UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C., 20549
					FORM	10-Q
(Mark One)
☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
			For the quarterly period ended				September 30, 2019
			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							Pacific Gas and Electric Company
77 Beale Street							77 Beale Street
P.O. Box 770000							P.O. Box 770000
San Francisco,		California	94177				San Francisco,		California	94177
Address of principal executive offices, including zip code
PG&E Corporation							Pacific Gas and Electric Company
415	973-1000						415	973-7000
Registrant’s telephone number, including area code

Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock, no par value	PCG	The New York Stock Exchange
First preferred stock, cumulative, par value $25 per share, 5% series A redeemable	PCG-PE	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% redeemable	PCG-PD	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.80% redeemable	PCG-PG	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.50% redeemable	PCG-PH	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable	PCG-PI	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 6% nonredeemable	PCG-PA	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable	PCG-PB	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% nonredeemable	PCG-PC	NYSE American LLC

Indicate by check mark whether 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) has been subject to such filing requirements for the past 90 days.
PG&E Corporation:	☒	Yes	☐	No
Pacific Gas and Electric Company:	☒	Yes	☐	No

1

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).
PG&E Corporation:	☒	Yes	☐	No
Pacific Gas and Electric Company:	☒	Yes	☐	No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
PG&E Corporation:	☒	Large accelerated filer	☐	Accelerated filer
	☐	Non-accelerated filer
	☐	Smaller reporting company	☐	Emerging growth company
Pacific Gas and Electric Company:	☐	Large accelerated filer	☐	Accelerated filer
	☒	Non-accelerated filer
	☐	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	☒	No
Pacific Gas and Electric Company:			☐	Yes	☒	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 November 1, 2019:
PG&E Corporation:	529,229,517
Pacific Gas and Electric Company:	264,374,809

2

PG&E CORPORATION AND

PACIFIC GAS AND ELECTRIC COMPANY, DEBTORS-IN-POSSESSION

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2019

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
	CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
	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
	CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
	NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION
	NOTE 2: BANKRUPTCY FILING
	NOTE 3: SIGNIFICANT ACCOUNTING POLICIES
	NOTE 4: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
	NOTE 5: DEBT
	NOTE 6: EQUITY
	NOTE 7: EARNINGS PER SHARE
	NOTE 8: DERIVATIVES
	NOTE 9: FAIR VALUE MEASUREMENTS
	NOTE 10: WILDFIRE-RELATED CONTINGENCIES
	NOTE 11: OTHER CONTINGENCIES AND COMMITMENTS
	NOTE 12: 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 INITIATIVES
	ENVIRONMENTAL MATTERS
	CONTRACTUAL COMMITMENTS
	RISK MANAGEMENT ACTIVITIES
	RECENT DEVELOPMENTS
	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 6. EXHIBITS
	SIGNATURES

3

GLOSSARY

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

2018 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, 2018
2019 Wildfire Mitigation Plan	the wildfire mitigation plan for 2019 submitted by the Utility to the CPUC pursuant to SB 901, previously also referred to as the "2019 Wildfire Safety Plan"
AB	Assembly Bill
ALJ	administrative law judge
ARAM	average rate assumption method
ARO	asset retirement obligation
ASU	accounting standard update issued by the FASB (see below)
Backstop Party	a third-party investor party to a Backstop Commitment Letter
Bankruptcy Code	the United States Bankruptcy Code
Bankruptcy Court	the U.S. Bankruptcy Court for the Northern District of California
CAISO	California Independent System Operator
Cal Fire	California Department of Forestry and Fire Protection
CCA	Community Choice Aggregator
CCPA	California Consumer Privacy Act of 2018
CEC	California Energy Resources Conservation and Development Commission
CEMA	Catastrophic Event Memorandum Account
Chapter 11	chapter 11 of title 11 of the U.S. Code
Chapter 11 Cases	the voluntary cases commenced by each of PG&E Corporation and the Utility under Chapter 11 on January 29, 2019
CHT	Customer Harm Threshold
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
CUE	Coalition of California Utility Employees
CWSP	Community Wildfire Safety Program
DA	Direct Access
DER	distributed energy resources
Diablo Canyon	Diablo Canyon nuclear power plant
DIP Credit Agreement	Senior Secured Superpriority Debtor in Possession Credit, Guaranty and Security Agreement, dated as of February 1, 2019, among the Utility, as borrower, PG&E Corporation, as guarantor, JPMorgan Chase Bank, N.A., as administrative agent, and Citibank, N.A., as collateral agent
DRP	Distribution Resource Plan
DTSC	Department of Toxic Substances Control
EPS	earnings per common share
EV	electric vehicle
EVM	enhanced vegetation management
FASB	Financial Accounting Standards Board
FEMA	Federal Emergency Management Agency
FERC	Federal Energy Regulatory Commission
FHPMA	Fire Hazard Prevention Memorandum Account
FRMMA	Fire Risk Mitigation Memorandum Account
GAAP	U.S. Generally Accepted Accounting Principles
GHG	greenhouse gas

4

GRC	general rate case
GT&S	gas transmission and storage
HSM	Hazardous Substance Memorandum Account
IOU(s)	investor-owned utility(ies)
LIBOR	London Interbank Offered Rate
LSTC	liabilities subject to compromise
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Item 2 of this Form 10-Q
MGP(s)	manufactured gas plants
the Monitor	third-party monitor retained as part of its compliance with the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction
NAV	net asset value
NDCTP	Nuclear Decommissioning Cost Triennial Proceedings
NDT	Diablo Canyon Nuclear Decommissioning Trust
NEIL	Nuclear Electric Insurance Limited
NRC	Nuclear Regulatory Commission
OES	State of California Office of Emergency Services
OII	order instituting investigation
OIR	order instituting rulemaking
OSA	Office of the Safety Advocate, a division of the CPUC
PAO	Public Advocates Office of the California Public Utilities Commission (formerly known as Office of Ratepayer Advocates or ORA)
PCIA	Power Charge Indifference Adjustment
PD	proposed decision
Petition Date	January 29, 2019
PFM	petition for modification
PSA	plan support agreement
PSPS	Public Safety Power Shutoff
ROE	return on equity
ROU asset	right-of-use asset
RSA	restructuring support agreement (as amended)
SB	Senate Bill
SEC	U.S. Securities and Exchange Commission
SED	Safety and Enforcement Division of the CPUC
Tax Act	Tax Cuts and Jobs Act of 2017
TCC	Official Committee of Tort Claimants
TE	transportation electrification
TO	transmission owner
TURN	The Utility Reform Network
UCC	Official Committee of Unsecured Creditors
USAO	United States Attorney’s Office for the Northern District of California
Utility	Pacific Gas and Electric Company
VIE(s)	variable interest entity(ies)
VM	vegetation management
WEMA	Wildfire Expense Memorandum Account
Wildfire Assistance Fund	program designed to assist those displaced by the 2018 Camp fire and 2017 Northern California wildfires with the costs of temporary housing and other urgent needs

5

Wildfire Fund	statewide fund established by AB 1054 that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment
WMPMA	Wildfire Mitigation Plan Memorandum Account

6

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 

PG&E CORPORATION

(DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	(Unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions, except per share amounts)	2019		2018		2019		2018
Operating Revenues
Electric	$	3,554	$	3,466	$	9,292	$	9,729
Natural gas	878		915		3,094		2,942
Total operating revenues	4,432		4,381		12,386		12,671
Operating Expenses
Cost of electricity	1,070		1,256		2,506		3,038
Cost of natural gas	68		69		515		437
Operating and maintenance	2,206		1,611		6,235		5,001
Wildfire-related claims, net of insurance recoveries	2,548		(10)		6,448		2,108
Depreciation, amortization, and decommissioning	840		759		2,433		2,257
Total operating expenses	6,732		3,685		18,137		12,841
Operating Income (Loss)	(2,300)		696		(5,751)		(170)
Interest income	18		14		62		35
Interest expense	(52)		(232)		(215)		(678)
Other income, net	62		104		199		318
Reorganization items, net	(73)		—		(256)		—
Income (Loss) Before Income Taxes	(2,345)		582		(5,961)		(495)
Income tax provision (benefit)	(729)		15		(1,932)		(527)
Net Income (Loss)	(1,616)		567		(4,029)		32
Preferred stock dividend requirement of subsidiary	3		3		10		10
Income (Loss) Attributable to Common Shareholders	$	(1,619)	$	564	$	(4,039)	$	22
Weighted Average Common Shares Outstanding, Basic	529		517		528		516
Weighted Average Common Shares Outstanding, Diluted	529		517		528		517
Net Income (Loss) Per Common Share, Basic	$	(3.06)	$	1.09	$	(7.65)	$	0.04
Net Income (Loss) Per Common Share, Diluted	$	(3.06)	$	1.09	$	(7.65)	$	0.04
See accompanying Notes to the Condensed Consolidated Financial Statements.

7

PG&E CORPORATION

(DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2019		2018		2019		2018
Net Income (Loss)	$	(1,616)	$	567	$	(4,029)	$	32
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates)	—		1		—		1
Total other comprehensive income	—		1		—		1
Comprehensive Income (Loss)	(1,616)		568		(4,029)		33
Preferred stock dividend requirement of subsidiary	3		3		10		10
Comprehensive Income (Loss) Attributable to Common Shareholders	$	(1,619)	$	565	$	(4,039)	$	23
See accompanying Notes to the Condensed Consolidated Financial Statements.

8

PG&E CORPORATION

(DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
(in millions)	September 30, 2019		December 31, 2018
ASSETS
Current Assets
Cash and cash equivalents	$	2,970	$	1,668
Accounts receivable:
Customers (net of allowance for doubtful accounts of $41 and $56 at respective dates)	1,397		1,148
Accrued unbilled revenue	1,023		1,000
Regulatory balancing accounts	1,919		1,435
Other	2,627		2,686
Regulatory assets	314		233
Inventories:
Gas stored underground and fuel oil	110		111
Materials and supplies	525		443
Income taxes receivable	15		23
Other	677		448
Total current assets	11,577		9,195
Property, Plant, and Equipment
Electric	61,797		59,150
Gas	22,741		21,556
Construction work in progress	2,689		2,564
Other	20		2
Total property, plant, and equipment	87,247		83,272
Accumulated depreciation	(25,923)		(24,715)
Net property, plant, and equipment	61,324		58,557
Other Noncurrent Assets
Regulatory assets	5,711		4,964
Nuclear decommissioning trusts	3,061		2,730
Operating lease right of use asset	2,435		—
Income taxes receivable	67		69
Other	1,538		1,480
Total other noncurrent assets	12,812		9,243
TOTAL ASSETS	$	85,713	$	76,995
See accompanying Notes to the Condensed Consolidated Financial Statements.

9

PG&E CORPORATION

(DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
(in millions, except share amounts)	September 30, 2019		December 31, 2018
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	—	$	3,435
Long-term debt, classified as current	—		18,559
Accounts payable:
Trade creditors	1,844		1,975
Regulatory balancing accounts	1,655		1,076
Other	558		464
Operating lease liabilities	553		—
Disputed claims and customer refunds	—		220
Interest payable	5		228
Wildfire-related claims	—		14,226
Other	1,857		1,512
Total current liabilities	6,472		41,695
Noncurrent Liabilities
Debtor-in-possession financing	1,500		—
Regulatory liabilities	9,336		8,539
Pension and other post-retirement benefits	1,986		2,119
Asset retirement obligations	6,259		5,994
Deferred income taxes	1,721		3,281
Operating lease liabilities	1,882		—
Other	2,473		2,464
Total noncurrent liabilities	25,157		22,397
Liabilities Subject to Compromise	45,093		—
Equity
Shareholders’ Equity
Common stock, no par value, authorized 800,000,000 shares; 529,229,517 and 520,338,710 shares outstanding at respective dates	13,027		12,910
Reinvested earnings	(4,279)		(250)
Accumulated other comprehensive loss	(9)		(9)
Total shareholders’ equity	8,739		12,651
Noncontrolling Interest - Preferred Stock of Subsidiary	252		252
Total equity	8,991		12,903
TOTAL LIABILITIES AND EQUITY	$	85,713	$	76,995
See accompanying Notes to the Condensed Consolidated Financial Statements.

10

PG&E CORPORATION

(DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Nine Months Ended September 30,
(in millions)	2019		2018
Cash Flows from Operating Activities
Net income (loss)	$	(4,029)	$	32
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,433		2,257
Allowance for equity funds used during construction	(64)		(97)
Deferred income taxes and tax credits, net	(1,548)		10
Reorganization items, net (Note 2)	97		—
Disallowed capital expenditures	232		(38)
Other	112		231
Effect of changes in operating assets and liabilities:
Accounts receivable	(264)		(201)
Wildfire-related insurance receivable	35		64
Inventories	(68)		(24)
Accounts payable	371		245
Wildfire-related claims	(114)		2,233
Income taxes receivable/payable	8		—
Other current assets and liabilities	(7)		(154)
Regulatory assets, liabilities, and balancing accounts, net	90		(128)
Liabilities subject to compromise	6,704		—
Other noncurrent assets and liabilities	79		(194)
Net cash provided by operating activities	4,067		4,236
Cash Flows from Investing Activities
Capital expenditures	(4,192)		(4,592)
Proceeds from sales and maturities of nuclear decommissioning trust investments	808		1,121
Purchases of nuclear decommissioning trust investments	(874)		(1,165)
Other	8		19
Net cash used in investing activities	(4,250)		(4,617)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	1,850		—
Repayments of debtor-in-possession credit facility	(350)		—
Debtor-in-possession credit facility debt issuance costs	(114)		—
Borrowings under revolving credit facilities	—		775
Repayments under revolving credit facilities	—		(775)
Net repayments of commercial paper, net of discount of $1	—		(182)
Short-term debt financing	—		250
Short-term debt matured	—		(250)
Proceeds from issuance of long-term debt, net of discount and issuance costs of $7	—		1,143
Long-term debt matured or repurchased	—		(750)
Common stock issued	85		137
Other	14		14
Net cash provided by financing activities	1,485		362
Net change in cash, cash equivalents, and restricted cash	1,302		(19)

11

Cash, cash equivalents, and restricted cash at January 1	1,675		456
Cash, cash equivalents, and restricted cash at September 30	$	2,977	$	437
Less: Restricted cash and restricted cash equivalents included in other current assets	(7)		$	(7)
Cash and cash equivalents at September 30	$	2,970	$	430

Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(38)	$	(650)
Income taxes, net	—		(49)
Supplemental disclosures of noncash operating activities
Operating lease liabilities arising from obtaining ROU assets	$	2,816	$	—
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	981	$	348
See accompanying Notes to the Condensed Consolidated Financial Statements.

12

PG&E CORPORATION

(DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(in millions, except share amounts)	Common Stock Shares	Common Stock Amount		Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders’ Equity		Non controlling Interest - Preferred Stock of Subsidiary		Total Equity
Balance at December 31, 2018	520,338,710	$	12,910	$	(250)	$	(9)	$	12,651	$	252	$	12,903
Net income	—	—		136		—		136		—		136
Other comprehensive loss	—	—		—		—		—		—		—
Common stock issued, net	8,871,568	85		—		—		85		—		85
Stock-based compensation amortization	—	5		—		—		5		—		5
Balance at March 31, 2019	529,210,278	$	13,000	$	(114)	$	(9)	$	12,877	$	252	$	13,129
Net loss	—	—		(2,549)		—		(2,549)		—		(2,549)
Other comprehensive loss	—	—		—		—		—		—		—
Common stock issued, net	13,515	—		—		—		—		—		—
Stock-based compensation amortization	—	14		—		—		14		—		14
Balance at June 30, 2019	529,223,793	$	13,014	$	(2,663)	$	(9)	$	10,342	$	252	$	10,594
Net loss	—	—		(1,616)		—		(1,616)		—		(1,616)
Other comprehensive loss	—	—		—		—		—		—		—
Common stock issued, net	5,724	—		—		—		—		—		—
Stock-based compensation amortization	—	13		—		—		13		—		13
Balance at September 30, 2019	529,229,517	$	13,027	$	(4,279)	$	(9)	$	8,739	$	252	$	8,991

(in millions, except share amounts)	Common Stock Shares	Common Stock Amount		Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders’ Equity		Non controlling Interest - Preferred Stock of Subsidiary		Total Equity
Balance at December 31, 2017	514,755,845	$	12,632	$	6,596	$	(8)	$	19,220	$	252	$	19,472
Net income	—	—		445		—		445		—		445
Other comprehensive income	—	—		5		(5)		—		—		—
Common stock issued, net	1,248,112	35		—		—		35		—		35
Stock-based compensation amortization	—	34		—		—		34		—		34
Preferred stock dividend requirement of subsidiary	—	—		(3)		—		(3)		—		(3)
Balance at March 31, 2018	516,003,957	$	12,701	$	7,043	$	(13)	$	19,731	$	252	$	19,983
Net loss	—	—		(980)		—		(980)		—		(980)
Other comprehensive income	—	—		—		—		—		—		—
Common stock issued, net	1,099,026	47		—		—		47		—		47
Stock-based compensation amortization	—	15		—		—		15		—		15
Preferred stock dividend requirement of subsidiary	—	—		(4)		—		(4)		—		(4)
Balance at June 30, 2018	517,102,983	$	12,763	$	6,059	$	(13)	$	18,809	$	252	$	19,061
Net income	—	—		567		—		567		—		567
Other comprehensive income	—	—		—		1		1		—		1
Common stock issued, net	1,229,841	55		—		—		55		—		55
Stock-based compensation amortization	—	15		—		—		15		—		15
Preferred stock dividend requirement of subsidiary	—	—		(3)		—		(3)		—		(3)
Balance at September 30, 2018	518,332,824	$	12,833	$	6,623	$	(12)	$	19,444	$	252	$	19,696

See accompanying Notes to the Consolidated Financial Statements.

13

PACIFIC GAS AND ELECTRIC COMPANY

(DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	(Unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2019		2018		2019		2018
Operating Revenues
Electric	$	3,554	$	3,467	$	9,292	$	9,730
Natural gas	878		915		3,094		2,942
Total operating revenues	4,432		4,382		12,386		12,672
Operating Expenses
Cost of electricity	1,070		1,256		2,506		3,038
Cost of natural gas	68		69		515		437
Operating and maintenance	2,208		1,611		6,252		5,002
Wildfire-related claims, net of insurance recoveries	2,548		(10)		6,448		2,108
Depreciation, amortization, and decommissioning	840		759		2,433		2,257
Total operating expenses	6,734		3,685		18,154		12,842
Operating Income (Loss)	(2,302)		697		(5,768)		(170)
Interest income	18		14		61		34
Interest expense	(52)		(229)		(213)		(668)
Other income, net	57		103		187		321
Reorganization items, net	(69)		—		(237)		—
Income (Loss) Before Income Taxes	(2,348)		585		(5,970)		(483)
Income tax provision (benefit)	(738)		14		(1,943)		(530)
Net Income (Loss)	(1,610)		571		(4,027)		47
Preferred stock dividend requirement	3		3		10		10
Income (Loss) Attributable to Common Stock	$	(1,613)	$	568	$	(4,037)	$	37
See accompanying Notes to the Condensed Consolidated Financial Statements.

14

PACIFIC GAS AND ELECTRIC COMPANY

(DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	(Unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2019		2018		2019		2018
Net Income (Loss)	$	(1,610)	$	571	$	(4,027)	$	47
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates)	—		—		—		1
Total other comprehensive income	—		—		—		1
Comprehensive Income (Loss)	$	(1,610)	$	571	$	(4,027)	$	48
See accompanying Notes to the Condensed Consolidated Financial Statements.

15

PACIFIC GAS AND ELECTRIC COMPANY

(DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
(in millions)	September 30, 2019		December 31, 2018
ASSETS
Current Assets
Cash and cash equivalents	$	2,539	$	1,295
Accounts receivable:
Customers (net of allowance for doubtful accounts of $41 and $56 at respective dates)	1,397		1,148
Accrued unbilled revenue	1,023		1,000
Regulatory balancing accounts	1,919		1,435
Other	2,639		2,688
Regulatory assets	314		233
Inventories:
Gas stored underground and fuel oil	110		111
Materials and supplies	525		443
Income taxes receivable	4		5
Other	666		448
Total current assets	11,136		8,806
Property, Plant, and Equipment
Electric	61,797		59,150
Gas	22,741		21,556
Construction work in progress	2,689		2,564
Other	18		—
Total property, plant, and equipment	87,245		83,270
Accumulated depreciation	(25,920)		(24,713)
Net property, plant, and equipment	61,325		58,557
Other Noncurrent Assets
Regulatory assets	5,711		4,964
Nuclear decommissioning trusts	3,061		2,730
Operating lease right of use asset	2,427		—
Income taxes receivable	66		66
Other	1,394		1,348
Total other noncurrent assets	12,659		9,108
TOTAL ASSETS	$	85,120	$	76,471
See accompanying Notes to the Condensed Consolidated Financial Statements.

16

PACIFIC GAS AND ELECTRIC COMPANY

(DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	Balance At
(in millions. except share amounts)	September 30, 2019		December 31, 2018
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	—	$	3,135
Long-term debt, classified as current	—		18,209
Accounts payable:
Trade creditors	1,841		1,972
Regulatory balancing accounts	1,655		1,076
Other	650		498
Operating lease liabilities	550		—
Disputed claims and customer refunds	—		220
Interest payable	5		227
Wildfire-related claims	—		14,226
Other	1,857		1,497
Total current liabilities	6,558		41,060
Noncurrent Liabilities
Debtor-in-possession financing	1,500		—
Regulatory liabilities	9,336		8,539
Pension and other post-retirement benefits	1,986		2,026
Asset retirement obligations	6,259		5,994
Deferred income taxes	1,839		3,405
Operating lease liabilities	1,877		—
Other	2,528		2,492
Total noncurrent liabilities	25,325		22,456
Liabilities Subject to Compromise	44,309		—
Shareholders’ Equity
Preferred stock	258		258
Common stock, $5 par value, authorized 800,000,000 shares; 264,374,809 shares outstanding at respective dates	1,322		1,322
Additional paid-in capital	8,550		8,550
Reinvested earnings	(1,201)		2,826
Accumulated other comprehensive income	(1)		(1)
Total shareholders’ equity	8,928		12,955
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	85,120	$	76,471
See accompanying Notes to the Condensed Consolidated Financial Statements.

17

PACIFIC GAS AND ELECTRIC COMPANY

(DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	(Unaudited)
	Nine Months Ended September 30,
(in millions)	2019		2018
Cash Flows from Operating Activities
Net income (loss)	$	(4,027)	$	47
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,433		2,257
Allowance for equity funds used during construction	(64)		(97)
Deferred income taxes and tax credits, net	(1,555)		5
Reorganization items, net (Note 2)	92		—
Disallowed capital expenditures	232		(38)
Other	79		170
Effect of changes in operating assets and liabilities:
Accounts receivable	(274)		(200)
Wildfire-related insurance receivable	35		64
Inventories	(68)		(24)
Accounts payable	418		245
Wildfire-related claims	(114)		2,233
Income taxes receivable/payable	1		—
Other current assets and liabilities	9		(156)
Regulatory assets, liabilities, and balancing accounts, net	90		(128)
Liabilities subject to compromise	6,695		—
Other noncurrent assets and liabilities	96		(194)
Net cash provided by operating activities	4,078		4,184
Cash Flows from Investing Activities
Capital expenditures	(4,192)		(4,592)
Proceeds from sales and maturities of nuclear decommissioning trust investments	808		1,121
Purchases of nuclear decommissioning trust investments	(874)		(1,165)
Other	8		19
Net cash used in investing activities	(4,250)		(4,617)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	1,850		—
Repayments of debtor-in-possession credit facility	(350)		—
Debtor-in-possession credit facility debt issuance costs	(98)		—
Borrowings under revolving credit facilities	—		650
Repayments under revolving credit facilities	—		(650)
Net repayments of commercial paper, net of discount	—		(50)
Short-term debt financing	—		250
Short-term debt matured	—		(250)
Proceeds from issuance of long-term debt, net of discount and issuance costs of $7	—		793
Long-term debt matured or repurchased	—		(400)
Other	14		14
Net cash provided by financing activities	1,416		357

18

Net change in cash, cash equivalents, and restricted cash	1,244		(76)
Cash, cash equivalents, and restricted cash at January 1	1,302		454
Cash, cash equivalents, and restricted cash at September 30	$	2,546	$	378
Less: Restricted cash and restricted cash equivalents included in other current assets	(7)		(7)
Cash and cash equivalents at September 30	$	2,539	$	371

Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(36)	$	(640)
Income taxes, net	—		(59)
Supplemental disclosures of noncash operating activities
Operating lease liabilities arising from obtaining ROU assets	$	2,807	$	—
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	981	$	348
See accompanying Notes to the Condensed Consolidated Financial Statements.

19

PACIFIC GAS AND ELECTRIC COMPANY

(DEBTOR-IN-POSSESSION)

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY

(in millions)	Preferred Stock		Common Stock Amount		Additional Paid-in Capital		Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders’ Equity
Balance at December 31, 2018	$	258	$	1,322	$	8,550	$	2,826	$	(1)	$	12,955
Net income	—		—		—		133		—		133
Other comprehensive loss	—		—		—		—		—		—
Equity contribution	—		—		—		—		—		—
Balance at March 31, 2019	$	258	$	1,322	$	8,550	$	2,959	$	(1)	$	13,088
Net loss	—		—		—		(2,550)		—		(2,550)
Other comprehensive loss	—		—		—		—		—		—
Equity contribution	—		—		—		—		—		—
Balance at June 30, 2019	$	258	$	1,322	$	8,550	$	409	$	(1)	$	10,538
Net loss	—		—		—		(1,610)		—		(1,610)
Other comprehensive loss	—		—		—		—		—		—
Equity contribution	—		—		—		—		—		—
Balance at September 30, 2019	$	258	$	1,322	$	8,550	$	(1,201)	$	(1)	$	8,928

(in millions)	Preferred Stock		Common Stock Amount		Additional Paid-in Capital		Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)		Total Shareholders’ Equity
Balance at December 31, 2017	$	258	$	1,322	$	8,505	$	9,656	$	6	$	19,747
Net income	—		—		—		452		—		452
Other comprehensive income (loss)	—		—		—		2		(2)		—
Equity contribution	—		—		—		—		—		—
Preferred stock dividend	—		—		—		(3)		—		(3)
Balance at March 31, 2018	$	258	$	1,322	$	8,505	$	10,107	$	4	$	20,196
Net loss	—		—		—		(976)		—		(976)
Other comprehensive income	—		—		—		—		1		1
Equity contribution	—		—		—		—		—		—
Preferred stock dividend	—		—		—		(4)		—		(4)
Balance at June 30, 2018	$	258	$	1,322	$	8,505	$	9,127	$	5	$	19,217
Net income	—		—		—		571		—		571
Other comprehensive income	—		—		—		—		—		—
Equity contribution	—		—		—		—		—		—
Preferred stock dividend	—		—		—		(3)		—		(3)
Balance at September 30, 2018	$	258	$	1,322	$	8,505	$	9,695	$	5	$	19,785

See accompanying Notes to the Consolidated Financial Statements.

20

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 assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate as 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 that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented.  The information at December 31, 2018 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in Item 8 of the 2018 Form 10-K.  This quarterly report should be read in conjunction with the 2018 Form 10-K. 

The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, legal and regulatory contingencies, insurance recoveries, environmental remediation liabilities, AROs, pension and other post-retirement benefit plan obligations, and the valuation of LSTC. 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.

