’s unrecovered investment in Diablo Canyon was $1.7 billion.

At the state level, the California Water Board has adopted a policy on once-through cooling that generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities in California by at least 85%. If the California Water Board requires the installation of cooling towers that the Utility believes are not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge. If the Utility obtains contingent approvals referred to herein that will result in retiring Diablo Canyon at the end of the current NRC operating licenses, the Utility will not be required to install cooling towers or implement alternative measures in order to comply with the California State Water Board Once-Through Cooling Water Policy, thus eliminating the risk of regulatory uncertainty regarding the measures that could have been imposed on the Utility or of incurring a material charge related thereto. Even ifrates the Utility is ~~ultimately not required~~permitted to install cooling towers, under the State Water Board’s interim mitigation measures applicable to Diablo Canyon’s operations prior to 2025, starting in 2016, it will be required to make payments to the California Coastal Conservancy to fund various environmental mitigation projects, thatrecover from its customers. Furthermore, the Utility ~~does~~currently is not ~~expect~~able to ~~exceed$5 million per year.~~ estimate the nature or amount of additional costs and expenses that it might incur in connection with the uncertainties surrounding Westinghouse but such costs and expenses could be material.

~~On June 28, 2016~~For certain critical technologies, products and services, the ~~California State Lands Commission approved an extension~~Utility relies on a limited number of suppliers and, in some cases, sole suppliers. In the event these suppliers are unable to perform, the Utility could experience delays and disruptions in its business operations while it transitions to alternative plans or suppliers.

The Utility relies on a limited number of sole source suppliers for certain of its technologies, products and services. Although the Utility has long-term agreements with such suppliers, if the suppliers are unable to deliver these technologies, products or services, the Utility could experience delays and disruptions while it implements alternative plans and makes arrangements with acceptable substitute suppliers. As a result, the Utility’s ~~leases~~business, financial condition, and results of coastal land occupied by the water intake and discharge structures for the nuclear generation units at Diablo Canyon, to run concurrently with Diablo Canyon’s current operating licenses. The Utility will be required to obtain an additional lease extension from the State Lands Commission to cover the period of time necessary to decommission the facility. The State Lands Commission and California Coastal Commission will evaluate appropriate environmental mitigation and development conditions associated with the decommissioning project, the costs of whichoperations could be ~~substantial.~~

~~The Utility also has~~significantly affected. As an obligation to decommission its electricity generation facilities, including its nuclear facilities, as well as gas transmission system assets, at the end of their useful lives. (See Note 2 of the Notes to Condensed Consolidated Financial Statements in Item 1 herein and Note 2 of the Notes to the Consolidated Financial Statement in Item 8 of the 2015 Form 10-K.) The CPUC authorizesexample, the Utility relies on Silver Spring Networks, Inc. and Aclara Technologies LLC as suppliers of proprietary SmartMeter™ devices and software, and of managed services, utilized in its advanced metering system that collects electric and natural gas usage data from customers. If these suppliers encounter performance difficulties, are unable to ~~recover its estimated costs~~supply these devices or maintain and update their software, or provide other services to decommission its nuclear facilities through nuclear decommissioning charges that are collected from customers and held in nuclear decommissioning trusts to be used for the eventual decommissioning of each nuclear unit. Ifmaintain these systems, the Utility’s ~~actual decommissioning costs, including the amounts held in the nuclear decommissioning trusts, exceed estimated costs, PG&E Corporation’s~~metering, billing, and ~~the Utility’s financial results~~electric network operations could be ~~materially affected.~~impacted and disrupted.

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

During the quarter ended September 30, ~~2016,~~2017, PG&E Corporation made equity contributions totaling ~~$460~~$215 million to the Utility in order to maintain the 52% common equity component of the Utility’s CPUC-authorized capital structure. Neither PG&E Corporation nor the Utility made any sales of unregistered equity securities during the quarter ended September 30, ~~2016.~~2017.

Issuer Purchases of Equity Securities

During the quarter ~~endedSeptember~~ended September 30, ~~2016,~~2017, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. PG&E Corporation does not have any preferred stock outstanding. During the quarter ended September 30, ~~2016,~~2017, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

ITEM 5. OTHER INFORMATION

Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends

The Utility’s earnings to fixed charges ratio for the nine months ended September 30, ~~2016~~2017 was ~~1.57.~~2.60. The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the nine months ended September 30, ~~2016 was1.55.~~2017 was 2.58. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and Exhibits into the Utility’s Registration Statement No. ~~333-193879.~~333-215427.

PG&E Corporation’s earnings to fixed charges ratio for the nine months ended September 30, ~~2016~~2017 was ~~1.55.~~2.62. The statement of the foregoing ratio, together with the statement of the computation of the foregoing ratio filed as Exhibit 12.3 hereto, is included herein for the purpose of incorporating such information and Exhibit into PG&E Corporation’s Registration Statement No. ~~333-193880.~~333-215425.