Chapter 11 Filing and Going Concern

The accompanying Condensed Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the continuity of operations, the realization of assets and the satisfaction of liabilities in the normal course of business. However, as a result of the challenges that are further described below, such realization of assets and satisfaction of liabilities are subject to uncertainty. PG&E Corporation and the Utility are facing extraordinary challenges relating to a series of catastrophic wildfires that occurred in Northern California in 2017 and 2018. See Note 10 below. Uncertainty regarding these matters raises substantial doubt about PG&E Corporation’s and the Utility’s abilities to continue as going concerns. PG&E Corporation and the Utility determined that commencing reorganization cases under Chapter 11 was necessary to restore PG&E Corporation’s and the Utility’s financial stability to fund ongoing operations and provide safe service to customers. However, there can be no assurance that such proceedings will restore PG&E Corporation’s and the Utility’s financial stability.

On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. The Condensed Consolidated Financial Statements do not include any adjustments that might be necessary should PG&E Corporation and the Utility be unable to continue as going concerns.

Pursuant to sections 1107(a) and 1108 of the Bankruptcy Code, PG&E Corporation and the Utility retain control of their assets and are authorized to operate their business as debtors-in-possession while being subject to the jurisdiction of the Bankruptcy Court. While operating as debtors-in-possession under Chapter 11, PG&E Corporation and the Utility may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business and subject to restrictions in PG&E Corporation’s and the Utility’s DIP Credit Agreement (see Note 5 below) and applicable orders of the Bankruptcy Court, for amounts other than those reflected in the accompanying Condensed Consolidated Financial Statements.  Any such actions occurring during the Chapter 11 Cases authorized by the Bankruptcy Court could materially impact the amounts and classifications of assets and liabilities reported in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements. (For more information regarding the Chapter 11 Cases, see Note 2 below.)

21

NOTE 2: BANKRUPTCY FILING

Chapter 11 Proceedings

On January 29, 2019, PG&E Corporation and the Utility commenced the Chapter 11 Cases with the Bankruptcy Court. PG&E Corporation and the Utility continue to operate their business as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Under the Bankruptcy Code, third-party actions to collect pre-petition indebtedness owed by PG&E Corporation or the Utility, as well as most litigation pending against PG&E Corporation and the Utility (including the third-party matters described in Note 10 below) as of the Petition Date, are subject to an automatic stay. Absent an order of the Bankruptcy Court providing otherwise, substantially all pre-petition liabilities will be resolved under a Chapter 11 plan of reorganization to be voted upon by impaired creditors and interest holders, and approved by the Bankruptcy Court. However, under the Bankruptcy Code, regulatory or criminal proceedings generally are not subject to an automatic stay, and these proceedings have been continuing during the pendency of the Chapter 11 Cases.

Under the priority scheme established by the Bankruptcy Code, certain post-petition and secured or “priority” pre-petition liabilities need to be satisfied before general unsecured creditors and holders of PG&E Corporation's and the Utility’s equity are entitled to receive any distribution. No assurance can be given as to what values, if any, will be ascribed in the Chapter 11 Cases to the claims and interests of each of these constituencies. Additionally, no assurance can be given as to whether, when or in what form unsecured creditors and holders of PG&E Corporation’s or the Utility’s equity may receive a distribution on such claims or interests.

Under the Bankruptcy Code, PG&E Corporation and the Utility may assume, assume and assign, or reject certain executory contracts and unexpired leases, including, without limitation, leases of real property and equipment, subject to the approval of the Bankruptcy Court and to certain other conditions. Any description of an executory contract or unexpired lease in this quarterly report on Form 10-Q, or in the 2018 Form 10-K, including, where applicable, the express termination rights thereunder or a quantification of their obligations, must be read in conjunction with, and is qualified by, any overriding rejection rights PG&E Corporation and the Utility have under the Bankruptcy Code.

Significant Bankruptcy Court Actions

First Day Motions

On January 31, 2019, the Bankruptcy Court approved, on an interim basis, certain motions (the “First Day Motions”) authorizing, but not directing, PG&E Corporation and the Utility to, among other things, (a) secure $5.5 billion of debtor-in-possession financing; (b) continue to use PG&E Corporation’s and the Utility’s cash management system; and (c) pay certain pre-petition claims relating to (i) certain safety, reliability, outage, and nuclear facility suppliers; (ii) shippers, warehousemen, and other lien claimants; (iii) taxes; (iv) employee wages, salaries, and other compensation and benefits; and (v) customer programs, including public purpose programs. The First Day Motions were subsequently approved by the Bankruptcy Court on a final basis at hearings on February 27, 2019, March 12, 2019, March 13, 2019, and March 27, 2019.

Exclusivity Period

On May 23, 2019, the Bankruptcy Court entered an order (the “Exclusivity Order”) pursuant to section 1121(d) of the Bankruptcy Code, extending PG&E Corporation’s and the Utility’s exclusive periods in which to file a Chapter 11 plan of reorganization (the “Exclusive Filing Period”) and solicit acceptances thereof (the “Exclusive Solicitation Period” and, together with the Exclusive Filing Period, the “Exclusive Periods”). Pursuant to the Exclusivity Order, PG&E Corporation’s and the Utility’s Exclusive Filing Period was extended to, and including, September 26, 2019, and PG&E Corporation’s and the Utility’s Exclusive Solicitation Period was extended to, and including, November 26, 2019.

On June 25, 2019, the Ad Hoc Committee of Senior Unsecured Noteholders of the Utility (the “Ad Hoc Noteholder Committee”) submitted a motion, pursuant to section 1121(d)(1) of the Bankruptcy Code, for the entry of an order terminating the Exclusive Periods. The Ad Hoc Noteholder Committee annexed to its motion a “Term Sheet for Plan of Reorganization,” which was thereafter amended on July 17, 2019. On July 18, 2019, PG&E Corporation and the Utility filed an objection to the Ad Hoc Noteholder Committee’s motion with the Bankruptcy Court, requesting that the motion be denied.

22

On July 23, 2019, the Ad Hoc Group of Subrogation Claim Holders (the “Ad Hoc Subrogation Group”) submitted its own motion, pursuant to section 1121(d)(1) of the Bankruptcy Code, to terminate the Exclusive Periods, which included as an exhibit a “Restructuring Term Sheet.” On August 6, 2019, PG&E Corporation and the Utility filed an objection to the Ad Hoc Subrogation Group’s motion with the Bankruptcy Court, requesting that the motion be denied.

On August 16, 2019, the Bankruptcy Court issued a decision in which it denied the Ad Hoc Noteholder Committee’s and the Ad Hoc Subrogation Group’s motions to terminate exclusivity. As discussed in Note 10, on the same date, the Bankruptcy Court granted the motions to lift the automatic stay as applied to certain claims arising out of the 2017 Tubbs fire to allow a state court jury trial on those claims (the “Lift Stay Decision”).

On September 19, 2019, the TCC and the Ad Hoc Noteholder Committee filed a joint motion to terminate PG&E Corporation’s and the Utility’s Exclusive Periods, which included as an exhibit a “Term Sheet for Plan of Reorganization.” On September 25, 2019, PG&E Corporation and the Utility filed a motion seeking a further extension of their Exclusive Periods pursuant to section 1121(d) of the Bankruptcy Code. Also on September 25, 2019, the TCC and Ad Hoc Noteholder Committee filed an amended plan term sheet, which amended the term sheet previously annexed to their joint motion. The term sheet was further amended on October 4, 2019. PG&E Corporation and the Utility filed an objection to the motion of the TCC and the Ad Hoc Noteholder Committee on October 4, 2019, requesting that the joint motion be denied. The hearing on the joint motion to terminate exclusivity filed by the TCC and the Ad Hoc Noteholder Committee was held on October 7, 2019. Following the hearing, on October 9, 2019, the Bankruptcy Court entered an order granting the motion of the TCC and the Ad Hoc Noteholder Committee to terminate the Exclusive Periods as to the TCC and the Ad Hoc Noteholder Committee (the “Exclusivity Termination Decision”). On that same date, the Bankruptcy Court entered an order denying the motion filed by PG&E Corporation and the Utility seeking a further extension of their Exclusive Periods. On October 17, 2019, the TCC and the Ad Hoc Noteholder Committee filed their competing Chapter 11 plan of reorganization (the “TCC/Ad Hoc Noteholder Plan”). See “TCC/Ad Hoc Noteholder Plan of Reorganization” below.

Upcoming Legal Briefings

A status conference on the TCC/Ad Hoc Noteholder Plan and the Proposed Plan (as described below) was held on October 23, 2019, at which the Bankruptcy Court established a tentative briefing schedule on certain legal issues and postponed consideration of PG&E Corporation’s and the Utility’s motion to approve the RSA (as described below) to November 13, 2019. On October 31, 2019, the Bankruptcy Court entered an order setting the final briefing and hearing schedule on certain legal issues in the Chapter 11 Cases. The hearings on the various legal issues are scheduled as follows:

•on the application of the doctrine of inverse condemnation: November 19, 2019;

•on the issue of post-petition interest rate applicable on unsecured claims: December 11, 2019;

•on whether the claims asserted by the U.S. Government, certain California state agencies and certain other entities are unliquidated and subject to estimation under section 502(c) of the Bankruptcy Code: December 17, 2019;

•on whether holders of the Utility’s funded debt claims are entitled to any make-whole or optional redemption or similar amounts: January 14, 2020; and

•on whether the Subrogation Claims that are settled and allowed as provided in the Subrogation Claims Settlement (described below) are impaired: January 14, 2020.

23

Bar Date

On July 1, 2019, the Bankruptcy Court entered an order approving a deadline of October 21, 2019, at 5:00 p.m. (Pacific Time) (the “Bar Date”) for filing claims against PG&E Corporation and the Utility relating to the period prior to the Petition Date. The Bar Date is subject to certain exceptions, including for claims arising under section 503(b)(9) of the Bankruptcy Code, the Bar Date for which occurred on April 22, 2019. The Bankruptcy Court also approved PG&E Corporation’s and the Utility’s plan to provide notice of the Bar Date to parties in interest, including potential wildfire-related claimants and other potential creditors. On October 18, 2019, the TCC filed with the Bankruptcy Court a motion for entry of an order extending the Bar Date for individual wildfire-related claims. On October 28, 2019, PG&E Corporation and the Utility announced that they had offered to extend the Bar Date for individual wildfire-related claims from October 21, 2019 to December 20, 2019. On the same day, during a meet and confer between PG&E Corporation and the Utility and the TCC, and at the request of the TCC, PG&E Corporation and the Utility agreed to further extend the Bar Date for individual wildfire-related claims to December 31, 2019. On November 4, 2019, PG&E Corporation and the Utility and the TCC announced that they have reached agreement to an extension of the Bar Date for individual wildfire-related claims to December 31, 2019, which agreement also involves procedures for additional notice to potential individual wildfire claimants. PG&E Corporation and the Utility and the TCC will file a stipulation with the Bankruptcy Court detailing the terms of the agreement and seeking approval of their agreement.

Other Significant Actions Related to the Chapter 11 Cases

Other significant actions and developments related to the Chapter 11 Cases, including the Tubbs Lift Stay Decision, the Tubbs Trial and the Estimation Proceeding are described in Note 10 (including under the headings “Proceeding in San Francisco County Superior Court for Certain Tubbs Fire-Related Claims” and “Wildfire Claims Estimation Proceeding in the U.S. District Court for the Northern District of California”).

On October 28, 2019, the Bankruptcy Court issued an order directing the principal parties in the Chapter 11 Cases to participate in mediation. The mediator is retired Bankruptcy Court Judge Randall Newsome.

Plan of Reorganization, RSA, Equity Backstop Commitments and Debt Commitment Letters

On September 9, 2019, PG&E Corporation and the Utility filed with the Bankruptcy Court their Joint Chapter 11 Plan of Reorganization (as may be amended, modified or supplemented from time to time, the “Proposed Plan”) for the resolution of the outstanding pre-petition claims against and interests in PG&E Corporation and the Utility.

On September 22, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement with certain holders of insurance subrogation claims (collectively, the “Consenting Subrogation Creditors”). On November 1, 2019, PG&E Corporation and the Utility and the Consenting Subrogation Creditors entered into an amended and restated Restructuring Support Agreement. The RSA provides for an aggregate amount of $11.0 billion (the “Allowed Subrogation Claim Amount”) to be paid by PG&E Corporation and the Utility pursuant to the Proposed Plan in order to settle all insurance subrogation claims (the “Subrogation Claims”) relating to the 2017 Northern California wildfires and the 2018 Camp fire (the “Subrogation Claims Settlement”), upon the terms and conditions set forth in the RSA. Under the RSA, PG&E Corporation and the Utility also have agreed to reimburse the holders of Subrogation Claims for professional fees of up to $55 million, upon the terms and conditions set forth in the RSA. See “Restructuring Support Agreement with Holders of Subrogation Claims” in Note 10 for further information on the RSA.

On September 23, 2019, in accordance with the RSA, PG&E Corporation and the Utility filed their First Amended Joint Chapter 11 Plan of Reorganization to incorporate the terms of the Subrogation Claims Settlement. On November 4, 2019, in accordance with the RSA, as amended, PG&E Corporation and the Utility filed their Joint Chapter 11 Plan of Reorganization dated November 4, 2019. The Proposed Plan, as amended, proposes the following:

•compensation of wildfire victims and certain public entities from a trust funded for their benefit in an amount to be determined in an estimation proceeding not to exceed $8.4 billion;

•compensation of insurance subrogation claimants from a trust funded for their benefit in the amount of $11.0 billion in accordance with the terms of the Subrogation Claims Settlement and RSA;

•payment of $1.0 billion in full settlement of the claims of the settling public entities relating to the wildfires (as further described under the heading “Plan Support Agreements with Public Entities” in Note 10);

24

•payment in full, with interest at the federal judgment rate, of all pre-petition funded debt obligations, all pre-petition trade claims and all pre-petition employee-related unsecured claims;

•assumption of all power purchase agreements and community choice aggregation servicing agreements;

•assumption of all pension obligations, other employee obligations, and collective bargaining agreements with labor;

•future participation in the state wildfire fund established by AB 1054; and

•satisfaction of the requirements of AB 1054.

The Proposed Plan, as amended, proposes the following key financing sources:

•one or more equity offerings of up to $14 billion, in accordance with the Backstop Commitment Letters (as described below); and

•permanent financing in the form of bank facilities, debt securities or a combination of the foregoing in the amount of $27.35 billion at the Utility and $7.0 billion at PG&E Corporation, which would be in lieu of the Facilities (as described below).

Additional sources of financing are expected to include insurance proceeds in connection with the 2015 Butte fire, 2017 Northern California wildfires and the 2018 Camp fire.

The Proposed Plan, as amended, has not been approved and may be further amended, modified, or supplemented as necessary or desired by PG&E Corporation and the Utility or as required by the Bankruptcy Court or the CPUC.

On September 24, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authority to enter into, and perform under, the RSA and approval of the Subrogation Claims Settlement. Pursuant to that motion, PG&E Corporation and the Utility requested that the allowance of the Subrogation Claims in the aggregate amount of $11.0 billion be effective upon the approval of the motion and that the treatment and satisfaction of the Subrogation Claims be effectuated pursuant to the Proposed Plan following confirmation of the effectiveness of the Proposed Plan. Various stakeholders filed objections to PG&E Corporation's and the Utility's motion, including the UCC, the Ad Hoc Noteholder Committee, the TCC and the U.S. Government. A hearing on PG&E Corporation’s and the Utility’s motion to approve the RSA was held on October 23, 2019, at which the Bankruptcy Court continued the hearing on the motion to November 13, 2019. On November 2, 2019, PG&E Corporation and the Utility filed the RSA, as amended, with the Bankruptcy Court.

Equity Backstop Commitments

As of September 30, 2019, PG&E Corporation has entered into Chapter 11 Plan Backstop Commitment Letters (collectively, the “Backstop Commitment Letters”) with investors (collectively, the “Backstop Parties”), pursuant to which the Backstop Parties severally agreed to fund up to $14.0 billion of proceeds to finance the Proposed Plan through the purchase of PG&E Corporation common stock, subject to the terms and conditions set forth in such Backstop Commitment Letters (the “Backstop Commitments”). The price at which any such new shares would be issued to the Backstop Parties would be equal to (a) 10 (subject to adjustment as provided in the Backstop Commitment Letters), times (b) PG&E Corporation’s consolidated Normalized Estimated Net Income (as defined in the Backstop Commitment Letters) for the estimated year 2021, divided by (c) the number of fully diluted shares of PG&E Corporation that will be outstanding on the effective date of the Proposed Plan (the “Effective Date”) (assuming that all equity is raised by funding the Backstop Commitments).

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The Backstop Commitment Letters provide that, under certain circumstances, PG&E Corporation and the Utility will be permitted to issue new shares of common stock of PG&E Corporation for up to $14.0 billion of proceeds to finance the transactions contemplated by the Proposed Plan through one or more equity offerings that, under certain circumstances, must include a rights offering (the “Rights Offering”). The structure, terms and conditions of any such equity offering (including a Rights Offering) are expected to be determined by PG&E Corporation and the Utility at a later time in the Chapter 11 process, subject to the terms and conditions of the Backstop Commitment Letters. This may include terms and conditions that are designed to preserve the ability of PG&E Corporation or the Utility to utilize their net operating loss carryforwards. There can be no assurance that any such equity offering would be successful. In the event that such equity offerings (together with additional permitted capital sources) do not raise at least $14.0 billion of proceeds in the aggregate or if PG&E Corporation and the Utility do not otherwise consummate such offerings, then PG&E Corporation and the Utility may draw on the Backstop Commitments for equity funding to finance the transactions contemplated by the Proposed Plan, subject to the satisfaction or waiver by the Backstop Parties of the conditions set forth therein.

The Backstop Parties’ funding obligations under the Backstop Commitment Letters are subject to numerous conditions, including, among others, that (a) the Backstop Commitment Letters have been approved by the Bankruptcy Court on or before November 20, 2019, (b) the conditions precedent to the Effective Date set forth in the Proposed Plan have been satisfied or waived in accordance with the Proposed Plan, (c) the Bankruptcy Court has entered an order confirming the Proposed Plan and approving the transactions contemplated thereunder, which shall confirm the Proposed Plan with such amendments, modifications, changes and consents as are approved by holders of a majority of the Backstop Commitments (the “Confirmation Order”), (d) PG&E Corporation’s and the Utility’s weighted average earning rate base for 2021 is no less than 95% of $48 billion and (e) there has been no event, occurrence or other circumstance that would have or would reasonably be expected to have a material adverse effect on the business of PG&E Corporation and the Utility or their ability to consummate the transactions contemplated by the Backstop Commitment Letters and the Proposed Plan. PG&E Corporation intends to seek an extension of the deadline to obtain Bankruptcy Court approval of the Backstop Commitment Letters.

In addition, the Backstop Parties have certain termination rights under the Backstop Commitment Letters. The Backstop Parties may terminate the Backstop Commitment Letters if PG&E Corporation’s and the Utility’s aggregate liability with respect to pre-petition wildfire-related claims exceeds $18.9 billion (the “Wildfire Claims Cap”) (without counting wildfire-related claims that are approved by the CPUC for recovery or pass-through against such cap), which cap may be adjusted upward for wildfire-related claims consisting of professional fees that the Bankruptcy Court (or the U.S. District Court for the Northern District of California (the “District Court”), if applicable) determines to be reasonable. The Backstop Parties’ other termination rights include, among others, if (i) the Proposed Plan is amended without the consent of the holders of a majority of the Backstop Commitments, (ii) the Confirmation Order has not been entered by June 30, 2020, (iii) the Effective Date has not occurred within 60 days of entry of the Confirmation Order, (iv) a material adverse effect (as described above) occurs, (v) wildfires occur in the Utility’s service area in 2019 that damage or destroy in excess of 500 dwellings or commercial structures in the aggregate, (vi) the CPUC fails to issue all necessary approvals, authorizations and final orders to implement the Proposed Plan prior to June 30, 2020, including approvals related to the Utility’s capital structure and authorized rate of return and the resolution of the CPUC’s claims against the Utility for fines or penalties, all of which must be satisfactory to the holders of a majority of the Backstop Commitments, (vii) asserted administrative expense claims in the Chapter 11 Cases exceed $250 million (subject to certain exceptions), (viii) one or more wildfires occur in the Utility’s service area during or after 2020 that damage or destroy at least 500 dwellings or commercial structures in the aggregate at a time when the portion of the Utility’s system at the location of such wildfire was not successfully de-energized, and (ix) the Utility has not elected and received Bankruptcy Court approval, or satisfied the other required conditions, to participate in the statewide wildfire fund established by AB 1054. There can be no assurance that the conditions precedent set forth in the Backstop Commitment Letters will be satisfied or waived, nor that events or circumstances will not occur that give rise to termination rights of the Backstop Parties.

In connection with PG&E Corporation’s and the Utility’s entry into the RSA as described above, if the Bankruptcy Court does not approve the RSA on or prior to November 20, 2019, then the Backstop Commitment Letters provide that (i) the Wildfire Claims Cap will be reduced to $17.9 billion (without counting wildfire-related claims that are approved by the CPUC for recovery or pass-through against such cap), which cap may be adjusted upward for wildfire-related claims consisting of professional fees that the Bankruptcy Court (or the District Court, if applicable) determines to be reasonable, and (ii) the Proposed Plan must be amended to remove any Permitted Amendments (as defined in the Backstop Commitment Letters).

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The initial commitment premium for the Backstop Commitments is 0.75% of the amount of the Backstop Commitments. The initial term of the Backstop Commitment Letters expires on January 20, 2020. PG&E Corporation and the Utility can extend the term of the Backstop Commitment Letters to April 30, 2020 for an additional commitment premium of 1.25% of the amount of the Backstop Commitments, to June 30, 2020 for an additional commitment premium of 2.5% of the amount of the Backstop Commitments and to August 29, 2020 for an additional commitment premium of 0.5% of the amount of the Backstop Commitments. All such commitment premiums are cumulative. Subject to limited exceptions, all commitment premiums are payable in shares of PG&E Corporation common stock to be issued on the Effective Date, and the number of such shares to be paid as commitment premiums will be calculated using the backstop price described above. In the event that a plan of reorganization for PG&E Corporation and the Utility that is not the Proposed Plan is confirmed by the Bankruptcy Court, then the backstop commitment premium will be payable in cash if elected by the applicable Backstop Party.

Debt Commitment Letters

On October 11, 2019, PG&E Corporation and the Utility entered into debt commitment letters (the “Debt Commitment Letters”) with JPMorgan Chase Bank, N.A., Bank of America, N.A., BofA Securities, Inc., Barclays Bank PLC, Citigroup Global Markets Inc., Goldman Sachs Bank USA, Goldman Sachs Lending Partners LLC and the other lenders that may become parties to the Debt Commitment Letters as additional “Commitment Parties” as provided therein (the foregoing parties, collectively, the “Commitment Parties”), pursuant to which the Commitment Parties committed to provide $34.35 billion in bridge financing in the form of (a) a $27.35 billion senior secured bridge loan facility (the “OpCo Facility”) with the Utility or any domestic entity formed to hold all of the assets of the Utility upon emergence from bankruptcy (the Utility or any such entity, the “OpCo Borrower”) as borrower thereunder and (b) a $7.0 billion senior unsecured bridge loan facility (together with the OpCo Facility, the “Facilities”) with PG&E Corporation or any domestic entity formed to hold all of the assets of PG&E Corporation upon emergence from bankruptcy (the Corporation or any such entity, the "HoldCo Borrower") as borrower thereunder, subject to the terms and conditions set forth therein. The commitments under the Debt Commitment Letters will expire on August 29, 2020, unless terminated earlier pursuant to the termination rights described below.

Borrowings under the OpCo Facility would be senior secured obligations of the OpCo Borrower, secured by substantially all of the assets of the OpCo Borrower. Borrowings under the HoldCo Facility would be senior unsecured obligations of the HoldCo Borrower. The OpCo Borrower’s obligations under the OpCo Facility, and the HoldCo Borrower’s obligations under the HoldCo Facility, would not be guaranteed by any other entity. The scheduled maturity of each of the Facilities would be 364 days following the date the Facilities are funded. PG&E Corporation and the Utility will pay customary fees and expenses in connection with obtaining the Facilities.

The Commitment Parties’ funding obligations under the Debt Commitment Letters are subject to numerous conditions and termination rights, including, among others, certain conditions and termination rights similar to those included in the Backstop Commitment Letters, in addition to conditions that are not in the Backstop Commitment Letters, including (a) the delivery of specified financial information, (b) PG&E Corporation’s receipt of at least $14.0 billion of proceeds from the issuance of equity, of which up to $2.0 billion may take the form of preferred equity, equity-linked securities or securitizations to the extent not negatively impacting cash distributions to PG&E Corporation or distributions that will be available to service debt at PG&E Corporation, (c) the execution of definitive documentation for the Facilities and (d) that the Utility shall have received investment grade senior secured debt ratings. In addition, the Debt Commitment Letters are subject to approval by the Bankruptcy Court on or before November 20, 2019, and the Utility’s ability to borrow under the OpCo Facility is subject to approval by the CPUC. PG&E Corporation and the Utility intend to seek an extension of the deadline to obtain Bankruptcy Court approval of the Debt Commitment Letters.

In lieu of entering into the Facilities, PG&E Corporation and the Utility intend to obtain permanent financing on or prior to emergence from bankruptcy in the form of bank facilities, debt securities or a combination of the foregoing.

On October 23, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking approval of the Backstop Commitment Letters, the Debt Commitment Letters and certain related matters. The hearing on PG&E Corporation’s and the Utility’s motion to approve the Backstop Commitment Letters, the Debt Commitment Letters and certain related matters is scheduled for November 19, 2019.

The timing and outcome of the Chapter 11 Cases is uncertain. Although PG&E Corporation, the Utility, the Bankruptcy Court, the CPUC and many other stakeholders have stated that they are working towards confirming a plan of reorganization by June 30, 2020, it is possible that the Chapter 11 process could extend beyond the June 30, 2020 deadline and take a number of years to resolve.

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TCC/Ad Hoc Noteholder Plan of Reorganization

On October 17, 2019, the TCC and the Ad Hoc Noteholder Committee filed the TCC/Ad Hoc Noteholder Plan. The TCC/Ad Hoc Noteholder Plan differs from the Proposed Plan in a number of respects, including, but not limited to:

•the TCC/Ad Hoc Noteholder Plan proposes a trust for payment of wildfire victim claims (other than insurance subrogation claims) funded with consideration in an amount equal to the lesser of (i) $14.5 billion (“at plan value”), of which $1.0 billion would be set aside in a separate trust for the Supporting Public Entities, and (ii) an amount of such claims as determined by a court of competent jurisdiction (with the form of such consideration to be an unspecified mix of cash and PG&E Corporation common stock (“at plan value”));

•the TCC/Ad Hoc Noteholder Plan proposes that holders of claims in respect of certain series of short-term senior notes of the Utility receive consideration consisting of (i) principal and accrued and unpaid pre-petition interest at the contract rate specified in the definitive documentation for each such series, (ii) accrued and unpaid post-petition interest at the contract rate specified in the definitive documentation for each such series and (iii) any prepayment premium, make-whole or other similar call protection specified in the definitive documentation for each such series;

•the TCC/Ad Hoc Noteholder Plan proposes that the Utility’s other senior notes would be reinstated at emergence with holders receiving (i) accrued and unpaid pre-petition interest at the contract rate specified in the definitive documentation for each such series and (ii) accrued and unpaid post-petition interest at the contract rate specified in the definitive documentation for each such series; and

•the TCC/Ad Hoc Noteholder Plan proposes the following significant financing sources: (i) $12.75 billion (“at plan value”) of newly issued PG&E Corporation common stock, representing 40.6% of the post-emergence PG&E Corporation common stock, would be issued to the trust for payment of wildfire victim claims and, if applicable, the trust for payment of insurance subrogation claims; (ii) members of the Ad Hoc Noteholder Committee, and potentially other third parties, would make a $15.5 billion investment in PG&E Corporation common stock, representing 59.3% of the post-emergence PG&E Corporation common stock, in order to fund the transactions contemplated by the TCC/Ad Hoc Noteholder Plan; and (iii) PG&E Corporation would issue $5.75 billion of new senior unsecured notes and the Utility would issue $8.0 billion of new senior secured notes, in each case to certain members of the Ad Hoc Noteholder Committee in order to fund the transactions contemplated by the TCC/Ad Hoc Noteholder Plan.

The TCC/Ad Hoc Noteholder Plan has not been approved by the Bankruptcy Court or the CPUC and may be amended, modified, or supplemented as necessary or desired by the proponents thereof.

Debtor-In-Possession Financing

See Note 5 for further discussion of the DIP Facilities, which provide up to $5.5 billion in financing.

Financial Reporting in Reorganization

Effective on the Petition Date, PG&E Corporation and the Utility began to apply accounting standards applicable to reorganizations, which are applicable to companies under Chapter 11 bankruptcy protection. These accounting standards require the financial statements for periods subsequent to the Petition Date to distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Expenses, realized gains and losses, and provisions for losses that are directly associated with reorganization proceedings must be reported separately as reorganization items, net in the Condensed Consolidated Statements of Income. In addition, the balance sheet must distinguish pre-petition LSTC of PG&E Corporation and the Utility from pre-petition liabilities that are not subject to compromise, post-petition liabilities, and liabilities of the subsidiaries of PG&E Corporation that are not debtors in the Chapter 11 Cases in the Condensed Consolidated Balance Sheets. LSTC are pre-petition obligations that are not fully secured and have at least a possibility of not being repaid at the full claim amount. Where there is uncertainty about whether a secured claim will be paid or impaired pursuant to the Chapter 11 Cases, PG&E Corporation and the Utility have classified the entire amount of the claim as LSTC.

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Furthermore, the realization of assets and the satisfaction of liabilities are subject to uncertainty. While operating as debtors-in-possession, actions to enforce or otherwise effect the payment of certain claims against PG&E Corporation and the Utility in existence before the Petition Date are stayed while PG&E Corporation and the Utility continue business operations as debtors-in-possession. These claims are reflected as LSTC in the Condensed Consolidated Balance Sheets at September 30, 2019. Additional claims (which could be LSTC) may arise after the Petition Date resulting from the rejection of executory contracts, including leases, and from the determination by the Bankruptcy Court (or agreement by parties-in-interest) of allowed claims for contingencies and other disputed amounts.

PG&E Corporation’s Condensed Consolidated Financial Statements are presented on a consolidated basis and include the accounts of PG&E Corporation and the Utility and other subsidiaries of PG&E Corporation and the Utility that individually and in aggregate are immaterial. Such other subsidiaries did not file for bankruptcy.

The Utility’s Condensed Consolidated Financial Statements are presented on a consolidated basis and include the accounts of the Utility and other subsidiaries of the Utility that individually and in aggregate are immaterial. Such other subsidiaries did not file for bankruptcy.

Liabilities Subject to Compromise

As a result of the commencement of the Chapter 11 Cases, the payment of pre-petition liabilities is subject to compromise or other treatment pursuant to a plan of reorganization. Generally, actions to enforce or otherwise effect payment of pre-petition liabilities are stayed. Although payment of pre-petition claims generally is not permitted, the Bankruptcy Court granted PG&E Corporation and the Utility authority to pay certain pre-petition claims in designated categories and subject to certain terms and conditions. This relief generally was designed to preserve the value of PG&E Corporation’s and the Utility’s business and assets. As described above, among other things, the Bankruptcy Court authorized, but did not require, PG&E Corporation and the Utility to pay certain pre-petition claims relating to employee wages and benefits, taxes, and amounts owed to certain vendors.

The determination of how liabilities will ultimately be settled or treated cannot be made until the Bankruptcy Court confirms a Chapter 11 plan of reorganization and such plan becomes effective. Accordingly, the ultimate amount of such liabilities is not determinable at this time. GAAP requires pre-petition liabilities that are subject to compromise to be reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for different amounts. The amounts currently classified as LSTC are preliminary and may be subject to future adjustments depending on Bankruptcy Court actions, further developments with respect to disputed claims, determinations of the secured status of certain claims, the values of any collateral securing such claims, rejection of executory contracts, continued reconciliation or other events.

The following table presents LSTC as reported in the Condensed Consolidated Balance Sheets at September 30, 2019:

(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Financing debt (2)	$	21,813	$	650	$	22,463
Wildfire-related claims (3)	20,560		—		20,560
Trade creditors	1,253		6		1,259
Non-qualified benefit plan	18		126		144
2001 bankruptcy disputed claims	221		—		221
Customer deposits & advances	278		—		278
Other	166		2		168
Total Liabilities Subject to Compromise	$	44,309	$	784	$	45,093

⁽¹⁾ PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.

⁽²⁾ At September 30, 2019, PG&E Corporation and the Utility had $650 million and $21,526 million in aggregate principal amount of pre-petition indebtedness, respectively. Utility pre-petition financing debt also includes $287 million of accrued contractual interest to the Petition Date. See Note 5 for details of pre-petition debt reported as LSTC.

⁽³⁾ See Note 10 for information regarding pre-petition wildfire-related claims reported as LSTC, including the settlement with the Consenting Subrogation Creditors entered into on September 22, 2019. Wildfire-related claims include amounts for the Butte fire of $212 million and is shown net of $100 million deposited into the Wildfire Assistance Fund on August 2, 2019 in connection with potential liabilities related to the 2018 Camp fire and 2017 Northern California wildfires.

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Potential Claims

PG&E Corporation and the Utility have filed with the Bankruptcy Court schedules and statements of financial affairs setting forth, among other things, the assets and liabilities of PG&E Corporation and the Utility, subject to the assumptions filed in connection therewith. As a general matter, claims against PG&E Corporation or the Utility relating to the period prior to the Petition Date must be filed by the Bar Date. See above under the heading “Bar Date” for a discussion of the Bar Date.

PG&E Corporation and the Utility have received a substantial number of proofs of claim since the Petition Date and are early in the process of reconciling those claims to the amounts listed in the schedules of assets and liabilities. PG&E Corporation and the Utility may ask the Bankruptcy Court to disallow claims that they believe are duplicative, have been later amended or superseded, are without merit, are overstated or should be disallowed for other reasons. Given the substantial number and amount of claims filed, the claims resolution process will take considerable time to complete. As a result of the agreement between PG&E Corporation and the Utility and the TCC to extend the Bar Date for individual wildfire-related claims and if approved by the Bankruptcy Court, the number and amount of claims filed may continue to grow, which may further increase the time the claims resolution process will take to complete. Differences between liability amounts recorded by PG&E Corporation and the Utility as liabilities subject to compromise and claims filed by creditors will be investigated and, if necessary, the Bankruptcy Court will make a final determination of the allowed amount of the claim. Differences between those final allowed claims and the liabilities recorded in the Condensed Consolidated Balance Sheet will be recognized as reorganization items in PG&E Corporation’s and the Utility’s Condensed Statement of Consolidated Income (Loss) as they are resolved. The determination of how liabilities will ultimately be resolved cannot be made until the Bankruptcy Court approves a plan of reorganization or approves orders related to settlement of specific liabilities. Accordingly, the ultimate amount or resolution of such liabilities is not determinable at this time. The resolution of such claims could result in substantial adjustments to PG&E Corporation’s and the Utility’s financial statements.

Reorganization Items, Net

Reorganization items, net represent amounts incurred after the Petition Date as a direct result of the Chapter 11 Cases and are comprised of professional fees and financing costs, net of interest income. Reorganization items also include adjustments to reflect the carrying value of LSTC at their estimated allowed claim amounts, as such adjustments are approved by the Bankruptcy Court.  Cash paid for reorganization items, net was $13 million and $145 million for PG&E Corporation and the Utility, respectively, during the nine months ended September 30, 2019. Reorganization items, net for the three months ended September 30, 2019 and from the Petition Date through September 30, 2019 include the following:

	Three Months Ended September 30, 2019
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	—	$	—	$	—
Legal and other	83		7		90
Interest income	(14)		(3)		(17)
Adjustments to LSTC	—		—		—
Total reorganization items, net	$	69	$	4	$	73

⁽¹⁾ PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.

	Petition Date Through September 30, 2019
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	97	$	17	$	114
Legal and other	181		10		191
Interest income	(41)		(8)		(49)
Adjustments to LSTC	—		—		—
Total reorganization items, net	$	237	$	19	$	256

⁽¹⁾ PG&E Corporation amounts reflected under the column “PG&E Corporation” exclude the accounts of the Utility.

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Contractual Interest on Debt Subject to Compromise

Effective as of the Petition Date, PG&E Corporation and the Utility ceased recording interest expense on outstanding pre-petition debt. Contractual interest expense represents amounts due under the contractual terms of outstanding pre-petition debt. From the Petition Date through September 30, 2019, contractual interest expense of $666 million related to LSTC has not been recorded in the financial statements. The portion of authorized revenues from the Petition Date through September 30, 2019 related to interest expense on pre-petition debt has been deferred as a noncurrent regulatory liability.

The Bankruptcy Court’s Decision on its Authority over PG&E Corporation’s and the Utility’s Rejection of Power Purchase Agreements

On June 7, 2019, the Bankruptcy Court granted PG&E Corporation’s and the Utility’s motion for declaratory judgment in an adversary proceeding entitled Pacific Gas and Electric Company v. FERC.  In its amended declaratory judgment, the Bankruptcy Court found that FERC had no “concurrent jurisdiction, or any jurisdiction, over the determination of whether any rejections of power purchase contracts by either Debtor should be authorized” pursuant to section 365 of the Bankruptcy Code.  The Bankruptcy Court also found that the “Debtors do not need approval from the Federal Energy Regulatory Commission to reject any of their power purchase contracts” and that “[a]ny determinations of the Federal Energy Regulatory Commission” that were contrary to these findings “are void, of no force and effect and not binding on this court or either Debtor.”  The Bankruptcy Court further stated that such determinations include, but are not limited to, those previously made in certain FERC proceedings initiated before the Chapter 11 Cases were filed in connection with power purchase contracts with the Utility (the “FERC Orders”).

On June 12, 2019, the Bankruptcy Court certified its amended declaratory judgment for direct appeal to the United States Court of Appeals for the Ninth Circuit.  On July 15, 2019, FERC and certain counterparties to the Utility’s power purchase agreements filed requests for the Ninth Circuit to permit such direct appeal, which the Ninth Circuit granted on September 17, 2019. On September 17, 2019, the Ninth Circuit granted the requests and docketed both appeals. Opening briefs of FERC and the other appellants are due November 20, 2019, PG&E Corporation’s and the Utility’s answering briefs are due December 20, 2019, and optional reply briefs are due 21 days after service of PG&E Corporation’s and the Utility’s answering briefs. Separately, on June 26, 2019, the Utility filed a petition for review of the FERC Orders, also in the Ninth Circuit. On September 20, 2019, the Ninth Circuit granted the Utility’s motion to align the briefing schedule with the direct appeals from the Bankruptcy Court. The Utility’s and petitioner-intervenor’s opening briefs are due November 20, 2019. FERC’s and respondent-intervenors’ answering briefs are due December 20, 2019, and the Utility’s optional reply brief is due 21 days after service of FERC’s answering brief.

The Proposed Plan proposes to assume all power purchase agreements and community choice aggregation servicing agreements.

Resolution of Remaining 2001 Chapter 11 Disputed Claims

Various electricity suppliers filed claims in the Utility’s 2001 prior 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 pursued settlements with electricity suppliers and 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, in some instances, would be 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.

The Utility’s obligations with respect to such claims (all of which arose prior to the initiation of the Utility’s pending Chapter 11 Case on January 29, 2019), including pursuant to any prior settlements relating thereto, are expected to be determined through the proceedings of the Chapter 11 Cases.

NOTE 3: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

For a summary of the significant accounting policies used by PG&E Corporation and the Utility, see Note 2 of the Condensed Consolidated Financial Statements above for bankruptcy-related policies and Note 2 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K.

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Disallowance of Plant Costs

PG&E Corporation and the Utility 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 charged to customers and the amount of disallowance can be reasonably estimated.

In the three and nine months ended September 30, 2019, PG&E Corporation and the Utility recorded $237 million for pipeline-replacement costs disallowed in the 2019 GT&S rate case as a result of spending above amounts authorized in the 2015-2018 rate case period.

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, 2019, 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, 2019, it did not consolidate any of them.

Pension and Other 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, 2019 and 2018 were as follows:

	Pension Benefits				Other Benefits
	Three Months Ended September 30,
(in millions)	2019		2018		2019		2018
Service cost for benefits earned (1)	$	110	$	128	$	14	$	16
Interest cost	189		171		19		17
Expected return on plan assets	(226)		(255)		(31)		(33)
Amortization of prior service cost	(1)		(1)		3		4
Amortization of net actuarial loss	1		1		—		(1)
Net periodic benefit cost	73		44		5		3
Regulatory account transfer (2)	10		41		—		—
Total	$	83	$	85	$	5	$	3

⁽¹⁾ A portion of service costs are capitalized pursuant to ASU 2017-07.

⁽²⁾ The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.

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	Pension Benefits				Other Benefits
	Nine Months Ended September 30,
(in millions)	2019		2018		2019		2018
Service cost for benefits earned (1)	$	332	$	385	$	42	$	49
Interest cost	568		515		57		52
Expected return on plan assets	(679)		(766)		(92)		(98)
Amortization of prior service cost	(4)		(4)		10		11
Amortization of net actuarial loss	2		4		(2)		(4)
Net periodic benefit cost	219		134		15		10
Regulatory account transfer (2)	31		118		—		—
Total	$	250	$	252	$	15	$	10

⁽¹⁾ A portion of service costs are capitalized pursuant to ASU 2017-07.

⁽²⁾ The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.

Non-service costs are reflected in Other income, net on the Condensed Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Condensed Consolidated Statements of Income.

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

On February 27, 2019, PG&E Corporation and the Utility received final approval from the Bankruptcy Court to maintain existing pension and other benefit plans, other than the non-qualified pension plan, during the pendency of the Chapter 11 Cases.

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 Benefits		Other Benefits		Total
(in millions, net of income tax)	Three Months Ended September 30, 2019
Beginning balance	$	(21)	$	17	$	(4)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $0 and $1, respectively)	(1)		2		1
Amortization of net actuarial loss (net of taxes of $0 and $0, respectively)	1		—		1
Regulatory account transfer (net of taxes of $0 and $1, respectively)	—		(2)		(2)
Net current period other comprehensive gain (loss)	—		—		—
Ending balance	$	(21)	$	17	$	(4)

⁽¹⁾ These components are included in the computation of net periodic pension and other post-retirement benefit costs.  (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)

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	Pension Benefits		Other Benefits		Total
(in millions, net of income tax)	Three Months Ended September 30, 2018
Beginning balance	$	(30)	$	17	$	(13)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $0 and $1, respectively)	(1)		3		2
Amortization of net actuarial loss (net of taxes of $0, and $0, respectively)	1		(1)		—
Regulatory account transfer (net of taxes of $0 and $1, respectively)	1		(2)		(1)
Net current period other comprehensive gain (loss)	1		—		1
Ending balance	$	(29)	$	17	$	(12)

⁽¹⁾ These components are included in the computation of net periodic pension and other post-retirement benefit costs.  (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)

	Pension Benefits		Other Benefits		Total
(in millions, net of income tax)	Nine Months Ended September 30, 2019
Beginning balance	$	(21)	$	17	$	(4)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1 and $3, respectively)	(3)		7		4
Amortization of net actuarial loss (net of taxes of $0 and $1, respectively)	2		(1)		1
Regulatory account transfer (net of taxes of $1 and $2, respectively)	1		(6)		(5)
Net current period other comprehensive gain (loss)	—		—		—
Ending balance	$	(21)	$	17	$	(4)

⁽¹⁾ These components are included in the computation of net periodic pension and other post-retirement benefit costs.  (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)

	Pension Benefits		Other Benefits		Total
(in millions, net of income tax)	Nine Months Ended September 30, 2018
Beginning balance	$	(25)	$	17	$	(8)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1 and $3, respectively)	(3)		8		5
Amortization of net actuarial loss (net of taxes of $1 and $1, respectively)	3		(3)		—
Regulatory account transfer (net of taxes of $0 and $2, respectively)	1		(5)		(4)
Reclassification of stranded income tax to retained earnings	(5)		—		(5)
Net current period other comprehensive gain (loss)	(4)		—		(4)
Ending balance	$	(29)	$	17	$	(12)

⁽¹⁾ These components are included in the computation of net periodic pension and other post-retirement benefit costs.  (See the “Pension and Other Post-Retirement Benefits” table above for additional details.)

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

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Revenue Recognition

Revenue from Contracts with Customers

The Utility recognizes revenues when electricity and natural gas services are delivered.  The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period.  Unbilled revenues are included in accounts receivable on the Condensed Consolidated Balance Sheets.  Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.

Regulatory Balancing Account Revenue

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and its GT&S rate case, which generally occur every three or four years.  The Utility’s ability to recover revenue requirements authorized by the CPUC in these rate cases is independent, or “decoupled,” from the volume of the Utility’s sales of electricity and natural gas services.  The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months.  Generally, electric and natural gas operating revenue is recognized ratably over the year.  The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.

The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs.  In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income.

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The following table presents the Utility’s revenues disaggregated by type of customer:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2019		2018		2019		2018
Electric
Revenue from contracts with customers
Residential	$	1,557	$	1,649	$	3,839	$	4,023
Commercial	1,481		1,430		3,568		3,737
Industrial	466		448		1,085		1,126
Agricultural	496		523		844		966
Public street and highway lighting	17		18		50		55
Other (1)	(82)		(273)		(391)		(388)
Total revenue from contracts with customers - electric	3,935		3,795		8,995		9,519
Regulatory balancing accounts (2)	(381)		(328)		297		211
Total electric operating revenue	$	3,554	$	3,467	$	9,292	$	9,730
Natural gas
Revenue from contracts with customers
Residential	$	249	$	242	$	1,764	$	1,652
Commercial	92		87		461		402
Transportation service only	264		287		950		847
Other (1)	(98)		30		(303)		(149)
Total revenue from contracts with customers - gas	507		646		2,872		2,752
Regulatory balancing accounts (2)	371		269		222		190
Total natural gas operating revenue	878		915		3,094		2,942
Total operating revenues	$	4,432	$	4,382	$	12,386	$	12,672

⁽¹⁾ This activity is primarily related to the change in unbilled revenue, partially offset by other miscellaneous revenue items.

⁽²⁾ These amounts represent revenues authorized to be billed or refunded to customers.

Recently Adopted Accounting Standards

Recognition of Lease Assets and Liabilities

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amended the guidance related to the definition of a lease, the recognition of lease assets and liabilities, and the disclosure of key information about leasing arrangements. Under the new standard, a lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility adopted the ASU for leases on January 1, 2019.

PG&E Corporation and the Utility elected certain practical expedients and will carry forward historical conclusions related to (1) contracts that contain leases, (2) existing lease and easement classification, and (3) initial direct costs. After adoption of the new standard, PG&E Corporation and Utility elected not to separate lease and non-lease components. Additionally, PG&E Corporation and the Utility will not restate comparative reporting periods.

The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates, unless the implicit discount rate in the leasing arrangement can be ascertained. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense in conformity with ratemaking.

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Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Condensed Consolidated Balance Sheets. Finance leases are included in property, plant, and equipment, other current liabilities, and other noncurrent liabilities on the Condensed Consolidated Balance Sheets. Financing leases were immaterial for the nine months ended September 30, 2019.

On January 1, 2019, PG&E Corporation and the Utility recorded ROU assets and lease liabilities of $2.8 billion, representing the net present value of only the fixed lease payments. This amount is presented within the supplemental disclosures of noncash activities. For the nine months ended September 30, 2019, the Utility made total cash payments, including fixed and variable, of $1.79 billion for operating leases which are presented within operating activities on the Condensed Consolidated Statement of Cash Flows. The fixed cash payments for the principal portion of the financing lease liabilities are immaterial and continue to be included within financing activities on the Condensed Consolidated Statement of Cash Flows. Any variable lease payments for financing leases are included in operating activities on the Condensed Consolidated Statement of Cash Flows.

The majority of the Utility’s ROU assets and lease liabilities relate to various power purchase agreements. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land arrangements.

At September 30, 2019, the Utility’s leases had a weighted average remaining lease term of 6.1 years and a weighted average discount rate of 6.1%.

The following table shows the lease expense recognized for the fixed and variable component of the Utility’s lease obligations:

(in millions)	Three Months Ended September 30, 2019		Nine Months Ended September 30, 2019
Operating lease fixed cost	$	266	$	502
Operating lease variable cost	669		1,468
Total operating lease costs	$	935	$	1,970

The following table shows the Utility’s future expected operating lease payments:

(in millions)	September 30, 2019
2019 (1)	$	184
2020	679
2021	623
2022	548
2023	255
2024	96
Thereafter	596
Total lease payments	2,981
Less imputed interest	(554)
Total	$	2,427

⁽¹⁾ Represents the remaining expected operating lease payments from October 1, 2019 through December 31, 2019.

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The following table shows the Utility’s future expected obligations for power purchase and other lease commitments:

(in millions)	December 31, 2018
2019	$	684
2020	677
2021	621
2022	546
2023	252
Thereafter	581
Total lease commitments	$	3,361

Accounting Standards Issued But Not Yet Adopted

Fair Value Measurement

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurements, which amends the existing guidance relating to the disclosure requirements for fair value measurements. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.

Intangibles—Goodwill and Other

In August 2018, the FASB issued ASU No. 2018-15, Intangibles – Goodwill and Other – Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact of the guidance on their Condensed Consolidated Financial Statements and related disclosures.

Financial Instruments—Credit Losses

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326), which provides a model, known as the current expected credit loss model, to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2020. PG&E Corporation and the Utility are currently evaluating the impact of the guidance on their Condensed Consolidated Financial Statements and related disclosures.

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NOTE 4: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets and Liabilities

Long-Term Regulatory Assets

Long-term regulatory assets are comprised of the following:

	Asset Balance at
(in millions)	September 30, 2019		December 31, 2018
Pension benefits (1)	$	1,918	$	1,947
Environmental compliance costs	1,067		1,013
Utility retained generation (2)	239		274
Price risk management	140		90
Unamortized loss, net of gain, on reacquired debt	66		76
Catastrophic event memorandum account (3)	954		790
Wildfire expense memorandum account (4)	143		94
Fire hazard prevention memorandum account (5)	294		263
Fire risk mitigation memorandum account (6)	109		—
Wildfire mitigation plan memorandum account (7)	160		—
Deferred income taxes (8)	94		—
Other (9)	527		417
Total long-term regulatory assets	$	5,711	$	4,964

⁽¹⁾ Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.

⁽²⁾ In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets.  The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized. 

⁽³⁾ Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. Recovery of CEMA costs are subject to CPUC review and approval.

⁽⁴⁾ Includes specific incremental wildfire-related liability costs the CPUC approved for tracking in June 2018. Recovery of WEMA costs are subject to CPUC review and approval.

⁽⁵⁾ Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs are subject to CPUC review and approval.

⁽⁶⁾ Includes costs associated with the 2019 Wildfire Mitigation Plan for the period January 1, 2019 through June 4, 2019. Recovery of FRMMA costs are subject to CPUC review and approval.

⁽⁷⁾ Includes costs associated with the 2019 Wildfire Mitigation Plan for the period June 5, 2019 through September 30, 2019. Recovery of WMPMA costs are subject to CPUC review and approval.

⁽⁸⁾ Represents cumulative differences between amounts recognized for ratemaking purposes and expense recognized in accordance with GAAP.

⁽⁹⁾ September 30, 2019 balance includes $178 million of unamortized debt issuance costs and debt discount that was written off in March 2019 to present the debt subject to compromise at the outstanding face value.

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Long-Term Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Liability Balance at
(in millions)	September 30, 2019		December 31, 2018
Cost of removal obligations (1)	$	6,341	$	5,981
Deferred income taxes	—		283
Recoveries in excess of AROs (3)	462		356
Public purpose programs (4)	802		674
Employee benefit plans (5)	428		421
Other	1,303		824
Total long-term regulatory liabilities	$	9,336	$	8,539

⁽¹⁾ Represents the cumulative differences between the recorded costs to remove assets and amounts collected in rates for expected costs to remove assets.

⁽²⁾ Represents the cumulative differences between ARO expenses and amounts collected in rates.  Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts.  This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments.  (See Note 9 below.)

⁽³⁾ Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.

⁽⁴⁾ Represents cumulative differences between incurred costs and amounts collected in rates for Post-Retirement Medical, Post-Retirement Life and Long Term Disability Plans.

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K.

Regulatory Balancing Accounts

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

	Receivable Balance at
(in millions)	September 30, 2019		December 31, 2018
Electric distribution	$	148	$	160
Electric transmission	43		128
Utility generation	93		79
Gas distribution and transmission	454		462
Energy procurement	739		168
Public purpose programs	137		111
Other	305		327
Total regulatory balancing accounts receivable	$	1,919	$	1,435

	Payable Balance at
(in millions)	September 30, 2019		December 31, 2018
Electric transmission	$	125	$	134
Gas distribution and transmission	24		9
Energy procurement	545		59
Public purpose programs	612		587
Other	349		287
Total regulatory balancing accounts payable	$	1,655	$	1,076

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K.

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NOTE 5: DEBT

Debtor-In-Possession Facilities

In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement, among the Utility, as borrower, PG&E Corporation, as guarantor, JPMorgan Chase Bank, N.A., as administrative agent, Citibank, N.A., as collateral agent, and the lenders and issuing banks party thereto (together with such other financial institutions from time to time party thereto, the “DIP Lenders”). The DIP Credit Agreement provides for $5.5 billion in senior secured superpriority debtor in possession credit facilities in the form of (i) a revolving credit facility in an aggregate amount of $3.5 billion (the “DIP Revolving Facility”), including a $1.5 billion letter of credit subfacility, (ii) a term loan facility in an aggregate principal amount of $1.5 billion (the “DIP Initial Term Loan Facility”) and (iii) a delayed draw term loan facility in an aggregate principal amount of $500 million (the “DIP Delayed Draw Term Loan Facility,” together with the DIP Revolving Facility and the DIP Initial Term Loan Facility, the “DIP Facilities”), subject to the terms and conditions set forth therein. The DIP Credit Agreement also provides for up to $4.0 billion of incremental facilities in the form of (i) one or more additional tranches of term loans or (ii) one or more increases in the aggregate amount of revolving commitments under the DIP Revolving Facility (together, the “Incremental Facilities”), subject to the terms and conditions set forth therein. The Incremental Facilities are uncommitted and would require approval from the Bankruptcy Court.

On the Petition Date, PG&E Corporation and the Utility filed a motion seeking, among other things, interim and final approval of the DIP Facilities, which motion was granted on an interim basis by the Bankruptcy Court following a hearing on January 31, 2019. As a result of the Bankruptcy Court’s interim approval of the DIP Facilities and the satisfaction of the other conditions thereof, the DIP Credit Agreement became effective on February 1, 2019 and a portion of the DIP Revolving Facility in the amount of $1.5 billion (including $750 million of the letter of credit subfacility) was made available to the Utility. On March 27, 2019, the Bankruptcy Court approved the DIP Facilities on a final basis, authorizing the Utility to borrow up to the remainder of the DIP Revolving Facility (including the remainder of the $1.5 billion letter of credit subfacility), the DIP Initial Term Loan Facility and the DIP Delayed Draw Term Loan Facility, in each case subject to the terms and conditions of the DIP Credit Agreement.