ITEM 6. EXHIBITS

EXHIBIT INDEX

~~3.1~~	~~Bylaws of PG&E Corporation amended as of September 20, 2016~~

~~3.2~~	~~Bylaws of Pacific Gas and Electric Company amended as of September 20, 2016~~

*10.1	~~Non-Annual Restricted Stock Unit Award~~Separation Agreement between PG&E Corporation and ~~David S. Thomason~~Hyun Park dated August ~~8, 2016~~

*10.2	~~Performance Share Award Agreement subject to financial goals between David S. Thomason~~7, 2017 and ~~PG&E Corporation dated August 8, 2016~~

*10.3	~~Performance Share Award Agreement subject to safety and customer affordability goals between David S. Thomason and PG&E Corporation dated August 8, 2016~~amended as of September 1, 2017

12.1	Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company

12.2	Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company

12.3	Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation

31.1	Certifications of the Principal Executive Officer and the Principal Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

31.2	Certifications of the Principal Executive ~~Officers~~Officer and the Principal Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002

**32.1	Certifications of the Principal Executive Officer and the Principal Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002

**32.2	Certifications of the Principal Executive ~~Officers~~Officer and the Principal Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

101.INS	XBRL Instance Document

101.SCH	XBRL Taxonomy Extension Schema Document

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB	XBRL Taxonomy Extension Labels Linkbase Document

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

*Management contract or compensatory agreement.

**Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this Quarterly Report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized.

PG&E CORPORATION

/s/ JASON P. WELLS

Jason P. Wells
Senior Vice President and Chief Financial Officer
(duly authorized officer and principal financial officer)

PACIFIC GAS AND ELECTRIC COMPANY

/s/ ~~DAVID~~DAVID S. THOMASON

David S. Thomason

Vice President, Chief Financial Officer and Controller

(duly authorized officer and principal financial officer)

Dated: November ~~4, 2016~~2, 2017

~~EXHIBIT INDEX~~

~~3.1~~	~~Bylaws of PG&E Corporation amended as of September 20, 2016~~

~~3.2~~	~~Bylaws of Pacific Gas and Electric Company amended as of September 20, 2016~~

*10.1	~~Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and David S. Thomason dated August 8, 2016~~

*10.2	~~Performance Share Award Agreement subject to financial goals between David S. Thomason and PG&E Corporation dated August 8, 2016~~

*10.3	~~Performance Share Award Agreement subject to safety and customer affordability goals between David S. Thomason and PG&E Corporation dated August 8, 2016~~

~~12.1~~	~~Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company~~

~~12.2~~	~~Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company~~

~~12.3~~	~~Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation~~

~~31.1~~	~~Certifications of the Principal Executive Officer and the Principal Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002~~

~~31.2~~	~~Certifications of the Principal Executive Officers and the Principal Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002~~

**32.1	~~Certifications of the Principal Executive Officer and the Principal Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002~~

**32.2	~~Certifications of the Principal Executive Officers and the Principal Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002~~

~~101.INS~~	~~XBRL Instance Document~~

~~101.SCH~~	~~XBRL Taxonomy Extension Schema Document~~

~~101.CAL~~	~~XBRL Taxonomy Extension Calculation Linkbase Document~~

~~101.LAB~~	~~XBRL Taxonomy Extension Labels Linkbase Document~~

~~101.PRE~~	~~XBRL Taxonomy Extension Presentation Linkbase Document~~

~~101.DEF~~	~~XBRL Taxonomy Extension Definition Linkbase Document~~

*Management contract or compensatory agreement.

**Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.


	Nine Months		Cumulative		Future
	Ended		Charges		Charges
		September 30,		September 30,	and		Total
(in millions)	2016		2016		Costs		Amount
Fine paid to the state	$	-	$	300	$	-	$	300
Customer bill credit paid		-		400		-		400
Charge for disallowed capital (1)		286		692		-		692
Disallowed revenue for pipeline safety
expenses (2)		8		8		150		158
CPUC estimated cost of other remedies (3)		-		-		-		50
Total Penalty Decision fines and remedies	$	294	$	1,400	$	150	$	1,600

Year		Increase Requested in GRC Application (in millions)		Increase Proposed in Settlement Agreement (in millions)		Difference(1) (Decrease from GRC Application) (in millions)
2017	$	319	$	88	$	(231)
2018		467		444		(23)
2019		368		361		(7)
2020(2)		N/A		361		N/A

						Increase/(Decrease) Proposed in Settlement Agreement				Difference(1) (Decrease from GRC Application)
(in millions)		Increase Requested in GRC Application
Line of Business:		Increase Requested in GRC Application
Electric distribution	$	67	1.6	%	$	(62)	(1.5)	%	$	(128)
Gas distribution		59	3.4			(3)	(0.2)			(62)
Electric generation		193	9.9			153	7.8			(40)
2017 revenue requirement increases	$	319	4.0	%	$	88	1.1	%	$	(231)