Borrowings under the DIP Facilities are senior secured obligations of the Utility, secured by substantially all of the Utility’s assets and entitled to superpriority administrative expense claim status in the Utility’s Chapter 11 Case. The Utility’s obligations under the DIP Facilities are guaranteed by PG&E Corporation, and such guarantee is a senior secured obligation of PG&E Corporation, secured by substantially all of PG&E Corporation’s assets and entitled to superpriority administrative expense claim status in PG&E Corporation’s Chapter 11 Case.

On February 1, 2019, the Utility borrowed $350 million under the DIP Revolving Facility. On April 3, 2019, following the Bankruptcy Court’s final approval of the DIP Facilities, the Utility borrowed $1.5 billion under the DIP Initial Term Loan Facility and repaid the $350 million outstanding under the DIP Revolving Facility.

The commencement of the Chapter 11 Cases constituted an event of default or termination event with respect to, and caused an automatic and immediate acceleration of the debt outstanding under or in respect of, certain instruments and agreements relating to direct financial obligations of PG&E Corporation and the Utility (the “Accelerated Direct Financial Obligations”). However, any efforts to enforce such payment obligations are automatically stayed as of the Petition Date, and are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The material Accelerated Direct Financial Obligations include the Utility’s outstanding senior notes, agreements in respect of certain series of pollution control bonds, and PG&E Corporation’s term loan facility, as well as short-term borrowings under PG&E Corporation’s and the Utility’s revolving credit facilities and the Utility’s term loan facility. For more information, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K.

Debtor-in-Possession Financing

The following table summarizes the Utility’s outstanding borrowings and availability under the DIP Facilities at September 30, 2019:

(in millions)	Termination Date		Aggregate Limit		Term Loan Borrowings		Revolver Borrowings		Letters of Credit Outstanding		Aggregate Availability
DIP Facilities	December 2020	(1)	$	5,500	$	1,500	$	—	$	599	$	3,401

⁽¹⁾ May be extended to December 2021, subject to satisfaction of certain terms and conditions, including payment of a 25 basis point extension fee.

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As of September 30, 2019, PG&E Corporation and the Utility each had no commercial paper borrowings outstanding. PG&E Corporation and the Utility do not expect to be able to access the commercial paper market for the duration of the Chapter 11 Cases.

Debt

The following table summarizes PG&E Corporation’s and the Utility’s outstanding debt subject to compromise:

		Balance at
(in millions)	Contractual Interest Rates	September 30, 2019		December 31, 2018
Debt Subject to Compromise (1)
PG&E Corporation
Borrowings under Pre-Petition Credit Facility
PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022	variable rate (2)	$	300	$	300
Other borrowings
Term Loan - Stated Maturity: 2020	variable rate (3)	350		350
Total PG&E Corporation Debt Subject to Compromise		650		650
Utility
Senior Notes - Stated Maturity:
2020	3.50%	800		800
2021	3.25% to 4.25%	550		550
2022	2.45%	400		400
2023	3.25% to 4.25%	1,175		1,175
2024 through 2047	2.95% to 6.35%	14,600		14,600
Unamortized discount, net of premium and debt issuance costs		—		(178)
Total Senior notes, net of premium and debt issuance costs		17,525		17,347
Pollution Control Bonds - Stated Maturity:
Series 2008 F and 2010 E, due 2026 (4)	1.75%	100		100
Series 2009 A-B, due 2026 (5)	variable rate (6)	149		149
Series 1996 C, E, F, 1997 B due 2026 (5)	variable rate (7)	614		614
Total pollution control bonds		863		863
Borrowings under Pre-Petition Credit Facilities
Utility Revolving Credit Facilities - Stated Maturity: 2022 (8)	variable rate (9)	2,888		2,965
Other borrowings:
Term Loan - Stated Maturity: 2019	variable rate (10)	250		250
Total Borrowings under Pre-Petition Credit Facility Subject to Compromise		3,138		3,215
Total Utility Debt Subject to Compromise		21,526		21,425
Total PG&E Corporation Consolidated Debt Subject to Compromise		$	22,176	$	22,075

⁽¹⁾ Debt subject to compromise must be reported at the amounts expected to be allowed by the Bankruptcy Court and the carrying values will be adjusted as claims are approved. Total Utility Debt Subject to Compromise does not include $287 million of accrued contractual interest to the Petition Date. At March 31, 2019, PG&E Corporation and the Utility wrote off $178 million of unamortized debt issuance costs and debt discount to present the debt subject to compromise at the outstanding face value. The write-offs are included within long-term regulatory assets in the Condensed Consolidated Balance Sheets. See Notes 2 and 4 for further details.

⁽²⁾ At September 30, 2019, the contractual LIBOR-based interest rate on loans was 3.49%.

⁽³⁾ At September 30, 2019, the contractual LIBOR-based interest rate on the term loan was 3.22%.

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⁽⁴⁾ Pollution Control Bonds series 2008F and 2010E were reissued in June 2017.  Although the stated maturity date for both series is 2026, these bonds have a mandatory redemption date of May 31, 2022.

⁽⁵⁾ Each series of these bonds is supported by a separate direct-pay letter of credit. Following the Utility’s Chapter 11 filing, investors in these bonds drew on the letter of credit facilities. The letter of credit facility supporting the Series 2009 A-B bonds matured on June 5, 2019. In December 2015, the maturity dates of the letter of credit facilities supporting the Series 1996 C, E, F, 1997 B bonds were extended to December 1, 2020. Although the stated maturity date of these bonds is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility.

⁽⁶⁾ At September 30, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds was 8.20%.

⁽⁷⁾ At September 30, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds ranged from 8.20% to 8.33%.

⁽⁸⁾ At September 30, 2019, excludes $23 million of undrawn letters of credit.

⁽⁹⁾ At September 30, 2019, the contractual LIBOR-based interest rate on the loans was 3.29%.

⁽¹⁰⁾ At September 30, 2019, the contractual LIBOR-based interest rate on the term loan was 2.62%.

Debt Commitments

See “Plan of Reorganization, RSA, Equity Backstop Commitments and Debt Commitments Letters” in Note 2 of the Condensed Consolidated Financial Statements above for discussion of the debt commitments.

NOTE 6: EQUITY

There were no issuances under the PG&E Corporation February 2017 equity distribution agreement for the nine months ended September 30, 2019.

PG&E Corporation issued common stock under the PG&E Corporation 401(k) plan and share-based compensation plans.  During the nine months ended September 30, 2019, 8.9 million shares were issued for cash proceeds of $85 million under these plans. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation.

Dividends

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018, due to the uncertainty related to the causes of and potential liabilities associated with the Northern California wildfires. See Wildfire-related Contingencies in Note 10 below.

The DIP Credit Agreement includes usual and customary covenants for debtor-in-possession loan agreements of this type, including covenants limiting PG&E Corporation’s and the Utility’s ability to, among other things, declare and pay any dividend or make any other distributions with respect to any of their capital stock. Also, on April 3, 2019, the court overseeing the Utility’s probation issued an order imposing new conditions of probation, including foregoing issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements” under applicable law and the Utility’s wildfire mitigation plan. PG&E Corporation does not expect to pay any cash dividends during the Chapter 11 Cases.

Equity Backstop Commitments

See “Plan of Reorganization, RSA, Equity Backstop Commitments and Debt Commitment Letters” in Note 2 of the Condensed Consolidated Financial Statements above for discussion of the equity backstop commitments.

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NOTE 7: EARNINGS PER SHARE

PG&E Corporation’s basic EPS are 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 September 30,				Nine Months Ended September 30,
(in millions, except per share amounts)	2019		2018		2019		2018
Income (Loss) attributable to common shareholders	$	(1,619)	$	564	$	(4,039)	$	22
Weighted average common shares outstanding, basic	529		517		528		516
Add incremental shares from assumed conversions:
Employee share-based compensation	—		—		—		1
Weighted average common shares outstanding, diluted	529		517		528		517
Total income (loss) per common share, diluted	$	(3.06)	$	1.09	$	(7.65)	$	0.04

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 8: DERIVATIVES

Use of Derivative Instruments

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities.  Procurement costs are recovered through customer rates.  The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices.  Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.  By order dated April 8, 2019, the Bankruptcy Court authorized the Utility to continue these programs in the ordinary course of business in a manner consistent with its pre-petition practices.

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

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover in rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.

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

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Volume of Derivative Activity

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

		Contract Volume at
Underlying Product	Instruments	September 30, 2019	December 31, 2018
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	186,320,892	177,750,349
	Options	32,310,000	13,735,405
Electricity (Megawatt-hours)	Forwards, Futures and Swaps	8,270,404	3,833,490
	Congestion Revenue Rights (3)	316,273,308	340,783,089

⁽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, 2019, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other	$	46	$	—	$	41	$	87
Other noncurrent assets – other	170		—		—		170
Current liabilities – other	(29)		—		3		(26)
Noncurrent liabilities – other	(140)		—		1		(139)
Total commodity risk	$	47	$	—	$	45	$	92

At December 31, 2018, the Utility’s outstanding derivative balances were as follows:

	Commodity Risk
(in millions)	Gross Derivative Balance		Netting		Cash Collateral		Total Derivative Balance
Current assets – other	$	44	$	(1)	$	89	$	132
Other noncurrent assets – other	165		—		—		165
Current liabilities – other	(29)		1		7		(21)
Noncurrent liabilities – other	(90)		—		2		(88)
Total commodity risk	$	90	$	—	$	98	$	188

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 instruments, including power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. During the first quarter of 2019, multiple credit rating agencies downgraded the Utility’s credit ratings below investment grade, which resulted in the Utility posting additional collateral. As of September 30, 2019, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk related contingency features.

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NOTE 9: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, trust assets, and price risk management instruments at fair value.  A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:

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

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

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

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

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

	Fair Value Measurements
	September 30, 2019
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	2,687	$	—	$	—	$	—	$	2,687
Nuclear decommissioning trusts
Short-term investments	17		—		—		—		17
Global equity securities	1,913		—		—		—		1,913
Fixed-income securities	876		738		—		—		1,614
Assets measured at NAV	—		—		—		—		19
Total nuclear decommissioning trusts (2)	2,806		738		—		—		3,563
Price risk management instruments (Note 8)
Electricity	—		3		201		27		231
Gas	—		12		—		14		26
Total price risk management instruments	—		15		201		41		257
Rabbi trusts
Fixed-income securities	—		100		—		—		100
Life insurance contracts	—		74		—		—		74
Total rabbi trusts	—		174		—		—		174
Long-term disability trust
Short-term investments	5		—		—		—		5
Assets measured at NAV	—		—		—		—		140
Total long-term disability trust	5		—		—		—		145
TOTAL ASSETS	$	5,498	$	927	$	201	$	41	$	6,826
Liabilities:
Price risk management instruments (Note 8)
Electricity	$	—	$	—	$	167	$	(4)	$	163
Gas	—		2		—		—		2
TOTAL LIABILITIES	$	—	$	2	$	167	$	(4)	$	165

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

⁽²⁾ Represents amount before deducting $502 million, primarily related to deferred taxes on appreciation of investment value.

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	Fair Value Measurements
	December 31, 2018
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	1,593	$	—	$	—	$	—	$	1,593
Nuclear decommissioning trusts
Short-term investments	29		—		—		—		29
Global equity securities	1,793		—		—		—		1,793
Fixed-income securities	661		639		—		—		1,300
Assets measured at NAV	—		—		—		—		16
Total nuclear decommissioning trusts (2)	2,483		639		—		—		3,138
Price risk management instruments (Note 8)
Electricity	—		5		203		51		259
Gas	—		1		—		37		38
Total price risk management instruments	—		6		203		88		297
Rabbi trusts
Fixed-income securities	—		93		—		—		93
Life insurance contracts	—		67		—		—		67
Total rabbi trusts	—		160		—		—		160
Long-term disability trust
Short-term investments	7		—		—		—		7
Assets measured at NAV	—		—		—		—		155
Total long-term disability trust	7		—		—		—		162
TOTAL ASSETS	$	4,083	$	805	$	203	$	88	$	5,350
Liabilities:
Price risk management instruments (Note 8)
Electricity	$	4	$	5	$	108	$	(10)	$	107
Gas	—		2		—		—		2
TOTAL LIABILITIES	$	4	$	7	$	108	$	(10)	$	109

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

⁽²⁾ Represents amount before deducting $408 million, primarily related to deferred taxes on appreciation of investment value.

Valuation Techniques

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.  There are no restrictions on the terms and conditions upon which the investments may be redeemed.  Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period.  There were no material transfers between any levels for the three and nine months ended September 30, 2019 and 2018.

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.

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Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities.  U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets.  A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences.  Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads.  The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

Assets Measured at NAV Using Practical Expedient

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

Price Risk Management Instruments

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. 

Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model.  Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1.  Over-the-counter forwards and swaps that are identical to exchange-traded futures, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2.  Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. 

Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3.  These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available.  Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market.  Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices.  CRRs are classified as Level 3.

Level 3 Measurements and Sensitivity Analysis

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

Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively.  All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments.  (See Note 8 above.)

	Fair Value at
(in millions)	September 30, 2019
Fair Value Measurement	Assets		Liabilities		Valuation Technique	Unobservable Input	Range (1)
Congestion revenue rights	$	190	$	60	Market approach	CRR auction prices	(15.62) - 9.48
Power purchase agreements	$	11	$	107	Discounted cash flow	Forward prices	13.28 - 62.12

 ⁽¹⁾ Represents price per megawatt-hour.

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	Fair Value at
(in millions)	December 31, 2018
Fair Value Measurement	Assets		Liabilities		Valuation Technique	Unobservable Input	Range (1)
Congestion revenue rights	$	203	$	75	Market approach	CRR auction prices	$ (18.61) - 32.26
Power purchase agreements	$	—	$	33	Discounted cash flow	Forward prices	$ 19.81 - 38.80

⁽¹⁾ Represents price per megawatt-hour.

Level 3 Reconciliation

The following tables present the reconciliation for Level 3 price risk management instruments for the three and nine months ended September 30, 2019 and 2018:

	Price Risk Management Instruments
(in millions)	2019		2018
Asset balance as of July 1	$	109	$	34
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)	(75)		(10)
Asset balance as of September 30	$	34	$	24

⁽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
(in millions)	2019		2018
Asset balance as of January 1	$	95	$	42
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)	(61)		(18)
Asset balance as of September 30	$	34	$	24

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

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable; short-term borrowings; accounts payable; and customer deposits approximate their carrying values at September 30, 2019 and December 31, 2018, as they are short-term in nature. 

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, 2019				At December 31, 2018
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
PG&E Corporation(1)	$	—	$	—	$	350	$	350
Utility(1)(2)	1,500		1,503		17,450		14,747

⁽¹⁾ On January 29, 2019 PG&E Corporation and the Utility filed for Chapter 11 protection. Debt held by PG&E Corporation and the Utility became debt subject to compromise and is valued at the allowed claim amount. For more information, see Note 2 and Note 5.

⁽²⁾ The fair value of the Utility pre-petition debt is $18.4 billion as of September 30, 2019. For more information, see Note 2 and Note 5.

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Nuclear Decommissioning Trust Investments

The following table provides a summary of equity securities and available-for-sale debt securities:

(in millions)
As of September 30, 2019	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
Nuclear decommissioning trusts
Short-term investments	$	17	$	—	$	—	$	17
Global equity securities	488		1,449		(5)		1,932
Fixed-income securities	1,508		108		(2)		1,614
Total (1)	$	2,013	$	1,557	$	(7)	$	3,563
As of December 31, 2018
Nuclear decommissioning trusts
Short-term investments	$	29	$	—	$	—	$	29
Global equity securities	568		1,246		(5)		1,809
Fixed-income securities	1,288		30		(18)		1,300
Total (1)	$	1,885	$	1,276	$	(23)	$	3,138

⁽¹⁾ Represents amounts before deducting $502 million and $408 million for the periods ended September 30, 2019 and December 31, 2018, 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, 2019
Less than 1 year	$	49
1–5 years	508
5–10 years	390
More than 10 years	667
Total maturities of fixed-income securities	$	1,614

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2019		2018		2019		2018
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	346	$	319	$	808	$	1,121
Gross realized gains on securities	45		3		67		51
Gross realized losses on securities	(5)		(5)		(12)		(14)

NOTE 10: WILDFIRE-RELATED CONTINGENCIES

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses 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 of 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 provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

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Wildfire-Related Claims

Wildfire-related claims on the Condensed Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire.

At September 30, 2019 and December 31, 2018, the Utility’s Condensed Consolidated Balance Sheets include estimated liabilities in respect of total wildfire-related claims as follows:

	Balance at
(in millions)	September 30, 2019		December 31, 2018
2015 Butte fire	$	212	$	226
2017 Northern California wildfires (1)	7,492		3,500
2018 Camp fire (1)	12,856		10,500
Total wildfire-related claims (2)	$	20,560	$	14,226

⁽¹⁾ Wildfire-related claims as of September 30, 2019 are shown net of $100 million of funds deposited into the Wildfire Assistance Fund on August 2, 2019 in connection with potential liabilities related to the 2018 Camp fire and 2017 Northern California wildfires. This $100 million is allocated to wildfire-related claims as follows: $30 million to the 2017 Northern California wildfires and $70 million to the 2018 Camp fire. For a description of the other components and categories of claims related to this liability accrual, see “Additional Information Related to 2018 Camp Fire and 2017 Northern California Wildfires Liability Accrual.”

⁽²⁾ On the Petition Date, all wildfire-related claims were classified as LSTC and all pending litigation was stayed. On August 16, 2019, the Bankruptcy Court issued the Lift Stay Decision in which it granted the TCC’s and the Ad Hoc Subrogation Group’s motions for relief from the automatic stay to allow a state court jury trial to proceed regarding the Tubbs fire. See “Proceeding in San Francisco County Superior Court for Certain Tubbs Fire-Related Claims” below.

In addition, during the three and nine months ended September 30, 2019, the Utility incurred legal and other costs of $25 million and $57 million, respectively, related to the 2018 Camp fire, with no corresponding costs in the same periods in 2018. During the three and nine months ended September 30, 2019, the Utility incurred legal and other costs of $13 million and $54 million, respectively, related to the 2017 Northern California wildfires, as compared to $53 million and $120 million, respectively, in the same periods in 2018.

2018 Camp Fire Background

On November 8, 2018, a wildfire began near the city of Paradise, Butte County, California (the “2018 Camp fire”), which is located in the Utility’s service territory. Cal Fire’s Camp Fire Incident Information Website as of October 25, 2019 (the “Cal Fire website”) indicated that the 2018 Camp fire consumed 153,336 acres. On the Cal Fire website, Cal Fire reported 85 fatalities and the destruction of 13,972 residences, 528 commercial structures and 4,293 other buildings resulting from the 2018 Camp fire. There have been no subsequent updates of this information on the Cal Fire website.

On May 15, 2019, Cal Fire issued a news release announcing the results of its investigation into the cause of the 2018 Camp fire. According to the news release:

•Cal Fire determined that the 2018 Camp fire was caused by electrical transmission lines owned and operated by the Utility near Pulga, California.

•Cal Fire identified a second ignition site and stated that the second fire was consumed by the original fire which started earlier near Pulga, California. Cal Fire stated that the cause of the second fire was determined to be “vegetation into electrical distribution lines owned and operated by” the Utility.

Cal Fire indicated in its news release that its investigation report for the 2018 Camp fire has been forwarded to the Butte County District Attorney. The California Attorney General’s Office is also investigating the 2018 Camp fire. (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations of the 2018 Camp fire.) As of the date of this filing, Cal Fire’s investigation report has not been released publicly.

PG&E Corporation and the Utility accept Cal Fire’s determination that the 2018 Camp fire ignited at the first ignition site. PG&E Corporation and the Utility have not been able to form a conclusion as to whether a second fire ignited as a result of vegetation contact with the Utility’s facilities.

PG&E Corporation and the Utility are continuing to review the evidence concerning the 2018 Camp fire. PG&E Corporation and the Utility have not yet had access to all of the evidence collected by Cal Fire as part of its investigation or to the investigation report prepared by Cal Fire.

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Further, the CPUC’s SED is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in areas impacted by the 2018 Camp fire. 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. Various other entities may also be investigating the fire. It is uncertain when the investigations will be complete and whether the SED will release any preliminary findings before its investigations are complete.

2017 Northern California Wildfires Background

Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the 2017 Northern California wildfires, there were 21 major fires that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The 2017 Northern California wildfires resulted in 44 fatalities.

Cal Fire has investigated the causes of the 2017 Northern California wildfires and made the following determinations:

•the Utility’s equipment was involved in causing 20 wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket, Atlas, Cascade, Pressley, Point and Youngs fires); and

•the Tubbs fire was caused by a private electrical system adjacent to a residential structure.

For additional details regarding Cal Fire’s investigations and findings, see PG&E Corporation’s and the Utility’s joint quarterly report on Form 10-Q for the period ended June 30, 2019.

As described under the heading “District Attorneys’ Offices’ Investigations” below, certain of the 2017 Northern California wildfires were the subject of criminal investigations, which have been settled or resulted in PG&E Corporation and the Utility being informed by the applicable district attorneys’ office of a decision not to prosecute.

The SED also conducted investigations into whether the Utility committed civil violations in connection with the 2017 Northern California wildfires. See “Order Instituting an Investigation into the 2017 Northern California Wildfires” in Note 11 for a description of these proceedings, including the alleged violations in connection with 2017 Northern California wildfires.

Various other entities may also be investigating certain of the fires. It is uncertain when the investigations will be complete.

Third-Party Claims, Investigations and Other Proceedings Related to the 2018 Camp Fire and 2017 Northern California Wildfires

If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the substantial cause of one or more fires, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought 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 benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. (See “Loss Recoveries – Regulatory Recovery” below for further information regarding potential cost recovery related to the wildfires, including in connection with SB 901.)

In addition to claims for property damage, business interruption, interest and attorneys’ fees, the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability, including if the Utility were found to have been negligent.

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Further, the Utility could be subject to material fines, penalties, or restitution orders if the CPUC or any law enforcement agency were to bring an enforcement action, including a criminal proceeding, and it were determined that the Utility had failed to comply with applicable laws and regulations.

As of January 28, 2019, before the automatic stay arising as a result of the filing of the Chapter 11 Cases, PG&E Corporation and the Utility were aware of approximately 100 complaints on behalf of at least 4,200 plaintiffs related to the 2018 Camp fire, nine of which sought to be certified as class actions. The pending civil litigation against PG&E Corporation and the Utility related to the 2018 Camp fire, which is currently stayed as a result of the commencement of the Chapter 11 Cases, included claims under multiple theories of liability, including inverse condemnation, trespass, private nuisance, public nuisance, negligence, negligence per se, negligent interference with prospective economic advantage, negligent infliction of emotional distress, premises liability, violations of the Public Utilities Code, violations of the Health & Safety Code, malice and false advertising in violation of the California Business and Professions Code. The plaintiffs principally asserted that PG&E Corporation’s 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 causes of the 2018 Camp fire. The plaintiffs sought damages and remedies that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, establishment of a class action medical monitoring fund, punitive damages, attorneys’ fees and other damages. PG&E Corporation’s and the Utility’s obligations with respect to such claims are expected to be determined through the Chapter 11 process.

As of January 28, 2019, before the automatic stay arising as a result of the filing of the Chapter 11 Cases, PG&E Corporation and the Utility were aware of approximately 750 complaints on behalf of at least 3,800 plaintiffs related to the 2017 Northern California wildfires, five of which sought to be certified as class actions. These cases were coordinated in the San Francisco County Superior Court. As of the Petition Date, the coordinated litigation was in the early stages of discovery. A trial with respect to the Atlas fire was scheduled to begin on September 23, 2019. The pending civil litigation against PG&E Corporation and the Utility related to the 2017 Northern California wildfires included claims under multiple theories of liability, including inverse condemnation, trespass, private nuisance and negligence. This litigation, including the trial date with respect to the Atlas fire, currently is stayed as a result of the commencement of the Chapter 11 Cases. The plaintiffs principally asserted that PG&E Corporation’s 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 causes of the 2017 Northern California wildfires. The plaintiffs sought damages and remedies that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, punitive damages, attorneys’ fees and other damages. PG&E Corporation’s and the Utility’s obligations with respect to such claims are expected to be determined through the Chapter 11 process. However, on August 16, 2019, the Bankruptcy Court issued an order granting the TCC’s motion to lift the stay on the 2017 Tubbs fire to allow a state court jury trial for certain preference plaintiffs, as further described under the heading “Proceeding in San Francisco Superior Court for Certain Tubbs Fire-Related Claims” below.

Insurance carriers who have made payments to their insureds for property damage arising out of the 2017 Northern California wildfires filed 52 subrogation complaints in the San Francisco County Superior Court and the Sonoma County Superior Court as of January 28, 2019. These complaints allege, among other things, negligence, inverse condemnation, trespass and nuisance. The allegations are similar to the ones made by individual plaintiffs. As of January 28, 2019, insurance carriers have filed 39 similar subrogation complaints with respect to the 2018 Camp fire in the Sacramento County Superior Court and the Butte County Superior Court. As described below under the heading “Restructuring Support Agreement with Holders of Subrogation Claims,” on September 22, 2019, PG&E Corporation and the Utility entered into a RSA with certain holders of insurance subrogation claims to potentially resolve all insurance subrogation claims relating to the 2017 Northern California wildfires and the 2018 Camp fire through the Chapter 11 process.

Various government entities, including Yuba, Nevada, Lake, Mendocino, Napa and Sonoma Counties and the Cities of Santa Rosa and Clearlake, also asserted claims against PG&E Corporation and the Utility based on the damages that these government entities allegedly suffered as a result of the 2017 Northern California wildfires. Such alleged damages included, among other things, loss of natural resources, loss of public parks, property damages and fire suppression costs. The causes of action and allegations are similar to the ones made by individual plaintiffs and the insurance carriers. With respect to the 2018 Camp fire, Butte County has filed similar claims against PG&E Corporation and the Utility. As described below under the heading “Plan Support Agreements with Public Entities,” on June 18, 2019, PG&E Corporation and the Utility entered into agreements with certain government entities to potentially resolve their wildfire-related claims through the Chapter 11 process.

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As described in Note 2, on July 1, 2019, the Bankruptcy Court entered an order approving the Bar Date of October 21, 2019, at 5:00 p.m. (Pacific Time) for filing claims against PG&E Corporation and the Utility relating to the period prior to the Petition Date, including claims in connection with the 2018 Camp fire and the 2017 Northern California wildfires. On October 18, 2019, the TCC filed with the Bankruptcy Court a motion for entry of an order extending the Bar Date for individual wildfire-related claims. On October 28, 2019, PG&E Corporation and the Utility announced that they had offered to extend the Bar Date for individual wildfire-related claims from October 21, 2019 to December 20, 2019. On the same day, during a meet and confer between PG&E Corporation and the Utility and the TCC, and at the request of the TCC, PG&E Corporation and the Utility agreed to further extend the Bar Date for individual wildfire-related claims to December 31, 2019. On November 4, 2019, PG&E Corporation and the Utility and the TCC announced that they have reached agreement to an extension of the Bar Date for individual wildfire-related claims to December 31, 2019, which agreement also involves procedures for additional notice to potential individual wildfire claimants. PG&E Corporation and the Utility and the TCC will file a stipulation with the Bankruptcy Court detailing the terms of the agreement and seeking approval of their agreement. PG&E Corporation and the Utility have received numerous proofs of claim in connection with the 2018 Camp fire and the 2017 Northern California wildfires since the Petition Date and are early in the process of reconciling those claims to the amounts listed in the schedules of assets and liabilities. See “Potential Claims” in Note 2 above.

PG&E Corporation and the Utility are continuing to review the evidence concerning the 2018 Camp fire and the 2017 Northern California wildfires. PG&E Corporation and the Utility have not yet had access to all of the evidence collected by Cal Fire as part of its investigations. PG&E Corporation and the Utility and wildfire litigation plaintiffs have reached an agreement to transfer available evidence collected by Cal Fire for the fires for which its investigation reports have been released to a shared storage facility. The transfer of the evidence is not yet complete. (See “District Attorneys’ Offices’ Investigations” below for information regarding certain investigations related to the 2018 Camp fire and 2017 Northern California wildfires.)

Regardless of any determinations of cause by Cal Fire with respect to any pre-petition fire, ultimately PG&E Corporation’s and the Utility’s liability will be resolved through the Chapter 11 process, the state court proceedings related to the 2017 Tubbs fire, regulatory proceedings and any potential enforcement proceedings. The timing and outcome of these and other potential proceedings are uncertain.

As discussed under the headings “Plan Support Agreements with Public Entities” and “Restructuring Support Agreement with Holders of Subrogation Claims,” PG&E Corporation and the Utility have entered into agreements with certain government entity claimholders to potentially resolve their wildfire-related claims as well as with certain insurance subrogation claimholders to potentially resolve all wildfire-related insurance subrogation claims. As discussed under the heading “Additional Information Related to 2018 Camp Fire and 2017 Northern California Wildfires Liability Accrual,” PG&E Corporation and the Utility have been engaged from time to time in discussions with representatives of individual wildfire claimholders to potentially resolve their claims. PG&E Corporation and the Utility cannot predict the outcome or timing of discussions with any other claimholders.

On October 25, 2019, PG&E Corporation and the Utility submitted a brief to the Bankruptcy Court challenging the application of inverse condemnation to California’s investor-owned utilities, including the Utility. The UCC joined in PG&E Corporation’s and the Utility’s brief, and a group of PG&E Corporation’s shareholders filed a supporting supplemental statement. Opposition briefs are due on November 15, 2019, and the Bankruptcy Court will hear argument regarding PG&E Corporation’s and the Utility’s motion on November 19, 2019.

Proceeding in San Francisco County Superior Court for Certain Tubbs Fire-Related Claims (the “Tubbs Trial”)

On July 2, 2019, the TCC filed a motion, pursuant to section 362(d)(1) of the Bankruptcy Code, for entry of an order modifying the automatic stay to permit certain individual plaintiffs to proceed to a jury trial on their claims against PG&E Corporation and the Utility arising from the Tubbs fire, and to request the San Francisco Superior Court in the coordinated litigation for the 2017 Northern California wildfires to order one or more of the cases of these individual plaintiffs to trial with preference pursuant to California Code of Civil Procedure section 36. On July 9, 2019, the TCC submitted an amended motion to request relief from the stay with respect to additional individual plaintiffs to proceed to a jury trial on their claims against PG&E Corporation and the Utility arising from the Tubbs fire.

On July 3, 2019, the Ad Hoc Subrogation Group submitted a motion for relief from the automatic stay to permit certain of the Ad Hoc Subrogation Group’s members to pursue their claims against PG&E Corporation and the Utility regarding the issue of PG&E Corporation’s and the Utility’s liability for the Tubbs fire in the San Francisco Superior Court in the coordinated litigation for the 2017 Northern California wildfires.

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On August 16, 2019, the Bankruptcy Court issued the Lift Stay Decision in which it granted the TCC’s and the Ad Hoc Subrogation Group’s motions for relief from the automatic stay to allow a state court jury trial to proceed regarding the Tubbs fire.

On September 12, 2019, the San Francisco County Superior Court issued a tentative ruling, granting motions for the Tubbs fire trial to proceed with respect to all designated individual plaintiffs on a preferential fast-track basis and denying PG&E Corporation’s and the Utility’s motion to transfer the trial from San Francisco County to Sonoma County, which the San Francisco County Superior Court reaffirmed on September 16, 2019, and set trial to begin on January 7, 2020.

At a status conference held on October 1, 2019, a pre-trial schedule was established, including dates relating to fact and expert discovery, motions in limine and jury selection. The court further ordered that the trial would be bifurcated into two phases – a liability phase to be tried first, followed, if necessary, by a damages phase. The court scheduled the trial to last for eight weeks, with four weeks for liability and four weeks for damages. The court further stated that it tentatively agreed with the plaintiffs’ argument that the same jury should hear both phases of the trial. On October 7, 2019, PG&E Corporation and the Utility notified the court and the plaintiffs that PG&E Corporation and the Utility would consent to a single jury for both phases of the preference trial. Also on October 7, 2019, PG&E Corporation and the Utility filed a motion for a protective order against publicity seeking to prevent plaintiffs’ counsel from communicating with members of the news media concerning specific evidence or theories of liability. The plaintiffs filed oppositions to the motion on October 17, 2019. Oral argument on the motion was held on October 30, 2019, during which the court directed the parties to further meet and confer on the issue and report back to the court for continued hearing on November 8, 2019. Discovery is ongoing.

The ultimate outcome of this proceeding is uncertain and could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Wildfire Claims Estimation Proceeding in the U.S. District Court for the Northern District of California (the “Estimation Proceeding”)

On July 18, 2019, PG&E Corporation and the Utility filed a motion for entry of an order establishing procedures and schedules for the estimation of PG&E Corporation’s and the Utility’s aggregate liability for certain claims arising out of the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire.

On August 21, 2019, the Bankruptcy Court issued recommendations to the District Court recommending the District Court order the partial withdrawal of the reference of the section 502(c) estimation of unliquidated claims arising from the 2018 Camp fire and the 2017 Northern California wildfires. On August 23, 2019, the District Court issued an order adopting the recommendation of the Bankruptcy Court in full and ordering that the reference to the Bankruptcy Court be withdrawn in part. Accordingly, the section 502(c) estimation of unliquidated claims arising from the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire is expected to take place before the District Court (and not the Bankruptcy Court).

On October 9, 2019, the District Court issued an initial order setting the estimation hearing for February 18, 2020 and reserving two weeks for the hearing, with the possibility of an additional week if warranted. In the order, the District Court named the TCC and PG&E Corporation and the Utility as the lead participants in the estimation proceedings. With respect to the subject matter of the estimation proceedings, the District Court proposed to “factor in the uncertainty of the liability disputes by directing the parties to assess the probability that the claimants would be successful at trial.” The parties will continue to meet and confer on those issues. In terms of potential damages, the parties agree that the District Court will estimate losses for property, personal injury (including emotional distress and mental and physical health impairments), wrongful death and punitive damages (if any).

On October 11, 2019, the District Court issued a Scheduling Order. According to the Scheduling Order, fact discovery is to be completed by December 23, 2019, expert discovery is to be completed by February 6, 2020, parties’ opening briefs are due February 12, 2020, and the first day of hearing is set for February 18, 2020.

The ultimate outcome of this proceeding is uncertain and could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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Plan Support Agreements with Public Entities

On June 18, 2019, PG&E Corporation and the Utility entered into PSAs with certain local public entities (collectively, the “Supporting Public Entities”) providing for an aggregate of $1.0 billion to be paid by PG&E Corporation and the Utility to such public entities pursuant to PG&E Corporation and the Utility’s Chapter 11 plan of reorganization in order to settle such public entities’ claims against PG&E Corporation and the Utility relating to the 2018 Camp fire, 2017 Northern California wildfires and 2015 Butte fire (collectively, “Public Entity Wildfire Claims”). For more information on the PSAs, see “Plan Support Agreements with Public Entities” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of PG&E Corporation and the Utility’s joint Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2019.

Restructuring Support Agreement with Holders of Subrogation Claims

On September 22, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement with the Consenting Subrogation Creditors of insurance subrogation claims. On November 1, 2019, PG&E Corporation and the Utility and the Consenting Subrogation Creditors of insurance subrogation claims entered into an amended and restated Restructuring Support Agreement. The RSA provides for an aggregate amount of $11.0 billion to be paid by PG&E Corporation and the Utility pursuant to the Proposed Plan in order to settle the Subrogation Claims, upon the terms and conditions set forth in the RSA. Under the RSA, PG&E Corporation and the Utility have also agreed to reimburse the holders of Subrogation Claims for professional fees of up to $55 million, upon the terms and conditions set forth in the RSA.

The RSA provides that, subject to certain terms and conditions (including that PG&E Corporation and the Utility remain solvent), the Consenting Subrogation Creditors will support the Proposed Plan with respect to its treatment of the Subrogation Claims, including by voting their Subrogation Claims to accept the Proposed Plan in the Chapter 11 Cases.

The effectiveness of the RSA is conditioned upon approval of the Bankruptcy Court in accordance with the terms of the RSA by no later than November 14, 2019 (which date may be extended with the consent of the holders of at least two-thirds of the Subrogation Claims held by Consenting Subrogation Creditors).

The RSA will automatically terminate if (i) the Proposed Plan is not confirmed by June 30, 2020 (or such later date as may be authorized by any amendment to AB 1054) or (ii) the Effective Date does not occur prior to December 31, 2020 (or six months following the deadline for confirmation of the Proposed Plan if such deadline is extended by any amendment to AB 1054).

The RSA may be terminated by any Consenting Subrogation Creditor as to itself if the Aggregate Subrogation Recovery is modified. The RSA may be terminated by the Consenting Subrogation Creditors holding at least two-thirds of the Subrogation Claims held by Consenting Subrogation Creditors under certain circumstances, including, among others, if (i) they reasonably determine in good faith at any time prior to confirmation of the Proposed Plan that PG&E Corporation and the Utility are insolvent or otherwise unable to raise sufficient capital to pay the Aggregate Subrogation Recovery on the Effective Date, (ii) PG&E Corporation and the Utility breach the terms of the RSA or otherwise fail to take certain actions specified in the RSA, (iii) the Proposed Plan does not treat the individual plaintiffs’ wildfire-related claims consistent with the provisions of AB 1054, (iv) the Bankruptcy Court allows a plan proponent other than PG&E Corporation and the Utility to commence soliciting votes on a plan (other than the Proposed Plan) that incorporates the terms of the settlement contemplated by the RSA and PG&E Corporation and the Utility have not already commenced soliciting votes on the Proposed Plan which incorporates such settlement, (v) the Bankruptcy Court confirms a plan other than the Proposed Plan or (vi) the Proposed Plan is modified to be inconsistent with such settlement. The RSA may be terminated by PG&E Corporation and the Utility (a) in the event of certain breaches of the RSA by Consenting Subrogation Creditors holding at least 5% of the Subrogation Claims held by Consenting Subrogation Creditors or (b) if the Bankruptcy Court confirms a plan other than the Proposed Plan or if the terms of the Proposed Plan related to the settlement contemplated by the RSA become unenforceable or are enjoined.

Subject to certain limited exceptions, the aggregate amount of $11.0 billion (the “Allowed Subrogation Claim Amount”) will survive any termination of the RSA and will be binding on PG&E Corporation and the Utility in the Chapter 11 Cases.

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On September 24, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authority to enter into, and perform under, the RSA and approving the terms of the settlement contemplated under the RSA. Pursuant to that motion, PG&E Corporation and the Utility requested that the allowance of the Subrogation Claims in the aggregate amount of $11.0 billion be effective upon the approval of the motion and that the treatment and satisfaction of the Subrogation Claims be effectuated pursuant to the Proposed Plan following confirmation of the effectiveness of the Proposed Plan. Various stakeholders filed objections to PG&E Corporation’s and the Utility’s motion, including the UCC, the Ad Hoc Noteholder Committee, the TCC and the U.S. Government. A hearing on PG&E Corporation’s and the Utility’s motion to approve the RSA was held on October 23, 2019, at which the Bankruptcy Court continued the hearing on the motion to November 13, 2019. On November 2, 2019, PG&E Corporation and the Utility filed the RSA, as amended, with the Bankruptcy Court.

Certain Federal, State and Local Claims in Connection with the 2018 Camp Fire and 2017 Northern California Wildfires

FEMA has filed proofs of claim in the Chapter 11 Cases in the amount of $1.2 billion in connection with the 2017 Northern California wildfires and $2.6 billion in connection with the 2018 Camp fire.

In addition, Cal Fire has filed proofs of claim in the Chapter 11 Cases in the amount of $133 million in connection with the 2017 Northern California wildfires and specifying at least $110 million in connection with the 2018 Camp fire. The OES has filed proofs of claim in the amount of $347 million in connection with the 2017 Northern California wildfires and $2.3 billion in connection with the 2018 Camp fire. The California Department of Transportation has filed proofs of claim in the Chapter 11 Cases in the amount of $217 million in connection with the 2018 Camp fire.

Certain other Federal, state and local entities have filed proofs of claim in the Chapter 11 Cases in connection with the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire. Proofs of claim have also been filed for unspecified amounts to be determined at a later time.

PG&E Corporation and the Utility are early in the process of reviewing the proofs of claim that have been filed in the Chapter 11 Cases. It is possible that additional Federal, state and local entities have filed or will file proofs of claim for wildfire-related claims in the Chapter 11 Cases. PG&E Corporation and the Utility may ask the Bankruptcy Court to disallow claims that they believe are duplicative, have been later amended or superseded, are without merit, are overstated or should be disallowed for other reasons. See “Potential Claims” in Note 2. In addition, there is dispute over whether claims asserted by the U.S. Government and the State of California (including any department, agency or instrumentality thereof) are unliquidated and subject to estimation under section 502(c) of the Bankruptcy Code. On November 1, 2019, PG&E Corporation and the Utility filed a notice with the Bankruptcy Court designating the Federal and state agency claims they contend are unliquidated and subject to estimation under section 502(c) of the Bankruptcy Code. A hearing on this issue before the Bankruptcy Court is set for December 17, 2019.

Potential Losses in Connection with the 2018 Camp Fire and 2017 Northern California Wildfires

On May 8, 2019, the California Department of Insurance issued a news release announcing an update on property losses in connection with the 2018 wildfires in Southern California (which are not in the Utility’s service territory) and the 2018 Camp fire, indicating that “total claims over $12 billion as of April [2019]” in insured losses have been reported from the November 2018 fires, of which approximately $8.6 billion relates to statewide claims from the 2018 Camp fire. On September 6, 2018, the California Department of Insurance issued a news release announcing that insurers have received nearly 55,000 insurance claims totaling more than $12.28 billion in losses, of which approximately $10 billion relates to statewide claims from the 2017 Northern California wildfires.

The dollar amounts announced by the California Department of Insurance represent an aggregate amount of approximately $18.6 billion of insurance claims made as of the above dates related to the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation and the Utility expect that additional claims have been submitted and will continue to be submitted to insurers, particularly with respect to the 2018 Camp fire. The Ad Hoc Subrogation Group in the Chapter 11 Cases has estimated that the total value of their claims related to the 2017 Northern California wildfires and the 2018 Camp fire could exceed $20 billion, including attorneys’ fees and interest. These claims reflect insured property losses only.

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The $18.6 billion of insurance claims made as of the above dates does not account for uninsured or underinsured property losses, interest, attorneys’ fees, fire suppression and clean-up costs, evacuation costs, personal injury or wrongful death damages, medical expenses or other costs, such as potential punitive damages, fines or penalties, or losses related to claims that have not manifested yet (“future claims”), each of which could be significant. The TCC has most recently estimated in the Chapter 11 Cases that the individual plaintiffs’ wildfire-related claims are valued at $30 billion to $40 billion. On October 17, 2019, the TCC and the Ad Hoc Noteholder Committee filed the TCC/Ad Hoc Noteholder Plan, which would allocate no more than approximately $13.5 billion of consideration to resolve all claims concerning the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire that are not the subject of either the PSAs with the Supporting Public Entities or the RSA with the Consenting Subrogation Creditors. This proposed cap on the covered wildfire claims would apply only if the TCC/Ad Hoc Noteholder Plan were confirmed by the Bankruptcy Court. The potential liabilities concerning those covered claims, and other wildfire claims, could materially exceed $13.5 billion as described below.

Potential liabilities related to the 2018 Camp fire and 2017 Northern California wildfires depend on various factors, including but not limited to the cause of each fire, contributing causes of the fires (including alternative potential origins, weather and climate related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the extent to which future claims arise, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent or as estimated in the Chapter 11 Cases, the amount of any penalties or fines that may be imposed by governmental entities, and the amount of any penalties, fines, or restitution orders that might result from any criminal charges brought.

There are a number of unknown facts and legal considerations that may impact the amount of any potential liability. Among other things, there is uncertainty at this time as to the number of current and future claims that will be allowed by the Bankruptcy Court, how claims for punitive damages and claims by variously situated persons will be classified and treated and whether such claims will be allowed, the impact that historical settlement values for wildfire claims and other factors may have on the estimation of wildfire liability in the Chapter 11 Cases, and the number of wildfire-related claims that will be filed in the Chapter 11 Cases as a result of the agreement to extend the Bar Date for individual wildfire-related claims. If PG&E Corporation and the Utility were to be found liable for certain or all of the costs, expenses and other losses described above with respect to the 2018 Camp fire and 2017 Northern California wildfires, the amount of such liability could exceed $30 billion. This estimate is based on a wide variety of data and other information available to PG&E Corporation and the Utility and their advisors, including various precedents involving similar claims, the estimates of insured losses (along with associated interest and attorneys’ fees) disclosed in the Chapter 11 Cases by the Ad Hoc Subrogation Group, the estimates of losses not covered by insurance disclosed in the Chapter 11 Cases by the TCC, and the TCC/Ad Hoc Noteholder Plan. This estimate accounts for property losses (including insured, uninsured and underinsured property losses), interest, attorneys’ fees, fire suppression and clean-up costs, evacuation costs, personal injury or wrongful death damages, medical expenses and certain other costs but does not include potential punitive damages, fines and penalties or damages related to claims that have not manifested yet. This estimate is not intended to provide an upper end of the range of potential liability arising from the 2018 Camp fire and 2017 Northern California wildfires. In certain circumstances, PG&E Corporation’s and the Utility’s liability could be substantially greater than such amount.

If PG&E Corporation and the Utility were to be found liable for any punitive damages, and such damages were allowed by the Bankruptcy Court, or if PG&E Corporation and the Utility were subject to fines or penalties, the amount of such punitive damages, fines and penalties could be significant. PG&E Corporation and the Utility have received significant fines and penalties in connection with past incidents. For example, in 2015, the CPUC approved a decision that imposed penalties on the Utility totaling $1.6 billion in connection with the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010 (the “San Bruno explosion”). These penalties represented nearly three times the underlying liability for the San Bruno explosion of approximately $558 million incurred for third-party claims, exclusive of shareholder derivative lawsuits and legal costs incurred. The amount of punitive damages, fines and penalties imposed on PG&E Corporation and the Utility could likewise be a significant amount in relation to the underlying liabilities with respect to the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation’s and the Utility’s obligations with respect to such claims are expected to be determined through the Chapter 11 process. Regulatory proceedings are not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of such proceedings are stayed.

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2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge

2018 Camp Fire

In light of the current state of the law and the information currently available to the Utility, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with the 2018 Camp fire. PG&E Corporation and the Utility recorded a charge in the amount of $10.5 billion for the year ended December 31, 2018 and a charge in the amount of $1.9 billion for the three months ended June 30, 2019. Based on additional facts and circumstances available to the Utility as of the date of this filing, including the entry into the RSA, PG&E Corporation and the Utility recorded an additional charge for claims in connection with the 2018 Camp fire in the amount of $526 million for the three months ended September 30, 2019, for a total charge of $2.4 billion for the nine months ended September 30, 2019.

The aggregate liability of $12.9 billion for claims in connection with the 2018 Camp fire corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimated probable losses, and is subject to change based on additional information.

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss related to the 2018 Camp fire will be greater than the amount accrued, but are unable to reasonably estimate the additional loss and the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the outcomes of claims estimation, whether existing settlements are upheld, how the claims filed by Federal, state and local entities are resolved, and the ongoing criminal investigation. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, additional information about the nature and extent of personal and business property damage and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

The process for estimating losses associated with claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including but not limited to factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the financial impact of the 2018 Camp fire may change, which could result in material increases to the loss accrued.

The $12.9 billion liability does not include any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, or punitive damages, if any, or any losses related to future claims for damages that have not manifested yet, each of which could be significant. In addition, the charge does not include any amount with respect to FEMA reimbursement claims, claims for property damages related to federal land and other property or claims by certain state and local public entities that are not party to the PSAs, which amounts could be substantial. The charge also does not include any amounts for potential losses in connection with the wildfire-related securities class action litigation described below.

2017 Northern California Wildfires

In light of the current state of the law and the information currently available to the Utility, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with all 21 of the 2017 Northern California wildfires identified above, the reasons for which are discussed in more detail in this section below. PG&E Corporation and the Utility recorded a charge in the amount of $2.5 billion during the quarter ended June 30, 2018 and a charge in the amount of $1.0 billion during the quarter ended December 31, 2018, for a total charge in the amount of $3.5 billion for the year ended December 31, 2018. PG&E Corporation and the Utility recorded a charge in the amount of $2.0 billion for the three months ended June 30, 2019. Based on additional facts and circumstances available to the Utility as of the date of this filing, including the entry into the RSA, PG&E Corporation and the Utility recorded an additional charge for claims in connection with the 2017 Northern California wildfires in the amount of $2.0 billion for the three months ended September 30, 2019, for a total charge of $4.0 billion for the nine months ended September 30, 2019.

The aggregate liability of $7.5 billion for claims in connection with the 2017 Northern California wildfires corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimated probable losses and is subject to change based on additional information.

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In the case of the Tubbs and 37 fires, PG&E Corporation and the Utility continue to believe that if the claims related to these fires were litigated on the merits, it would not be probable that they would incur a loss for such claims. As a result of settlement offers PG&E Corporation and the Utility had made to holders of claims related to the Tubbs and 37 fires, PG&E Corporation and the Utility determined that it is probable they will incur a loss for claims in connection with such fires. With respect to the other 19 of the 2017 Northern California wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, Blue, Pocket, Atlas, Cascade, Point, Nuns, Norrbom, Adobe, Partrick, Pythian, Youngs and Pressley fires), PG&E Corporation and the Utility previously determined that it is probable they would incur a loss for claims in connection with such fires if such claims were litigated on the merits.

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss related to the 2017 Northern California wildfires will be greater than the amount accrued, but are unable to reasonably estimate the additional loss and the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the outcomes of claims estimation, whether existing settlements are upheld, how the claims filed by Federal, state and local entities are resolved, and the proceeding for certain Tubbs fire-related claims. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damage and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

The process for estimating losses associated with claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including but not limited to factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the financial impact of the 2017 Northern California wildfires may change, which could result in material increases to the loss accrued.

The $7.5 billion liability does not include any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, or punitive damages, if any, or any losses related to future claims for damages that have not manifested yet, each of which could be significant. In addition, the charge does not include any amount in respect of FEMA reimbursement claims, claims for property damages related to federal land and other property or claims by certain state and local public entities that are not party to the PSAs, which amounts could be substantial. The charge also does not include any amounts for potential losses in connection with the wildfire-related securities class action litigation described below.

Additional Information Related to 2018 Camp Fire and 2017 Northern California Wildfires Liability Accrual

The aggregate liability of $20.3 billion for claims in connection with the 2018 Camp fire and the 2017 Northern California wildfires is comprised of (i) $11.0 billion for subrogated insurance claimholders pursuant to the RSA, plus (ii) $47 million for expected professional fees for professionals retained by subrogated insurance claimholders to be reimbursed pursuant to the RSA, plus (iii) $7.5 billion for individual wildfire claimholders (including those with uninsured and underinsured property losses, among other claims), plus (iv) $1.0 billion for the Supporting Public Entities with respect to their Public Entity Wildfire Claims pursuant to the PSAs, plus (v) $900 million for clean-up and fire suppression costs, minus (vi) $100 million of payments made to the Wildfire Assistance Fund on August 2, 2019. As described above, the aggregate liability of $20.3 billion for claims in connection with the 2018 Camp fire and the 2017 Northern California wildfires corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimated probable losses and is subject to change based on additional information. (See “Potential Losses in Connection with the 2018 Camp Fire and 2017 Northern California Wildfires” above.)

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The aggregate liability of $7.5 billion for individual wildfire claimholders is based on PG&E Corporation’s and the Utility’s estimate of probable loss developed from data and other information available to PG&E Corporation and the Utility and corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimated probable losses and is subject to change based on additional information. As described above, the TCC/Ad Hoc Noteholder Plan proposes a trust for payment of all wildfire-related claims (other than insurance subrogation claims and Public Entity Wildfire Claims) to be funded with consideration in an amount equal to the lesser of (i) $13.5 billion (the “TCC/Ad Hoc Noteholder Plan Cap”) and (ii) an amount of such claims as determined by a court of competent jurisdiction. This trust under the TCC/Ad Hoc Noteholder Plan would be available to pay the claims of individual wildfire claimholders and certain other claims (other than insurance subrogation claims and Public Entity Wildfire Claims), such as clean-up and fire suppression costs. Under the Proposed Plan, $900 million of the $8.4 billion trust for wildfire-related claims (other than insurance subrogation claims and Public Entity Wildfire Claims) corresponds to clean-up and fire suppression costs. The TCC, which is the official representative of all tort claimants in the Chapter 11 Cases (but not the representative of any individual wildfire claimholder), has stated that the TCC/Ad Hoc Noteholder Plan has the support of the individual wildfire claimholders. The actual amount of PG&E Corporation’s and the Utility’s liability to individual wildfire claimholders will be addressed and treated under a plan of reorganization in the Chapter 11 Cases and will be determined either through (i) the Tubbs Trial and the Estimation Proceeding or (ii) settlement with the individual wildfire claimholders.

Over the past several months, representatives of PG&E Corporation and the Utility have from time to time engaged in settlement discussions with representatives of the individual wildfire claimholders. On October 28, 2019, the Bankruptcy Court issued an order directing the principal parties in the Chapter 11 Cases to participate in mediation. On November 1, 2019, the California Governor announced that his office would seek to “broker” the mediation in order to encourage a “swift and consensual resolution to the Chapter 11 Cases.”

PG&E Corporation and the Utility are aware that representatives of certain debt- and equity-holders of PG&E Corporation and the Utility have from time to time engaged in separate settlement discussions with representatives of the individual wildfire claimholders, including following the date of the mediation order. As previously disclosed, PG&E Corporation’s and the Utility’s most recent settlement offer to the representatives of the individual wildfire claimholders was $7.5 billion. PG&E Corporation and the Utility are not aware of the amount of any settlement offer that may have been made by any representatives of any debt- or equity-holders to the representatives of the individual wildfire claimholders, although PG&E Corporation and the Utility believe that one or more settlement offers may have been made and that it is likely that such offers significantly exceed the previous offer made by PG&E Corporation and the Utility.

Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the status of settlement discussions, PG&E Corporation and the Utility believe that in the event the claims of the individual wildfire claimholders are resolved through settlement, the amount of such settlement may be much closer to the amount of the TCC/Ad Hoc Noteholder Plan Cap than to the amount of the liability accrual of $7.5 billion. As of the date of this filing, PG&E Corporation and the Utility believe that these settlement discussions are in a particularly critical period of the negotiation. PG&E Corporation and the Utility believe that the potential exists for material developments in such negotiation in the near term. Accordingly, if PG&E Corporation, the Utility and the representatives of the individual wildfire claimholders reach agreement, PG&E Corporation’s and the Utility’s probable loss contingency for the claims of the individual wildfire claimholders may increase by a material amount, which would result in an additional accrual above the $7.5 billion reflected in this filing. Any such increase could be substantial and could be recorded in the fourth quarter of 2019.

Notwithstanding recent developments in the status of settlement negotiations, PG&E Corporation and the Utility are unable to reasonably estimate (a) whether the amount of the liability to individual wildfire claimholders will actually be determined through (i) the Tubbs Trial and the Estimation Proceeding or (ii) settlement with the representatives of the individual wildfire claimholders or (b) the actual amount of such liability under either scenario. In addition, PG&E Corporation and the Utility cannot predict the outcome or timing of any settlement discussions with the representatives of the individual wildfire claimholders, and there can be no assurance that any settlement will be reached.

Loss Recoveries

PG&E Corporation and the Utility had insurance coverage for liabilities, including wildfire. Additionally, there are several mechanisms that allow for recovery of costs from customers. Potential for recovery is described below. Failure to obtain a substantial or full recovery of costs related to the 2018 Camp fire and 2017 Northern California wildfires or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the inability to recover costs in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

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Insurance

PG&E Corporation and the Utility had $842 million of insurance coverage for liabilities, including wildfire events, for the period from August 1, 2017 through July 31, 2018, subject to an initial self-insured retention of $10 million per occurrence and further retentions of approximately $40 million per occurrence. During the third quarter of 2018, PG&E Corporation and the Utility renewed their liability insurance coverage for wildfire events in an aggregate amount of approximately $1.4 billion for the period from August 1, 2018 through July 31, 2019, comprised of $700 million for general liability (subject to an initial self-insured retention of $10 million per occurrence), and $700 million for property damages only, which property damage coverage includes an aggregate amount of approximately $200 million through the reinsurance market where a catastrophe bond was utilized.

PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through September 30, 2019, PG&E Corporation and the Utility recorded $1.38 billion for probable insurance recoveries in connection with the 2018 Camp fire and $842 million for probable insurance recoveries in connection with the 2017 Northern California wildfires. These amounts reflect an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies. The amount of the receivable is subject to change based on additional information. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. Even if PG&E Corporation and the Utility were to recover the full amount of their insurance, PG&E Corporation and the Utility expect their losses in connection with the 2018 Camp fire and 2017 Northern California wildfires will substantially exceed their available insurance.

The balances for insurance receivables with respect to the 2018 Camp fire and the 2017 Northern California wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. The balance for insurance receivable for the 2018 Camp fire was $1.38 billion as of September 30, 2019 and December 31, 2018. The balance for insurance receivable for the 2017 Northern California wildfires was $807 million and $829 million as of September 30, 2019 and December 31, 2018, respectively.

Regulatory Recovery

On June 21, 2018, the CPUC issued a decision granting the Utility’s request to establish a WEMA to track specific incremental wildfire liability costs effective as of July 26, 2017. The decision does not grant the Utility rate recovery of any wildfire-related costs. Any such rate recovery would require CPUC authorization in a separate proceeding. The Utility may be unable to fully recover costs in excess of insurance, if at all. Rate recovery is uncertain, therefore the Utility has not recorded a regulatory asset related to any wildfire claims costs. Even if such recovery is possible, it could take a number of years to resolve and a number of years to collect.

In addition, SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT. SB 901 does not authorize securitization with respect to possible 2018 Camp fire costs.

On January 10, 2019, the CPUC adopted an OIR, which establishes a process to develop criteria and a methodology to inform determinations of the CHT in future applications under Section 451.2(a) of the Public Utilities Code for recovery of costs related to the 2017 Northern California wildfires.

On March 29, 2019, the assigned commissioner issued a scoping memo, which confirmed that the CPUC in this proceeding would establish a CHT methodology applicable only to 2017 fires, to be invoked in connection with a future application for cost recovery, and would not determine a specific financial outcome in this proceeding.

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On July 8, 2019, the CPUC issued a decision in the CHT proceeding. The CPUC decision provides that “[a]n electrical corporation that has filed for relief under chapter 11 of the Bankruptcy Code may not access the Stress Test to recover costs in an application under Section 451.2(b), because the Commission cannot determine the corporation’s ‘financial status,’ which includes, among other considerations, its capital structure, liquidity needs, and liabilities, as required by Section 451.2(b).” This determination effectively bars PG&E Corporation and the Utility from access to relief under the CHT during the pendency of the Chapter 11 Cases. On August 7, 2019, the Utility submitted to the CPUC an application for rehearing of the decision. The Utility indicated in its application, among other things, that the CPUC’s decision “is contrary to law because it bars a utility that has filed for Chapter 11 from accessing the CHT, requires a utility to file a cost recovery application before the CHT will be determined, and erects ratepayer protection mechanisms as an extra-statutory hurdle for accessing the CHT.” The Utility also argued that the CPUC should apply the CHT methodology to costs related to the 2018 Camp fire.

The decision otherwise adopts a methodology to determine the CHT based on (1) the maximum additional debt that a utility can take on and maintain a minimum investment grade credit rating; (2) excess cash available to the utility; (3) a potential maximum regulatory adjustment of either 20% of the CHT or 5% of the total disallowed wildfire liabilities, whichever is greater; and (4) an adjustment to preserve for ratepayers any tax benefits associated with the CHT. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers as part of an application under Section 451.2(b).

Failure to obtain a substantial or full recovery of costs related to wildfires could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.

Wildfire-Related Derivative Litigation

Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants current and certain former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility are named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018, and are denominated In Re California North Bay Fire Derivative Litigation. On April 13, 2018, the plaintiffs filed a consolidated complaint. After the parties reached an agreement regarding a stay of the derivative proceeding pending resolution of the tort actions described above and any regulatory proceeding relating to the 2017 Northern California wildfires, on April 24, 2018, the court entered a stipulation and order to stay. The stay is subject to certain conditions regarding the plaintiffs’ access to discovery in other actions. On January 28, 2019, the plaintiffs filed a request to lift the stay for the purposes of amending their complaint to add allegations regarding the 2018 Camp fire.

On August 3, 2018, a third purported derivative lawsuit, entitled Oklahoma Firefighters Pension and Retirement System v. Chew, et al., was filed in the U.S. District Court for the Northern District of California, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation is named as a nominal defendant. The lawsuit alleges claims for breach of fiduciary duties and unjust enrichment as well as a claim under Section 14(a) of the federal Securities Exchange Act of 1934 alleging that PG&E Corporation’s and the Utility’s 2017 proxy statement contained misrepresentations regarding the companies’ risk management and safety programs. On October 15, 2018, PG&E Corporation filed a motion to stay the litigation. Prior to the scheduled hearing on this motion, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of bankruptcy proceedings, as discussed below.

On October 23, 2018, a fourth purported derivative lawsuit, entitled City of Warren Police and Fire Retirement System v. Chew, et al., was filed in San Francisco County Superior Court, alleging claims for breach of fiduciary duty, corporate waste and unjust enrichment. It names as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation, and names PG&E Corporation as a nominal defendant. The plaintiff filed a request with the court seeking the voluntary dismissal of this matter without prejudice on January 18, 2019.

On November 21, 2018, a fifth purported derivative lawsuit, entitled Williams v. Earley, Jr., et al., was filed in federal court in San Francisco, alleging claims identical to those alleged in the Oklahoma Firefighters Pension and Retirement System v. Chew, et al. lawsuit listed above against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. This lawsuit includes allegations related to the 2017 Northern California wildfires and the 2018 Camp fire. This action was stayed by stipulation of the parties and order of the court on December 21, 2018, subject to resolution of the pending securities class action.

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On December 24, 2018, a sixth purported derivative lawsuit, entitled Bowlinger v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. On February 5, 2019, the plaintiff in Bowlinger v. Chew, et al. filed a response to the notice asserting that the automatic stay did not apply to his claims. PG&E Corporation and the Utility accordingly filed a Motion to Enforce the Automatic Stay with the Bankruptcy Court as to the Bowlinger action, which was granted. The court has scheduled a case management conference for December 13, 2019.

On January 25, 2019, a seventh purported derivative lawsuit, entitled Hagberg v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants.

On January 28, 2019, an eighth purported derivative lawsuit, entitled Blackburn v. Meserve, et al., was filed in federal court alleging claims for breach of fiduciary duty, unjust enrichment, and waste of corporate assets in connection with the 2017 Northern California wildfires and the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation as a nominal defendant.

Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed notices in each of these proceedings on February 1, 2019, reflecting that the proceedings are automatically stayed pursuant to Section 362(a) of the Bankruptcy Code.

Securities Class Action Litigation

Wildfire-Related Class Action

In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California, naming PG&E Corporation and certain of its current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively.  The complaints alleged material misrepresentations and omissions related to, among other things, vegetation management and transmission line safety in various PG&E Corporation public disclosures. The complaints asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases and the litigation is now denominated In re PG&E Corporation Securities Litigation. The court also appointed the Public Employees Retirement Association of New Mexico as lead plaintiff. The plaintiff filed a consolidated amended complaint on November 9, 2018. After the plaintiff requested leave to amend their complaint to add allegations regarding the 2018 Camp fire, the plaintiff filed a second amended consolidated complaint on December 14, 2018.

Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed a notice on February 1, 2019, reflecting that the proceedings are automatically stayed pursuant to Section 362(a) of the Bankruptcy Code. On February 15, 2019, PG&E Corporation and the Utility filed a complaint in Bankruptcy Court against the plaintiff seeking preliminary and permanent injunctive relief to extend the stay to the claims alleged against the individual officer defendants.

On February 22, 2019, a purported securities class action was filed in the United States District Court for the Northern District of California, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint names as defendants certain current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility is named as a defendant. The complaint alleges material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. The complaint asserts claims under Section 11 and Section 15 of the Securities Act of 1933, and seeks unspecified monetary relief, attorneys’ fees and other costs, and injunctive relief. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

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On May 28, 2019, the plaintiffs in the consolidated securities actions filed a third amended consolidated class action complaint, which includes the claims asserted in the previously-filed actions and names as defendants PG&E Corporation, the Utility, certain current and former officers and directors, and the underwriters. The action remains stayed as to PG&E Corporation and the Utility. On August 28, 2019, the Bankruptcy Court denied PG&E Corporation’s and the Utility’s request to extend the stay to the claims against the officer, director, and underwriter defendants. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint, which motions are currently set to be heard by the District Court on February 6, 2020.

De-energization Class Action

On October 25, 2019, a purported securities class action was filed in the United States District Court for the Northern District of California, entitled Vataj v. Johnson et al. The complaint names as defendants a current director and certain current and former officers of PG&E Corporation. Neither PG&E Corporation nor the Utility is named as a defendant. The complaint alleges materially false and misleading statements regarding PG&E Corporation’s wildfire prevention and safety protocols and policies, including regarding the Utility’s public safety power shutoffs, that allegedly resulted in losses and damages to holders of PG&E Corporation’s securities. The complaint asserts claims under Section 10(b) and Section 20(a) of, and Rule 10b-5 promulgated under, the Exchange Act of 1934, and seeks unspecified monetary relief, attorneys’ fees and other costs.

Given the early stages of the litigations, including but not limited to the fact that defendants’ motions to dismiss have not yet been heard and no discovery has occurred in the consolidated class action litigation, and that the de-energization class action was recently filed, PG&E Corporation and the Utility are unable to reasonably estimate the amount of any potential loss.

Indemnification Obligations

To the extent permitted by law, PG&E Corporation and the Utility have obligations to indemnify directors and officers for certain events or occurrences while a director or officer is or was serving in such capacity, which indemnification obligations extend to the claims asserted against the directors and officers in the securities class action. PG&E Corporation and the Utility maintain directors and officers insurance coverage to reduce their exposure to such indemnification obligations, and have provided notice to their insurance carriers of the claims asserted in the securities class action. PG&E Corporation and the Utility additionally have potential indemnification obligations to the underwriters for the Utility’s note offerings, pursuant to the underwriting agreements associated with those offerings. These indemnification obligations to the officers, directors and underwriters may be limited or affected by the Chapter 11 Cases.

District Attorneys’ Offices’ Investigations

During the second quarter of 2018, Cal Fire issued news releases stating that it referred the investigations related to the McCourtney, Lobo, Honey, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires to the appropriate county District Attorney’s offices for review “due to evidence of alleged violations of state law.” On March 12, 2019, the Sonoma, Napa, Humboldt and Lake County District Attorneys announced that they would not prosecute PG&E Corporation or the Utility for the fires in those counties, which include the Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires.

PG&E Corporation and the Utility were the subject of criminal investigations or other actions by the Nevada County District Attorney’s Office to whom Cal Fire had referred its investigations into the McCourtney and Lobo fires. On July 23, 2019, the Nevada County District Attorney informed PG&E Corporation and the Utility of his decision not to pursue criminal charges in connection with the McCourtney and Lobo fires.

The Honey fire was referred to the Butte County District Attorney’s Office, and in October 2018, the Utility reached an agreement to settle any civil claims or criminal charges that could have been brought by the Butte County District Attorney in connection with the Honey fire, as well as the La Porte and Cherokee fires (which were not referred). The settlement provides for funding by the Utility for at least four years of an enhanced fire prevention and communication program, in the amount of up to $1.5 million, not recoverable in rates.

On October 9, 2018, the Office of the District Attorney of Yuba County announced its decision not to pursue criminal charges at such time against PG&E Corporation or the Utility pertaining to the Cascade fire. The District Attorney’s Office also indicated that it reserved the right “to review any additional information or evidence that may be submitted to it prior to the expiration of the criminal statute of limitations.”

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In addition, the Butte County District Attorney’s Office and the California Attorney General’s Office have opened a criminal investigation of the 2018 Camp fire. PG&E Corporation and the Utility have been informed by the Butte County District Attorney’s Office and the California Attorney General’s Office that a grand jury has been empaneled in Butte County, and the Utility was served with subpoenas in the grand jury investigation. The Utility has produced documents and continues to produce documents and respond to other requests for information and witness testimony in connection with the criminal investigation of the 2018 Camp fire, including, but not limited to, documents related to the operation and maintenance of equipment owned or operated by the Utility. The Utility has also cooperated with the Butte County District Attorney’s Office and the California Attorney General’s Office in the collection of physical evidence from equipment owned or operated by the Utility. PG&E Corporation and the Utility are unable to predict the outcome of the criminal investigation into the 2018 Camp fire. The Utility could be subject to material fines, penalties, or restitution if it is determined that the Utility failed to comply with applicable laws and regulations, as well as non-monetary remedies such as oversight requirements. The criminal investigation is not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases. On October 17, 2019, the Butte County District Attorney’s Office and the California Attorney General’s Office filed proofs of claim in the Chapter 11 Cases of an undetermined amount on the basis of the criminal investigation of the 2018 Camp fire.

Additional investigations and other actions may arise out of the other 2017 Northern California wildfires and the 2018 Camp fire. The timing and outcome for resolution of the remaining referrals by Cal Fire to the appropriate county District Attorneys’ offices are uncertain.

SEC Investigation

On March 20, 2019, PG&E Corporation learned that the SEC’s San Francisco Regional Office is conducting an investigation related to PG&E Corporation’s and the Utility’s public disclosures and accounting for losses associated with the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire. PG&E Corporation and the Utility are unable to predict the timing and outcome of the investigation.

Clean-up and Repair Costs

The Utility incurred costs of $704 million for clean-up and repair of the Utility’s facilities (including $270 million in capital expenditures) through September 30, 2019, in connection with the 2018 Camp fire. The Utility also incurred costs of $346 million for clean-up and repair of the Utility’s facilities (including $171 million in capital expenditures) through September 30, 2019, in connection with the 2017 Northern California wildfires. The Utility is authorized to track and seek recovery of clean-up and repair costs through CEMA. (CEMA requests are subject to CPUC approval.) The Utility capitalizes and records as regulatory assets costs that are probable of recovery. At September 30, 2019, the CEMA regulatory asset balances related to the 2018 Camp fire and 2017 Northern California wildfires were zero and $88 million, respectively, and are included in long-term regulatory assets on the Condensed Consolidated Balance Sheets. Additionally, the capital expenditures for clean-up and repair are included in property, plant and equipment at September 30, 2019.

Should PG&E Corporation and the Utility conclude that recovery of any clean-up and repair costs included in the CEMA is no longer probable, PG&E Corporation and the Utility will record a charge in the period such conclusion is reached. Failure to obtain a substantial or full recovery of these costs could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Wildfire Assistance Fund

On May 24, 2019, the Bankruptcy Court entered an order authorizing PG&E Corporation and the Utility to establish and fund a program (the “Wildfire Assistance Fund”) to assist those displaced by the 2018 Camp fire and 2017 Northern California wildfires with the costs of substitute or temporary housing (“Alternative Living Expenses”) and other urgent needs. The Wildfire Assistance Fund is intended to aid certain wildfire claimants who are either uninsured or still in need of assistance for Alternative Living Expenses or have other urgent needs. The Wildfire Assistance Fund consists of $105 million deposited into a segregated account controlled by an independent third-party administrator appointed by the Bankruptcy Court, who will disburse and administer the funds. Up to $5 million of the Wildfire Assistance Fund may be used to pay the costs of administering the fund. The establishment of the Wildfire Assistance Fund is not an acknowledgment or admission by PG&E Corporation or the Utility of liability with respect to the 2018 Camp fire or 2017 Northern California wildfires.

The Utility fully funded $105 million into the Wildfire Assistance Fund on August 2, 2019. As of November 1, 2019, the administrator issued claimant payments totaling $22 million under the Wildfire Assistance Fund. The deadline to apply for financial assistance under the fund is November 15, 2019.

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Wildfire Fund under AB 1054

On July 12, 2019, the California Governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Eligible claims are claims for third party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any calendar year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054.

Electric utility companies that draw from the fund will only be required to repay amounts that are determined by the CPUC in an application for cost recovery not to be just and reasonable, subject to a rolling three-year disallowance cap equal to 20% of the electric utility company’s transmission and distribution equity rate base. For the Utility, this disallowance cap is expected to be approximately $2.3 billion for the three-year period starting in 2019, subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable will not need to be repaid to the fund, resulting in a draw-down of the fund.

The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the Department of Water Resources charge to ratepayers, (ii) $7.5 billion in initial contributions from California’s three investor-owned electric utility companies and (iii) $300 million in annual contributions paid by California’s three investor-owned electric utility companies. The contributions from the investor-owned electric utility companies will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from ratepayers. The costs of the initial and annual contributions are allocated among the three investor-owned electric utility companies pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable utility’s service territory classified as high fire threat districts and adjusted to account for risk mitigation efforts. The Utility’s initial Wildfire Fund allocation metric is expected to be 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million). In addition, all initial and annual contributions will be excluded from the measurement of the Utility’s authorized capital structure. The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies.

On July 23, 2019, the Utility notified the CPUC of its intent to participate in the Wildfire Fund. On August 7, 2019, PG&E Corporation and the Utility submitted a motion with the Bankruptcy Court for the entry of an order authorizing PG&E Corporation and the Utility to participate in the Wildfire Fund and to make any initial and annual contributions to the Wildfire Fund upon emergence from Chapter 11. On August 26, 2019, the Bankruptcy Court entered an order granting such authorizations. In order to participate in the Wildfire Fund, the Utility must also meet the eligibility and other requirements set forth in AB 1054, and pay its share of the initial contribution to the Wildfire Fund upon emergence from Chapter 11. In such event (assuming the Utility satisfies the eligibility and other requirements set forth in AB 1054), the Wildfire Fund will be available to the Utility to pay for eligible claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11, subject to a limit of 40% of the amount of such claims. The balance of any such claims would need to be addressed through the Chapter 11 Cases.

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The Utility expects to record its required contributions as an asset and amortize the asset over the estimated life of the Wildfire Fund. The Wildfire Fund asset will be further adjusted for impairment as the assets are used to pay eligible claims, which will result in decreases to the assets available for coverage of future events. AB 1054 does not establish a definite term of the Wildfire Fund; therefore, this accounting treatment is subject to significant judgments and estimates. The assumptions create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The most significant assumption is the number and severity of catastrophic fires that could occur in California within the participating electric utilities’ service territories during the term of the Wildfire Fund. The Utility intends to utilize historical, publicly available fire-loss data as a starting point; however, future fire-loss can be difficult to estimate due to uncertainties around the impacts of climate change, land use changes, and mitigation efforts by the California electric utility companies. Other assumptions include the estimated cost of wildfires caused by other electric utilities, the amount at which wildfire claims will be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires, the level of future insurance coverage held by the electric utilities, and the future transmission and distribution equity rate base growth of other electric utilities. Significant changes in any of these estimates could materially impact the amortization period. There could also be a significant delay between the occurrence of a wildfire and the timing of which the Utility recognizes impairment for the reduction in future coverage, due to the lack of data available to the Utility following a catastrophic event, especially if the wildfire occurs in the service territory of another electric utility. As of September 30, 2019, the Utility has not reflected the required contributions in its Condensed Consolidated Financial Statements as it has not yet satisfied all of the Wildfire Fund eligibility criteria pursuant to AB 1054.

2015 Butte Fire

In September 2015, a wildfire (the “2015 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 2015 Butte fire. According to Cal Fire’s report, the 2015 Butte fire burned 70,868 acres, resulted in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures.  Cal Fire’s report concluded that the 2015 Butte fire 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, County of Sacramento.  Subrogation insurers also filed a separate master complaint on the same date.  The California Judicial Council previously had authorized the coordination of all cases in Sacramento County.  As of January 28, 2019, 95 known complaints were 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 3,900 individual plaintiffs representing approximately 2,000 households and their insurance companies.  These complaints were part of, or were in the process of being added to, the coordinated proceeding.  Plaintiffs sought to recover damages and other costs, principally based on the doctrine of inverse condemnation and negligence theory of liability.  Plaintiffs also sought punitive damages.  Several plaintiffs dismissed the Utility’s two vegetation management contractors from their complaints. The Utility does not expect the number of claimants to increase significantly in the future, because the statute of limitations for property damage and personal injury in connection with the 2015 Butte fire has expired. Further, due to the commencement of the Chapter 11 Cases, these plaintiffs have been stayed from continuing to prosecute pending litigation and from commencing new lawsuits against PG&E Corporation or the Utility on account of pre-petition obligations. On January 30, 2019, the Court in the coordinated proceeding issued an order staying the action.

On April 28, 2017, the Utility moved for summary adjudication on plaintiffs’ claims for punitive damages.  The court denied the Utility’s motion and the Utility filed a writ with the Court of Appeal of the State of California, Third Appellate District. The writ was granted on July 2, 2018, directing the trial court to enter summary adjudication in favor of the Utility and to deny plaintiffs’ claim for punitive damages under California Civil Code Section 3294. Plaintiffs sought rehearing and asked the California Supreme Court to review the Court of Appeal’s decision. Both requests were denied. Neither the trial nor appellate courts originally addressed whether plaintiffs can seek punitive damages at trial under Public Utilities Code Section 2106. However, the trial court, in November 2018, denied a motion filed by the Utility that would have confirmed that punitive damages under Public Utilities Code Section 2106 are unavailable. The Utility believes a loss related to punitive damages is unlikely, but possible.

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On June 22, 2017, the Superior Court of California, County of Sacramento ruled on a motion of several plaintiffs and found that the doctrine of inverse condemnation applied to the Utility with respect to the 2015 Butte fire. The court held, among other things, that the Utility had failed to put forth any evidence to support its contention that the CPUC would not allow the Utility to pass on its inverse condemnation liability through rate increases. While the ruling was binding only between the Utility and the plaintiffs in the coordination proceeding at the time of the ruling, others could make similar claims. On January 4, 2018, the Utility filed with the court a renewed motion for a legal determination of inverse condemnation liability, citing the November 30, 2017 CPUC decision denying the San Diego Gas & Electric Company application to recover wildfire costs in excess of insurance, and the CPUC declaration that it will not automatically allow utilities to spread inverse condemnation losses through rate increases.

On May 1, 2018, the Superior Court of California, County of Sacramento issued its ruling on the Utility’s renewed motion in which the court affirmed, with minor changes, its tentative ruling dated April 25, 2018. The court determined that it was bound by earlier holdings of two appellate courts decisions, Barham and Pacific Bell. Further, the court stated that the Utility’s constitutional arguments should be made to the appellate courts and suggested that, to the extent the Utility raised the public policy implications of the November 30, 2017 CPUC decision in the San Diego Gas & Electric Company cost recovery proceeding, these arguments should be addressed to the Legislature or CPUC. The Utility filed a writ with the Court of Appeal seeking immediate review of the court’s decision. On June 18, 2018, after the writ was summarily denied, the Utility filed a Petition for Review with the California Supreme Court, which also was denied. On September 6, 2018, the court set a trial for some individual plaintiffs to begin on April 1, 2019. The Utility reached agreement with two plaintiffs in the litigation to stipulate to judgment against the Utility on inverse condemnation grounds. The court granted the Utility’s stipulated judgment motion on November 29, 2018 and the Utility filed its appeal on December 11, 2018. As a result of the filing of the Chapter 11 Cases, these lawsuits, including the trial and the appeal from the stipulated judgment, are stayed.

In addition to the coordinated plaintiffs, Cal Fire, the OES, the County of Calaveras, the Calaveras County Water District, and four smaller public entities (three fire districts and the California Department of Veterans Affairs) brought suit or indicated that they intended to do so. The Calaveras County Water District and the four smaller public entities filed their complaints in August 2018 and September 2018. They were added to the coordinated proceedings. The Utility settled the claims of the three fire protection districts and the Calaveras County Water District.

On April 13, 2017, Cal Fire filed a complaint with the Superior Court of California, County of Calaveras, seeking to recover over $87 million for its costs incurred on the theory that the Utility and its vegetation management contractors were negligent, or violated the law, among other claims.  On July 31, 2017, Cal Fire dismissed its complaint against Trees, Inc., one of the Utility’s vegetation contractors. Cal Fire had requested that a trial of its claims be set in 2019, following any trial of the claims of the individual plaintiffs. On October 19, 2018, the Utility filed a motion for summary judgment arguing that Cal Fire cannot recover any fire suppression costs under the Third District Court of Appeal’s decision in Dep’t of Forestry & Fire Prot. v. Howell (2017) 18 Cal. App. 5th 154. The hearing on that motion was set for January 31, 2019, but the hearing and Cal Fire’s case against the Utility are now stayed. Prior to the stay, the Utility and Cal Fire were also engaged in a mediation process.

Also, on February 20, 2018, the County of Calaveras filed suit against the Utility and the Utility’s vegetation management contractors to recover damages and other costs, based on the doctrine of inverse condemnation and negligence theory of liability. The County also sought punitive damages. On March 2, 2018, the County served a mediation demand seeking in excess of $167 million, having previously indicated that it intended to bring an approximately $85 million claim against the Utility. This claim included costs that the County of Calaveras allegedly incurred or expected to incur for infrastructure damage, erosion control, and other costs. The Utility and the County of Calaveras settled the County’s claims in November 2018 for $25.4 million.

Further, in May 2017, the OES indicated that it intended to bring a claim against the Utility that it estimated to be approximately $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 2015 Butte fire. The Utility has not received any information or documentation from the OES since its May 2017 statement. In June 2017, the Utility entered into an agreement with the OES that extended its deadline to file a claim to December 2020.

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PG&E Corporation’s and the Utility’s obligations with respect to such outstanding claims are expected to be determined through the Chapter 11 process. As described in Note 2, on July 1, 2019, the Bankruptcy Court entered an order approving the Bar Date of October 21, 2019, at 5:00 p.m. (Pacific Time) for filing claims against PG&E Corporation and the Utility relating to the period prior to the Petition Date, including claims in connection with the 2015 Butte fire. On October 18, 2019, the TCC filed with the Bankruptcy Court a motion for entry of an order extending the Bar Date for individual wildfire-related claims. On October 28, 2019, PG&E Corporation and the Utility announced that they had offered to extend the Bar Date for individual wildfire-related claims from October 21, 2019 to December 20, 2019. On the same day, during a meet and confer between PG&E Corporation and the Utility and the TCC, and at the request of the TCC, PG&E Corporation and the Utility agreed to further extend the Bar Date for individual wildfire-related claims to December 31, 2019. On November 4, 2019, PG&E Corporation and the Utility and the TCC announced that they have reached agreement to an extension of the Bar Date for individual wildfire-related claims to December 31, 2019, which agreement also involves procedures for additional notice to potential individual wildfire claimants. PG&E Corporation and the Utility and the TCC will file a stipulation with the Bankruptcy Court detailing the terms of the agreement and seeking approval of their agreement. PG&E Corporation and the Utility have received numerous proofs of claim in connection with the 2015 Butte fire since the Petition Date and are early in the process of reconciling those claims to the amount listed in the schedules of assets and liabilities. See “Potential Claims” in Note 2 above.

Certain Federal, State and Local Claims in Connection with the 2015 Butte Fire

FEMA has filed a proof of claim in the Chapter 11 Cases in the amount of $161 million in connection with the 2015 Butte fire. The U.S. Department of the Interior has filed proofs of claim in the Chapter 11 Cases in the amount of $63 million in connection with the 2015 Butte fire.

In addition, Cal Fire has filed a proof of claim in the Chapter 11 Cases in the amount of $105 million in connection with the 2015 Butte fire. The OES has filed a proof of claim in the amount of $107 million in connection with the 2015 Butte fire.

Certain other Federal, state and local entities have filed proofs of claim in the Chapter 11 Cases in connection with the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire. Proofs of claim have also been filed for unspecified amounts to be determined at a later time.

PG&E Corporation and the Utility are early in the process of reviewing the proofs of claim that have been filed in the Chapter 11 Cases. It is possible that additional Federal, state and local entities have filed or will file proofs of claim for wildfire-related claims in the Chapter 11 Cases. PG&E Corporation and the Utility may ask the Bankruptcy Court to disallow claims that they believe are duplicative, have been later amended or superseded, are without merit, are overstated or should be disallowed for other reasons. See “Potential Claims” in Note 2. In addition, there is dispute over whether claims asserted by the U.S. Government and the State of California (including any department, agency or instrumentality thereof) are unliquidated and subject to estimation under section 502(c) of the Bankruptcy Code. On November 1, 2019, PG&E Corporation and the Utility filed a notice with the Bankruptcy Court designating the Federal and state agency claims they contend are unliquidated and subject to estimation under section 502(c) of the Bankruptcy Code. A hearing on this issue before the Bankruptcy Court is set for December 17, 2019.

Estimated Losses from Third-Party Claims

In connection with the 2015 Butte fire, the Utility may be liable for property damages, business interruption, interest, and attorneys’ fees without having been found negligent, through the doctrine of inverse condemnation.

In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility is found to have been negligent.  While the Utility believes it was not negligent, there can be no assurance that a court would agree with the Utility.

The Utility’s assessment of the estimated loss related to the 2015 Butte fire is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the number and types of trees damaged or destroyed, as well as assumptions about personal injury damages, attorneys’ fees, fire suppression costs, and certain other damages.

The Utility has determined that it is probable that it will incur a loss of $1.1 billion in connection with the 2015 Butte fire. While this amount includes the Utility’s assumptions about fire suppression costs (including its assessment of the Cal Fire loss), it does not include any portion of the estimated claim from the OES. The Utility still does not have sufficient information to reasonably estimate any liability it may have for that additional claim.

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The process for estimating costs associated with claims relating to the 2015 Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors.  As more information becomes known, management estimates and assumptions regarding the financial impact of the 2015 Butte fire may result in material increases to the loss accrued.

PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets included liabilities for 2015 Butte fire third-party claims of $212 million and $226 million as of September 30, 2019 and December 31, 2018, respectively, reflecting payments of $14 million in January 2019, prior to the Petition Date. As of September 30, 2019, the Utility has paid $888 million of the $904 million in settlements to date in connection with the 2015 Butte fire.

If the Utility records losses in connection with claims relating to the 2015 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, liquidity, and cash flows could be materially affected in the reporting periods during which additional charges are recorded.

Loss Recoveries

The Utility has liability insurance from various insurers, that provides coverage for third-party liability attributable to the 2015 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, 2019, the Utility recorded $922 million for probable insurance recoveries in connection with losses related to the 2015 Butte fire.  While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.  In addition, the Utility has received $60 million in cumulative reimbursements from the insurance policies of its vegetation management contractors. 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 balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets and was $50 million and $85 million as of September 30, 2019 and December 31, 2018, respectively, reflecting reimbursements of $35 million during the nine months ended September 30, 2019.

NOTE 11: OTHER 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 liability has been incurred and the amount of the liability can reasonably be estimated.  PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred.

The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. 

PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows may be materially affected by the outcome of the following matters.

Enforcement and Litigation Matters

U.S. District Court Matters and Probation

On August 9, 2016, the jury in the federal criminal trial against the Utility in the United States District Court for the Northern District of California, in San Francisco, found the Utility guilty on 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 January 26, 2017, the court imposed a sentence on the Utility in connection with the conviction. The court sentenced the Utility to a five-year corporate probation period, oversight by the Monitor for a period of five years, with the ability to apply for early termination after three years, a fine of $3 million to be paid to the federal government, certain advertising requirements, and community service.

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The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period. As part of the probation, the Utility has retained the Monitor at the Utility’s expense. The goal of the Monitor is to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations, and to maintain effective ethics, compliance and safety related incentive programs on a Utility-wide basis.

On November 27, 2018, the court overseeing the Utility’s probation issued an order requiring that the Utility, the United States Attorney’s Office for the Northern District of California (the “USAO”) and the Monitor provide written answers to a series of questions regarding the Utility’s compliance with the terms of its probation, including what requirements of the Utility’s probation “might be implicated were any wildfire started by reckless operation or maintenance of PG&E power lines” or “might be implicated by any inaccurate, slow, or failed reporting of information about any wildfire by PG&E.” The court also ordered the Utility to provide “an accurate and complete statement of the role, if any, of PG&E in causing and reporting the recent 2018 Camp fire in Butte County and all other wildfires in California” since January 2017 (“Question 4 of the November 27 Order”). On December 5, 2018, the court issued an order requesting that the Office of the California Attorney General advise the court of its view on “the extent to which, if at all, the reckless operation or maintenance of PG&E power lines would constitute a crime under California law.” The responses of the Attorney General were submitted on December 28, 2018, and the responses of the Utility, the USAO and the Monitor were submitted on December 31, 2018.

On January 3, 2019, the court issued a new order requiring that the Utility provide further information regarding the 2017 Atlas fire.  The court noted that “[t]his order postpones the question of the adequacy of PG&E’s response” to Question 4 of the November 27 Order.  On January 4, 2019, the court issued another order requiring that the Utility provide, “with respect to each of the eighteen October 2017 Northern California wildfires that [Cal Fire] has attributed to [the Utility’s] facilities,” information regarding the wind conditions in the vicinity of each fire’s origin and information about the equipment allegedly involved in each fire’s ignition.  The responses of the Utility were submitted on January 10, 2019.

On January 9, 2019, the court ordered the Utility to appear in court on January 30, 2019, as a result of the court’s finding that “there is probable cause to believe there has been a violation of the conditions of supervision” with respect to reporting requirements related to the 2017 Honey fire.  In addition, on January 9, 2019, the court issued an order (the “January 9 Order”) proposing to add new conditions of probation that would require the Utility, among other things, to:

•prior to June 21, 2019, “re-inspect all of its electrical grid and remove or trim all trees that could fall onto its power lines, poles or equipment in high-wind conditions, . . . identify and fix all conductors that might swing together and arc due to slack and/or other circumstances under high-wind conditions[,] identify and fix damaged or weakened poles, transformers, fuses and other connectors [and] identify and fix any other condition anywhere in its grid similar to any condition that contributed to any previous wildfires,”

•“document the foregoing inspections and the work done and . . . rate each segment’s safety under various wind conditions” and

•at all times from and after June 21, 2019, “supply electricity only through those parts of its electrical grid it has determined to be safe under the wind conditions then prevailing.”

The Utility was ordered to show cause by January 23, 2019 as to why the Utility’s conditions of probation should not be modified as proposed.  The Utility’s response was submitted on January 23, 2019. The court requested that Cal Fire file a public statement, and invited the CPUC to comment, by January 25, 2019.  On January 30, 2019, the court found that the Utility had violated a condition of its probation with respect to reporting requirements related to the 2017 Honey fire. Also, on January 30, 2019, the court ordered the Utility to submit to the court on February 6, 2019 the 2019 Wildfire Mitigation Plan that the Utility was required to submit to the CPUC by February 6, 2019 in accordance with SB 901, and invited interested parties to comment on such plan by February 20, 2019. In addition, on February 14, 2019, the court ordered the Utility to provide additional information, including on its vegetation clearance requirements. The Utility submitted its response to the court on February 22, 2019.

On March 5, 2019, the court issued an order proposing to add new conditions of probation that would require the Utility, among other things, to:

•“fully comply with all applicable laws concerning vegetation management and clearance requirements;”

•“fully comply with the specific targets and metrics set forth in its wildfire mitigation plan, including with respect to enhanced vegetation management;”

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•submit to “regular, unannounced inspections” by the Monitor “of PG&E’s vegetation management efforts and equipment inspection, enhancement, and repair efforts” in connection with a requirement that the Monitor “assess PG&E’s wildfire mitigation and wildfire safety work;”

•“maintain traceable, verifiable, accurate, and complete records of its vegetation management efforts” and report to the Monitor monthly on its vegetation management status and progress; and

•“ensure that sufficient resources, financial and personnel, including contractors and employees, are allocated to achieve the foregoing” and to forgo issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements as set forth above.”

The court ordered all parties to show cause by March 22, 2019, as to why the Utility’s conditions of probation should not be modified as proposed. The responses of the Utility, the USAO, Cal Fire, the CPUC, and non-party victims were filed on March 22, 2019. At a hearing on April 2, 2019, the court indicated it would impose the new conditions of probation proposed on March 5, 2019, on the Utility, and on April 3, 2019, the court issued an order imposing the new terms though amended the second condition to clarify that “[f]or purposes of this condition, the operative wildfire mitigation plan will be the plan ultimately approved by the CPUC.”

Also, on April 2, 2019, the court directed the parties to submit briefing by April 16, 2019, regarding whether the court can extend the term of probation beyond five years in light of the violation that has been adjudicated and whether the Monitor reports should be made public. The responses of the Utility, the USAO, and the Monitor were filed on April 16, 2019. The Utility’s response contended that the term of probation may not be extended beyond five years and the USAO’s response contended that whether the term of probation could be extended beyond five years was an open legal issue.

The court held a sentencing hearing on the probation violation related to reporting requirements in connection with the 2017 Honey fire on May 7, 2019. After that hearing, the court imposed two additional conditions of probation by order dated May 14, 2019: (1) requiring that PG&E Corporation’s Board of Directors, Chief Executive Officer, senior executives, the Monitor and U.S. Probation Officer visit the towns of Paradise and San Bruno “to gain a firsthand understanding of the harm inflicted on those communities;” and (2) requiring that a committee of PG&E Corporation’s Board of Directors assume responsibility for tracking progress of the 2019 Wildfire Mitigation Plan and the additional terms of probation regarding wildfire safety, reporting in writing to the full Board at least quarterly. The court also stated that it was not going to rule at this time on whether the court has authority to extend probation and would leave that question “in abeyance.” The court did not discuss whether the Monitor reports should be made public. Members of PG&E Corporation’s Board of Directors and senior management attended site visits to the Town of Paradise on June 7, 2019 and the City of San Bruno on July 16, 2019, which were coordinated by the U.S. Probation Officer overseeing the Utility’s probation. In addition, the Compliance and Public Policy Committee, a committee of PG&E Corporation’s Board of Directors, will be responsible for tracking the Utility’s progress against the Utility’s wildfire mitigation plan, as approved by the CPUC, and compliance with the terms of the Utility’s probation regarding wildfire safety.

On July 10, 2019, the court ordered the Utility to respond to a Wall Street Journal article titled “PG&E Knew for Years Its Lines Could Spark Wildfires, and Didn’t Fix Them” on a paragraph-by-paragraph basis, stating the extent to which each paragraph in the article is accurate.  The court also ordered the Utility to disclose all political contributions made by the Utility since January 1, 2017, and provide additional explanations regarding those contributions and dividends distributed prior to filing the Chapter 11 Cases. The Utility filed its response with the court on July 31, 2019. In the response, the Utility disagreed with the Wall Street Journal article’s suggestion that the Utility knew of the specific maintenance conditions that caused the 2018 Camp fire and nonetheless deferred work that would have addressed those conditions.

On July 26, 2019, the Monitor submitted a letter to the court regarding its VM field inspections (“VM inspections”), which were designed to evaluate the Utility’s compliance with aspects of its publicly-filed Wildfire Mitigation Plan’s EVM. The Monitor’s letter, which was filed on the public docket on August 14, 2019, provided its preliminary observations and preliminary findings, which included that (1) the Utility’s contractors had missed trees that should have been identified and worked under the EVM program; and (2) the Utility’s systems for recording, tracking and assigning EVM work were inconsistent and may have been contributing to the missed work. In its September 3, 2019 response to the Monitor’s letter, the Utility detailed its plan to address the concerns raised by the Monitor. The Monitor’s concerns and the Utility’s response were discussed at a hearing on September 17, 2019.

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During the September 17, 2019 hearing, the court asked the Utility to provide information about: (1) its preparation for high wind season; and (2) the number of fires 10 acres or greater allegedly caused by the Utility to date in 2019. The Utility responded on October 1, 2019 by describing its efforts to strengthen its programs and infrastructure to maximize safety and mitigate the potential wildfire risk during high wind season. The Utility also responded that as of September 17, 2019, the Utility’s equipment may have contributed to nine ignitions in 2019 that resulted in fires 10 acres or greater. Two of these fires were potentially caused by vegetation and one was potentially caused by equipment. On October 2, 2019, the court asked the Utility for further information regarding the three fires potentially caused by vegetation and equipment. In its response, which was filed on October 9, 2019, the Utility provided information regarding certain fires, including but not limited to total acreage of the fire, ignition date, and potential causes.

On October 8, 2019, the court held a hearing related to the Utility’s San Bruno community service. An additional related hearing is scheduled for November 12, 2019.

On October 14, 2019, the court issued a request for information in connection with the PSPS event the Utility initiated on October 9, 2019 that shut off power to approximately 738,000 customers in 34 counties across Northern and Central California, asking the Utility to file a statement setting forth, among other information, “how many trees and limbs fell or blew onto the deenergized lines and how many of those would likely have caused arcing had the power been left on.” The Utility’s response was filed on October 30, 2019.

On November 4, 2019, the court issued a request for information in connection with PSPS events the Utility initiated in late October of 2019, asking the Utility to file a statement setting forth, among other information, the same type of information requested on October 14, 2019 in connection with the PSPS event initiated on October 9, 2019. The Utility’s response is due on November 29, 2019.

CPUC and FERC Matters

OII into the 2017 Northern California Wildfires

On June 27, 2019, the CPUC issued an OII (the “2017 Northern California Wildfires OII”) to determine whether the Utility “violated any provision(s) of the California Public Utilities Code (PU Code), Commission General Orders (GO) or decisions, or other applicable rules or requirements pertaining to the maintenance and operation of its electric facilities that were involved in igniting fires in its service territory in 2017.”

The 2017 Northern California Wildfires OII discloses the findings of a June 13, 2019 report by the SED, which, among other things, alleges that the Utility committed 27 violations in connection with 12 of the 2017 Northern California wildfires (specifically, the Adobe, Atlas, Cascade, Norrbom, Nuns, Oakmont/Pythian, Partrick, Pocket, Point, Potter/Redwood, Sulphur and Youngs fires). As described in the OII, the 27 alleged violations include failure to maintain vegetation clearances, failure to identify and abate hazardous trees, improper record keeping, incomplete patrol prior to re-energizing a circuit, failure to retain evidence, failure to report an incident, and failure to maintain clearances between lines. No violations were identified by the SED in connection with the Cherokee, La Porte and Tubbs fires. The 37 fire was determined by the SED to not be a reportable incident. The SED report does not address the Lobo and McCourtney fires because Cal Fire referred its investigations into these fires to local law enforcement and the information contained in its investigation reports related to these fires remains confidential. On a status conference call before the assigned ALJ on July 29, 2019, the SED informed the parties that because the Nevada County District Attorney had decided not to pursue criminal charges in connection with the Lobo and McCourtney fires, the SED may add alleged violations related to those fires and the 2018 Camp fire to the OII.

The 2017 Northern California Wildfires OII required the Utility to (i) show cause by July 29, 2019 why it should not be sanctioned for the 27 violations alleged in the SED report and (ii) submit a report by August 5, 2019, responding to information requests relating to “matters of concern that […] warrant further investigation and possible charges for violations of law.” These latter matters include the following: (i) the Utility’s vegetation management procedures and practices, (ii) the Utility’s procedures and practices regarding use of “recloser” devices in fire risk areas and during fire season, (iii) the Utility’s lack of procedures or policies for proactive de-energization of power lines during times of extreme fire danger, and (iv) the Utility’s record-keeping and other practices. The Utility was also required to take certain corrective actions and provide information regarding the qualifications of vegetation management personnel within 30 days of the issuance of the 2017 Northern California Wildfires OII. The Utility was required to also file an application to develop an open source, publicly available asset management system/database and mobile app, the costs of development and continued operation of which would be at shareholder expense.

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As required by the OII, on July 29, 2019, the Utility filed its initial response to the OII. In the initial response, the Utility indicated that it intends to fully cooperate with the CPUC but also stated that it disagreed with certain of the alleged violations set forth in the OII. The Utility also filed a Corrective Actions Report and an Application to Develop a Mobile Application and Supporting Systems, both as required by the OII. Also as required by the OII, on August 5, 2019, the Utility submitted a report to respond to the information requests contained in the OII, as explained above.

On October 9, 2019, the SED disclosed investigation reports, which, among other things, allege that the Utility committed five violations in connection with the Lobo and McCourtney fires. On October 17, 2019, the SED filed a motion to add the alleged violations related to the Lobo and McCourtney fires to the OII. The Utility does not intend to oppose the motion. The SED has disclosed that its investigation report for the 2018 Camp fire may be available by mid-November 2019. It is uncertain when the SED will file a motion to add alleged violations related to the 2018 Camp fire to the OII. The assigned ALJ has scheduled evidentiary hearings in the OII to take place on December 9-13, 2019.

The Utility, SED, PAO, CUE, TURN, OSA, Mendocino and Sonoma Counties, Napa County, City and County of San Francisco, the City of Santa Rosa, and Thomas Del Monte have continued to engage in multilateral settlement discussions. The parties have not reached a settlement but have agreed to continue to engage in settlement discussions. The OII will continue to follow its procedural schedule.

Based on the information currently available, PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties, including fines or other remedies, on the Utility.  The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion and the number of factors that can be considered in determining penalties.  The Utility is unable to predict the timing and outcome of this proceeding. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility were required to pay a material amount of penalties or if the Utility were required to incur a material amount of costs that it cannot recover through rates.

This proceeding is not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of this proceeding are stayed.

OII and Order to Show Cause into the Utility’s Locate and Mark practices

On December 14, 2018, the CPUC issued an order instituting investigation and order to show cause (the “OII”) to assess the Utility’s practices and procedures related to the locating and marking of natural gas facilities. The OII directs the Utility to show cause as to why the CPUC should not find violations in this matter, and why the CPUC should not impose penalties, and/or any other forms of relief, if any violations are found. The Utility also is directed in the OII to provide a report on specific matters, including that it is conducting locate and mark programs in a safe manner.

The OII cites a report by the SED dated December 6, 2018, which alleges that the Utility violated the law pertaining to the locating and marking of its gas facilities and falsified records related to its locate and mark activities between 2012 and 2017. As described in the OII, the SED cites reports issued in this matter by two consultants retained by the Utility, that (i) included certain facts and conclusions about the extent of inaccuracies in the Utility’s late tickets and the reasons for the inaccuracies, and (ii) provided an analysis, based on the available data, of tickets that should be properly categorized as late, and identification of associated dig-ins. As a result, the OII will determine whether the Utility violated any provision of the Public Utilities Code, general orders, federal law adopted by California, other rules, or requirements, and/or other state or federal law, by its locate and mark policies, practices, and related issues, and the extent to which the Utility’s practices with regard to locate and mark may have diminished system safety.

The CPUC indicates that it has not concluded that the Utility has violated the law in any instance pertaining to late tickets, locating and marking, or any matter related to either, or to any other matter raised in this OII. However, if violations are found, the CPUC will consider what monetary fines and other remedies are appropriate, will review the duration of violations and, if supported by the evidence, it will consider ordering daily fines.

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On March 14, 2019, as directed by the CPUC, the Utility submitted a report that addressed the SED report and responded to the order to show cause.  A prehearing conference was held on April 4, 2019, to establish scope and a procedural schedule.  The assigned commissioner and ALJ encouraged the SED and the Utility to engage in settlement discussions.  On April 24, 2019, the Utility provided notice of a settlement conference and the parties began ongoing settlement discussions.  On May 7, 2019, the assigned commissioner issued a scoping memo and ruling that included within the proceedings, in addition to the issues identified in the OII relating to the Utility’s locate and mark procedures, issues relating to locating and marking of the Utility’s electric distribution facilities and the use of “qualified electrical workers” for locating and marking underground infrastructure. On July 24, 2019, the SED submitted its opening testimony to the CPUC.  A status conference with the ALJ was held on July 30, 2019. In accordance with the current procedural schedule issued by the ALJ on June 27, 2019, intervenor testimony was submitted on August 16, 2019, and the Utility’s reply testimony was submitted on September 18, 2019.

On October 3, 2019, the Utility, SED and CUE jointly submitted to the CPUC a proposed settlement agreement and jointly moved for its approval. The following parties have participated in the settlement negotiations but have not joined the settlement: PAO, TURN, OSA, and the City and County of San Francisco. The proposed settlement will be reviewed by the ALJ overseeing the proceeding, and these other parties will have an opportunity to provide comments on the proposed settlement agreement before a final CPUC decision is issued. On October 11, 2019, PAO, TURN, and OSA indicated that they intend to provide comments on the proposed settlement agreement. Pursuant to the settlement agreement, the Utility agreed to a total financial remedy of $65 million, comprised of (i) a fine of $5 million funded by shareholders to be paid to the General Fund of the State of California pursuant to, and in accordance with, the time frame and other provisions governing distributions as set forth in the Chapter 11 plan of reorganization for the Utility as confirmed by the Bankruptcy Court; and (ii) $60 million in shareholder-funded initiatives undertaken to enhance, among other things, the Utility’s locate and mark compliance and capabilities and the reliability of the Underground Service Alert ticket management information that the Utility maintains in the ordinary course of its business.

In accordance with the settlement agreement, shareholder-funded system enhancements will include, among other things, locate and mark ticket compliance audits to verify accurate categorization of timeliness, compliance audits using field reviews of gas and electric locate and mark tickets to assess performance, procedure adherence and compliance, and additional locate and mark staff. The expenditure of any sums not fully expended within three years of the effective date of the settlement agreement will be subject to further agreement among the parties.

The Utility expects that the system enhancement spending pursuant to this settlement agreement will occur through 2022.

The settlement agreement will become effective upon: (i) approval by the CPUC in a written decision and (ii) following such approval by the CPUC, approval by the Bankruptcy Court. The CPUC may accept, reject or modify the terms of the settlement agreement, including imposing additional penalties on the Utility.

On October 4, 2019, the ALJ issued a ruling modifying the procedural schedule to focus the evidentiary hearings on the proposed settlement agreement. An evidentiary hearing was held on October 21, 2019; comments on the settlement agreement were submitted by certain other parties on November 4, 2019, and reply comments are due November 19, 2019.

As of September 30, 2019, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets include a $5 million accrual for the amounts payable to the General Fund of the State of California.

Because the CPUC has wide discretion and there are a number of factors that can be considered in determining penalties, the Utility is unable to predict the timing and outcome of this proceeding. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility were required to pay a material amount of penalties beyond the amount reserved, or if the Utility were required to incur a material amount of costs that it cannot recover through rates.

This proceeding is not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of this proceeding are stayed.

For more information about this proceeding, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K.

OII into Compliance with Ex Parte Communication Rules

On April 26, 2018, the CPUC approved the revised PD issued on April 3, 2018, adopting the settlement agreement jointly submitted to the CPUC on March 28, 2017, as modified (the “settlement agreement”) by the Utility, the Cities of San Bruno and San Carlos, PAO, the SED, and TURN.

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The decision resulted 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 2020 GRC), and (4) compensation payments to the Cities of San Bruno and San Carlos in a total amount of $12 million ($6 million to each city).  In addition, the settlement agreement provides for certain non-financial remedies, including enhanced noticing obligations between the Utility and CPUC decision-makers, as well as certification of employee training on the CPUC ex parte communication rules.  Under the terms of the settlement agreement, customers will bear no costs associated with the financial remedies set forth above.

As a result of the CPUC’s April 26, 2018 decision, on May 17, 2018, the Utility made a $12 million payment to the California General Fund and $6 million payments to each of the Cities of San Bruno and San Carlos. At September 30, 2019, the Utility has refunded $24 million for a portion of the 2019 GT&S revenue requirement reduction. In accordance with accounting rules, adjustments related to revenue requirements are recorded in the periods in which they are incurred.

The CPUC also ordered a second phase in this proceeding to determine if any of the additional communications that the Utility reported to the CPUC on September 21, 2017, violate the CPUC ex parte rules. On June 28, 2019, the Cities of San Bruno and San Carlos, PAO, the SED, TURN, and the Utility filed a joint motion with the CPUC seeking approval of a comprehensive settlement agreement that addresses all issues in the second phase of this proceeding. The phase two settlement agreement proposed that the Utility pay a total penalty of $10 million comprised of: (1) a $2 million payment to the California General Fund, (2) forgoing collection of $5 million in revenue requirements during the term of its 2019 GT&S rate case, (3) forgoing collection of $1 million in revenue requirement during the term of its 2020 GRC cycle, and (4) compensation payments to the Cities of San Bruno and San Carlos in a total amount of $2 million ($1 million to each city). According to the terms of the phase two settlement, these payments and forgone collection would not take place until a plan of reorganization is approved in the Chapter 11 Cases. In accordance with accounting rules, adjustments related to forgone collections would be recorded in the periods in which they are incurred.

As of September 30, 2019, PG&E Corporation’s and the Utility’s Consolidated Balance Sheets include a $4 million accrual for the amounts payable to the California General Fund and the Cities of San Bruno and San Carlos. On September 20, 2019, the CPUC extended the statutory deadline until December 31, 2019 to review the phase two settlement agreement and to prepare a proposed decision. The Utility is unable to predict whether the CPUC will approve the settlement.

For more information about this proceeding, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K.

Transmission Owner Rate Case Revenue Subject to Refund

The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in the TO rate case. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, and March 1, 2018, for TO18 and TO19, respectively. Rates subject to refund for TO20 went into effect on May 1, 2019.

On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case and the Utility filed initial briefs on October 31, 2018, in response to the ALJ’s recommendations. The Utility expects the FERC to issue a decision in the TO18 rate case by late-2019, however, that decision will likely be the subject of requests for rehearing and appeal.

On September 21, 2018, the Utility filed an all-party settlement with FERC, which was approved by FERC on December 20, 2018, in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon issuance of a final unappealable decision in TO18.

On November 30, 2018, the FERC issued an order accepting the Utility’s October 2018 filing of its TO20 formula rate case, subject to hearings and refund, and established May 1, 2019, as the effective date for rate changes.  FERC also ordered that the hearings will be held in abeyance pending settlement discussions among the parties. 

The Utility is unable to predict the timing or outcome of FERC’s decisions in the TO18 and TO19 proceedings or the timing or outcome of the TO20 proceeding.

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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.

Other Matters

PG&E Corporation and the Utility are subject to various claims, lawsuits, and regulatory proceedings that separately are not considered material.  Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled $98 million at December 31, 2018. These amounts were included in Other current liabilities in the Condensed Consolidated Balance Sheets. On the Petition Date, these amounts were moved to LSTC. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

2015 GT&S Rate Case Capital Disallowance

On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case. The phase one decision excluded from rate base $696 million of capital spending in 2011 through 2014 in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. Additional charges may be required in the future based on the outcome of the CPUC’s audit of 2011 through 2014 capital spending. Capital disallowances are reflected in operating and maintenance expenses in the Condensed Consolidated Statements of Income. For more information, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K.

Environmental Remediation Contingencies

The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following:

	Balance at
(in millions)	September 30, 2019		December 31, 2018
Topock natural gas compressor station	$	382	$	369
Hinkley natural gas compressor station	143		146
Former manufactured gas plant sites owned by the Utility or third parties (1)	586		520
Utility-owned generation facilities (other than fossil fuel-fired),   other facilities, and third-party disposal sites (2)	115		111
Fossil fuel-fired generation facilities and sites (3)	116		137
Total environmental remediation liability	$	1,342	$	1,283

⁽¹⁾ Primarily driven by the following sites: Vallejo, San Francisco East Harbor and Outside East Harbor, Napa, Beach Street, San Francisco North Beach.

⁽²⁾ Primarily driven by the Geothermal landfill and Shell Pond site.

⁽³⁾ Primarily driven by the San Francisco Potrero Power Plant.

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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 in addition to 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 the environmental requirements on an ongoing basis, and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.

The Utility’s environmental remediation liability at September 30, 2019, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans and the Utility’s time frame for remediation.  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. At September 30, 2019, the Utility expected to recover $998 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC. 

For more information, see remediation site descriptions below and see Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 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. The Utility is also required to take measures to abate the effects of the contamination on the environment.

Topock Site

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018 and will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $207 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSM, where 90% of the costs are recovered in rates.

Hinkley Site

The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater 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 Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility 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 sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is currently conducting a background study on the site to better define the chromium plume boundaries. A draft background study report is expected to be issued in 2020 and finalized thereafter. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $129 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.

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Former Manufactured Gas Plants

Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has undertaken a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $621 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSM, where 90% of the costs are recovered in rates.

Utility-Owned Generation Facilities and Third-Party Disposal Sites

Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $91 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSM, where 90% of the costs are recovered in rates.

Fossil Fuel-Fired Generation Sites

In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $80 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.

Insurance

Wildfire Insurance

In 2018, PG&E Corporation and the Utility renewed their liability insurance coverage for wildfire events in an aggregate amount of approximately $1.4 billion for the period from August 1, 2018 through July 31, 2019, comprised of $700 million for general wildfire liability in policies covering wildfire and non-wildfire events (subject to an initial self-insured retention of $10 million per occurrence), and $700 million for wildfire property damages only, which included approximately $200 million of coverage through the use of a catastrophe bond. In 2019, PG&E Corporation and the Utility has liability insurance coverage for wildfire events in an amount of $430 million (subject to an initial self-insured retention of $10 million per occurrence) for the period of August 1, 2019 through July 31, 2020, and $1 billion in liability insurance coverage for non-wildfire events (subject to an initial self-insured retention of $10 million per occurrence), comprised of $520 million for the period of August 1, 2019 through July 31, 2020 and $480 million for the period of September 3, 2019 through September 2, 2020. PG&E Corporation and the Utility continue to pursue additional insurance coverage. Various coverage limitations applicable to different insurance layers could result in uninsured costs in the future depending on the amount and type of damages resulting from covered events.

PG&E Corporation’s and the Utility’s cost of obtaining the wildfire and non-wildfire insurance coverage in place for the period of August 1, 2019 through September 2, 2020 is approximately $212 million, compared to the approximately $50 million that the Utility is currently recovering through rates through December 31, 2019. The Utility intends to seek recovery for the full amount of premium costs paid in excess of the amount the Utility currently is recovering from customers through the end of the current GRC period, which ends on December 31, 2019.

PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur.  Through September 30, 2019, PG&E Corporation and the Utility recorded $1.38 billion for probable insurance recoveries in connection with the 2018 Camp fire and $842 million for probable insurance recoveries in connection with the 2017 Northern California wildfires. These amounts reflect an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies. The amount of the receivable is subject to change based on additional information. PG&E Corporation and the Utility intend to seek full recovery for all insured losses and believe it is reasonably possible that they will record a receivable for the full amount of the insurance limits in the future.

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Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL and European Mutual Association for Nuclear Insurance, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3.  If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment.  If NEIL were to exercise this assessment, as of the policy renewal on April 1, 2020, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $41 million.  If European Mutual Association for Nuclear Insurance losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 million, as of the policy renewal on April 1, 2020.  For more information about the Utility’s nuclear insurance coverage, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K. 

Tax Matters

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the resolution of audits.  As of September 30, 2019, it is reasonably possible that unrecognized tax benefits will decrease by approximately $10 million within the next 12 months.  PG&E Corporation and the Utility believe that the majority of the decrease will not impact net income. 

PG&E Corporation does not believe that the Chapter 11 Cases resulted in loss of or limitation on the utilization of any of the tax carryforwards. PG&E Corporation will continue to monitor the status of tax carryforwards during the pendency of the Chapter 11 Cases.

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, 2018, the Utility had undiscounted future expected obligations of approximately $40 billion. (See Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K.) The Utility has not entered into any new material commitments during the nine months ended September 30, 2019.

NOTE 12: SUBSEQUENT EVENTS

2019 Kincade Fire

On October 23, 2019, a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service territory of the Utility. The Cal Fire Kincade Fire Incident Update dated November 6, 2019, 7:00 p.m. Pacific Time (the “incident update”) indicated that the 2019 Kincade fire had consumed 77,758 acres and was 100% contained. In the incident update, Cal Fire reported 0 fatalities and four first responder injuries. The incident update also indicates the following: structures destroyed, 374 (consisting of 174 residential structures, 11 commercial structures and 189 other structures); and structures damaged, 60 (consisting of 35 residential structures, one commercial structure and 24 other structures).

On October 23, 2019, by 3 p.m. Pacific Time, the Utility had conducted a PSPS event and turned off the power to approximately 27,837 customers in Sonoma County, including Geyserville and the surrounding area. As part of the PSPS, the Utility’s distribution lines in these areas were deenergized. Following the Utility’s established and CPUC-approved PSPS protocols and procedures, transmission lines in these areas remained energized.

On October 24, 2019, the Utility submitted an electric incident report to the CPUC indicating that:

•at approximately 9:20 p.m. Pacific Time on October 23, 2019, the Utility became aware of a transmission level outage on the Geysers #9 Lakeville 230 kV line when the line relayed and did not reclose;

•at approximately 7:30 a.m. Pacific Time on October 24, 2019, a responding Utility troubleman patrolling the Geysers #9 Lakeville 230 kV line observed that Cal Fire had taped off the area around the base of transmission tower 001/006 in the area of the 2019 Kincade fire; and

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•on site Cal Fire personnel brought to the troubleman’s attention what appeared to be a broken jumper on the same tower.

The cause of the 2019 Kincade fire is under investigation by Cal Fire and the CPUC, and PG&E Corporation and the Utility are cooperating with their investigations. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2019 Kincade fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to all of the evidence in the possession of Cal Fire or other third parties.

Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information contained in the electric incident report and other information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is reasonably possible that they will incur a loss in connection with the 2019 Kincade fire. However, due to the limited amount of time that has elapsed since the start of the 2019 Kincade fire, the preliminary stages of the investigations, lack of access to potentially relevant evidence and the uncertainty as to the cause of the fire and the extent and magnitude of potential damages, PG&E Corporation and the Utility cannot reasonably estimate the amount or range of such possible loss.

While the cause of the 2019 Kincade fire remains under investigation and there are a number of unknown facts surrounding the cause of the 2019 Kincade fire, the Utility could be subject to significant liability in excess of insurance coverage that would be expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, as well as on the bankruptcy timing and process and the ability of the Utility to participate in the Wildfire Fund.

Impact of Recent and Future Public Safety Power Shutoffs

On October 9, 2019, the Utility initiated a PSPS event which was the subject of significant criticism, including from the California Governor and the CPUC. In connection with this PSPS event, the California Governor suggested that PG&E Corporation and the Utility provide affected customers an automatic credit or rebate of $100 per residential customer and $250 per small business, to be funded by PG&E Corporation’s and the Utility’s shareholders. On October 29, 2019, PG&E Corporation and the Utility announced that they would issue such credits to customers with respect to the October 9, 2019 PSPS event. PG&E Corporation and the Utility estimate that such credit will result in an approximately $90 million charge for the fourth quarter of 2019. As of the date of this filing, PG&E Corporation and the Utility do not expect to issue any similar customer credits in connection with any other PSPS events (whether past events or in the future). If PG&E Corporation or the Utility were to issue any credits, rebates or other payments in connection with any other PSPS events (whether past events or in the future), the aggregate amount of any such credits or rebates could be substantial and could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the PSPS program has had an adverse impact on PG&E Corporation’s and the Utility’s reputation with customers, regulators and policymakers and future PSPS events may increase these negative perceptions.

On October 28, 2019, the CPUC announced that it would open a formal investigation of 2019 PSPS events, utility compliance with CPUC regulations and requirements, any resulting violations, and potential actions to ensure utilities are held accountable. The CPUC will meet on November 13, 2019 to discuss initiating an investigation into whether California's investor-owned electric utilities prioritized safety and complied with the CPUC’s regulations and requirements with respect to their October 2019 PSPS events. The purpose of this investigation would be to investigate whether California’s investor-owned utilities’ actions to de-energize their electric facilities during hazardous weather conditions properly balance the need to provide reliable service with public safety. In later phases of this proceeding, the CPUC may consider taking action if violations of the CPUC’s decisions or general orders have been committed and to enforce compliance, if necessary. PG&E Corporation and the Utility are unable to predict the timing and outcome of such an investigation.

The Utility’s wildfire risk mitigation initiatives, including the PSPS program, as outlined in the 2019 Wildfire Mitigation Plan, involve substantial and ongoing expenditures and could involve other costs. The extent to which the Utility will be able to recover these expenditures and potential other costs through rates is uncertain.

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

OVERVIEW

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 regulated primarily by the CPUC and the FERC.  The CPUC has jurisdiction over the rates, terms, and conditions of service for the Utility’s electricity and natural gas distribution operations, electric generation, and natural gas transportation and storage.  The FERC has jurisdiction over the rates and terms and conditions of service governing the Utility’s electric transmission operations and interstate natural gas transportation contracts.  The NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.  The Utility is also subject to the jurisdiction of other federal, state, and local governmental agencies.

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s separate Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in this quarterly report.  It also should be read in conjunction with the 2018 Form 10-K.

Chapter 11 Proceedings

On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. PG&E Corporation’s and the Utility’s Chapter 11 Cases are being jointly administered under the caption In re: PG&E Corporation and Pacific Gas and Electric Company, Case No. 19-30088 (DM). For additional information regarding the Chapter 11 Cases, refer to the website maintained by Prime Clerk, LLC, PG&E Corporation’s and the Utility’s claims and noticing agent, at http://restructuring.primeclerk.com/pge.

For more information about the Chapter 11 Cases, see “Item 1A. Risk Factors – Risks Related to Chapter 11 Proceedings and Liquidity” and “Item 7. MD&A – Chapter 11 Proceedings” in the 2018 Form 10-K and Notes 2 and 5 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.

Going Concern

The accompanying Condensed Consolidated Financial Statements to this Form 10-Q have been prepared on a going concern basis, which contemplates the continuity of operations, the realization of assets and the satisfaction of liabilities in the normal course of business. However, PG&E Corporation and the Utility are facing extraordinary challenges relating to a series of catastrophic wildfires that occurred in Northern California in 2017 and 2018. As a result of these challenges, such realization of assets and satisfaction of liabilities are subject to uncertainty. For more information about the 2018 Camp fire and 2017 Northern California wildfires, see Note 10 of the Notes to the Condensed Consolidated Financial Statements and the 2018 Form 10-K.

Management has concluded that uncertainty regarding these matters raises substantial doubt about PG&E Corporation’s and the Utility’s ability to continue as going concerns, and their independent registered public accountants included an explanatory paragraph in their auditors’ reports relating to the consolidated balance sheets of PG&E Corporation and the Utility as of December 31, 2018 and 2017, and the related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the three years in the period ended December 31, 2018, included in the 2018 Form 10-K, which stated certain conditions exist which raise substantial doubt about PG&E Corporation’s and the Utility’s ability to continue as going concerns in relation to the foregoing. The Condensed Consolidated Financial Statements do not include any adjustments that might result from the outcome of these uncertainties. For more information about these matters, see Notes 1 and 2 to the Condensed Consolidated Financial Statements and the 2018 Form 10-K.

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Summary of Changes in Net Income and Earnings per Share

PG&E Corporation’s net loss was $1.6 billion and $4.0 billion in the three and nine months ended September 30, 2019, respectively, compared to net income of $564 million and $22 million in the same periods in 2018. PG&E Corporation recognized charges of $526 million and $2.0 billion associated with the 2018 Camp fire and the 2017 Northern California wildfires, respectively, for the three months ended September 30, 2019, with no corresponding charges during the same period in 2018. PG&E Corporation recognized charges of $2.4 billion and $4.0 billion associated with the 2018 Camp fire and the 2017 Northern California wildfires, respectively, for the nine months ended September 30, 2019, compared to charges of $2.1 billion, net of probable insurance recoveries of $385 million, associated with the 2017 Northern California wildfires during the same period in 2018.

Key Factors Affecting Financial Results

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

•The Outcome of the Chapter 11 Cases. For the duration of the Chapter 11 Cases, PG&E Corporation’s and the Utility’s business is subject to the risks and uncertainties of bankruptcy. For example, the Chapter 11 Cases could adversely affect the Utility’s relationships with suppliers and employees which, in turn, could adversely affect the value of the business and assets of PG&E Corporation and the Utility. PG&E Corporation and the Utility also have incurred and expect to continue to incur increased legal and other professional costs associated with the Chapter 11 Cases and the reorganization. At this time, it is not possible to predict with certainty the effect of the Chapter 11 Cases on their business or various creditors, or whether or when PG&E Corporation and the Utility will emerge from bankruptcy. PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity and cash flows depend upon confirming, and successfully implementing, on a timely basis, a plan of reorganization. On October 9, 2019, the Bankruptcy Court entered an order granting the motion of the TCC and the Ad Hoc Noteholder Committee to terminate the exclusive rights of PG&E Corporation and the Utility to file a plan of reorganization as to the TCC and the Ad Hoc Noteholder Committee. On October 17, 2019, the TCC and the Ad Hoc Noteholder Committee filed the TCC/Ad Hoc Noteholder Plan. (See Note 2 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) The resulting competing plan process could reduce the likelihood that the plan of reorganization that is ultimately approved by the CPUC and confirmed by the Bankruptcy Court is one filed by PG&E Corporation and the Utility and, in any event, could have a material effect on PG&E Corporation’s and the Utility’s ability to achieve confirmation of a plan of reorganization that would enable PG&E Corporation and the Utility to reach their stated goals.

If the TCC/Ad Hoc Noteholder Plan were consummated, holders of PG&E Corporation common stock would experience extreme dilution in their percentage ownership of PG&E Corporation and the value of their shares. Under the TCC/Ad Hoc Noteholder Plan, post-emergence, the pre-petition holders of PG&E Corporation common stock would hold approximately 0.1% of the total outstanding PG&E Corporation common stock (with the balance of the post-emergence PG&E Corporation common stock held (i) 59.3% by certain members of the Ad Hoc Noteholder Committee (with pre-emergence holders of PG&E Corporation common stock potentially being afforded the opportunity to make up to 5% of this investment through a rights offering) and (ii) 40.6% by one or both of the wildfire claimholder trusts). The TCC and Ad Hoc Noteholder Committee have requested that the Bankruptcy Court expedite the confirmation process of the TCC/Ad Hoc Noteholder Plan on a faster timetable than the Proposed Plan. As the TCC/Ad Hoc Noteholder Plan progresses through the Chapter 11 process, such progress could have a material adverse effect on PG&E Corporation’s stock price. Finally, it is possible that the changes in ownership contemplated by the TCC/Ad Hoc Noteholder Plan would result in an “ownership change” within the meaning of Section 382 of the Internal Revenue Code (and regulations thereunder), which could result in limitations on PG&E Corporation or the Utility to utilize their net operating loss carryforwards.

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•The Utility’s Ability to Fund Ongoing Operations and Other Capital Needs. In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement, which was approved on a final basis on March 27, 2019.  For the duration of the Chapter 11 Cases, PG&E Corporation and the Utility expect that the DIP Credit Agreement, together with cash on hand and cash flow from operations, will be the Utility’s primary source of capital to fund ongoing operations and other capital needs and that they will have limited, if any, access to additional financing. In the event that cash on hand, cash flow from operations, and availability under the DIP Credit Agreement are not sufficient to meet liquidity needs, PG&E Corporation and the Utility may be required to seek additional financing, and can provide no assurance that additional financing would be available or, if available, offered on acceptable terms.  The amount of any such additional financing could be limited by negative covenants in the DIP Credit Agreement, which include restrictions on PG&E Corporation’s and the Utility’s ability to, among other things, incur additional indebtedness and create liens on assets.

•The Impact of the 2018 Camp Fire and the 2017 Northern California Wildfires.  PG&E Corporation and the Utility face several uncertainties in connection with the 2018 Camp fire and 2017 Northern California wildfires, related to:

◦the amount of possible loss related to third-party claims (as of September 30, 2019, the Utility had incurred aggregate losses of $20.4 billion for claims in connection with the 2018 Camp fire and the 2017 Northern California wildfires, which reflects the low end of the range of reasonably estimated probable losses and is subject to change based on additional information), which aggregate possible losses, if the Utility were found liable for certain or all of the costs, expenses and other losses in connection with the 2018 Camp fire and 2017 Northern California wildfires could exceed $30 billion (not including potential punitive damages, fines and penalties or damages related to future claims);

◦whether, in light of the CPUC July 8, 2019 final decision in the CHT OIR that excludes companies in Chapter 11 from accessing the CHT, the Utility will be able to obtain a substantial recovery of costs related to the 2017 Northern California wildfires;

◦the impact of investigations, including criminal, regulatory, and SEC investigations;

◦the outcome of the 2017 Northern California Wildfires OII, and any resulting fines or penalties;

◦fines or penalties, which could be material, if any regulatory or law enforcement agency were to bring an enforcement action, including a criminal proceeding, and determine that the Utility had failed to comply with applicable laws and regulations;

◦the amount of punitive damages, fines and penalties, or damages in respect of future claims, which could be material;

◦the applicability of the doctrine of inverse condemnation in the 2018 Camp fire and 2017 Northern California wildfires litigation, which the Utility is continuing to challenge by filing a brief on the inverse condemnation cause of action with the Bankruptcy Court on October 25, 2019;

◦the applicability of other theories of liability, including negligence, related to the 2018 Camp fire and 2017 Northern California wildfire claims;

◦the recoverability of the above-mentioned costs, even if a court decision imposes liability under the doctrine of inverse condemnation;

◦the ability of PG&E Corporation and the Utility to finance costs, expenses and other possible losses in respect of claims related to the 2018 Camp fire and the 2017 Northern California wildfires, through securitization mechanisms or otherwise;

◦the amount and recoverability of enhanced and accelerated inspection costs of the Utility’s electric transmission and distribution assets (the Utility incurred costs of $121 million and $606 million for enhanced and accelerated inspection and repair costs for the three and nine months ended September 30, 2019, respectively); and

◦the amount and recoverability of clean-up and repair costs (the Utility incurred costs of $1.05 billion for clean-up and repair of the Utility’s facilities through September 30, 2019).

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(See Notes 4 and 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and Item 1A. Risk Factors in Part II.)

•The Impact of the 2019 Kincade Fire. Regardless of whether the Utility is determined to have caused the 2019 Kincade fire, the 2019 Kincade fire is expected to have numerous adverse consequences to PG&E Corporation and the Utility, including, among others:

◦PG&E Corporation’s and the Utility’s ability to consummate the Proposed Plan by June 30, 2020 (or at all) could be impaired, and PG&E Corporation and the Utility may not be able to amend the Proposed Plan, or develop another alternative to the Proposed Plan, that could be confirmed by June 30, 2020 (or at all);

◦depending on the number and type of structures damaged or destroyed by the 2019 Kincade fire or the amount of post-petition claims against PG&E Corporation or the Utility as a result of the 2019 Kincade fire, PG&E Corporation and the Utility may not be able to satisfy, or obtain a waiver of, the conditions precedent to the commitments under the Backstop Commitment Letters or the Debt Commitment Letters, or the Backstop Parties or the Commitment Parties, respectively, may have the right to terminate such commitments, which would jeopardize PG&E Corporation’s and the Utility’s ability to finance the Proposed Plan;

◦PG&E Corporation and the Utility may not be able to obtain alternative financing to the transactions contemplated by the Backstop Commitment Letters and the Debt Commitment Letters, and may not be able to obtain financing for an alternative plan that may be proposed by PG&E Corporation and the Utility after the impact of the 2019 Kincade fire is better known;

◦the Utility could be subject to significant liability in excess of insurance coverage that would be expected to have a material impact on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows;

◦PG&E Corporation, which has experienced significant declines in stock price since the beginning of the 2019 Kincade fire, could fail to satisfy the continued listing criteria of the New York Stock Exchange, which could result in the suspension of trading of PG&E Corporation common stock or Utility preferred stock and delisting of such securities;

◦the 2019 Kincade fire may have adverse consequences on the Utility’s probation proceeding, the Utility’s proceedings with the CPUC and FERC (including the 2017 Northern California Wildfires OII, the Safety Culture OII and the Chapter 11 Proceedings OII), the criminal investigation into the 2018 Camp fire and future regulatory proceedings, including future applications for the safety certification required by AB 1054;

◦PG&E Corporation and the Utility may experience even greater difficulty in securing adequate insurance coverage for wildfire risks; and

◦PG&E Corporation and the Utility expect to suffer additional reputational harm and face an even more challenging operating, political, and regulatory environment.

•The Uncertainties in Connection with Any Future Wildfires, Wildfire Insurance, and AB 1054. While PG&E Corporation and the Utility cannot predict the occurrence, timing or extent of damages in connection with future wildfires, factors such as environmental conditions (including weather and vegetation conditions) and the efficacy of wildfire risk mitigation initiatives are expected to influence the frequency and severity of future wildfires. Although the financial impact of future wildfires could be mitigated through insurance, the Utility may not be able to obtain sufficient wildfire insurance coverage at a reasonable cost, or at all, and any such coverage may include limitations that could result in substantial uninsured losses depending on the amount and type of damages resulting from covered events. In addition, the policy reforms contemplated by AB 1054 are likely to affect the financial impact of future wildfires on PG&E Corporation and the Utility should any such wildfires occur. The Wildfire Fund would be available to the Utility to pay eligible claims for liabilities arising from future wildfires and would serve as an alternative to traditional insurance products, provided that the Utility satisfies the numerous conditions to the Utility’s participation in the Wildfire Fund set forth in AB 1054 and that the Wildfire Fund has sufficient remaining funds.

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However, the impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including the Utility’s eligibility to access relief under the Wildfire Fund (which is dependent on, among other things, the Chapter 11 Cases being resolved by June 30, 2020 pursuant to a plan or similar document not subject to a stay and the Utility making its initial contribution thereto), the Utility’s ability to demonstrate to the CPUC that wildfire-related costs paid from the Wildfire Fund were just and reasonable, and whether the benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs. The Utility may not be able to finance its required contributions to the Wildfire Fund, which consist of an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million. Finally, even if the Utility satisfies the eligibility and other requirements set forth in AB 1054, for eligible claims against the Utility arising between July 12, 2019 and the Utility’s emergence from Chapter 11, the availability of the Wildfire Fund to pay such claims will be capped at 40% of the amount of such claims.

•The AB 1054 Deadline of June 30, 2020. In the event that PG&E Corporation and the Utility are unable to confirm a plan of reorganization by June 30, 2020, the Utility will not be eligible to participate in the Wildfire Fund established under AB 1054. In that scenario, the Utility (i) would be unable to seek payment from the Wildfire Fund for liabilities arising from wildfires occurring after the July 12, 2019 effective date of AB 1054 (which in the case of pre-emergence wildfires, such as the 2019 Kincade fire, would be limited to 40% of such liabilities), (ii) would not receive the benefit of the 20% disallowance cap contemplated by AB 1054, (iii) would not be required to make any contributions to the Wildfire Fund, (iv) in applications for cost recovery for wildfires occurring after July 12, 2019, would nevertheless be subject to review under the “just and reasonable” standard set forth in section 451.1 of the Public Utilities Code (i.e., the standard as modified by AB 1054) and (v) may be eligible to obtain the annual safety certifications contemplated by section 8389 of the Public Utilities Code (which has implications for the burden of proof in a proceeding for cost recovery under section 451.1 of the Public Utilities Code). Under certain circumstances, it is possible that a successor corporation to the Utility which is formed after July 12, 2019 could be authorized to participate in the Wildfire Fund if the administrator of the Wildfire Fund determines that such successor corporation meets the requirements for participation in the Wildfire Fund set forth in AB 1054. There can be no assurance that such a successor corporation would be authorized to participate in the Wildfire Fund or that, even if it were, that investors in PG&E Corporation common stock would own an interest in such successor corporation or otherwise directly or indirectly receive any benefits from such participation.

•The Uncertainties Regarding the Impact of Recent and Future Public Safety Power Shutoffs. The Utility’s wildfire risk mitigation initiatives involve substantial and ongoing expenditures and could involve other costs. The extent to which the Utility will be able to recover these expenditures and potential other costs through rates is uncertain. The PSPS program, one of the Utility’s wildfire risk mitigation initiatives outlined in the 2019 Wildfire Mitigation Plan, has been the subject of significant recent criticism, including from the California Governor and the CPUC. In connection with the PSPS event initiated on October 9, 2019, the California Governor suggested that PG&E Corporation and the Utility provide affected customers an automatic credit or rebate of $100 per residential customer and $250 per small business, to be funded by PG&E Corporation’s and the Utility’s shareholders. On October 29, 2019, PG&E Corporation and the Utility announced that they would issue such credits to customers with respect to the October 9, 2019 PSPS event. PG&E Corporation and the Utility estimate that such credit will result in an approximately $90 million charge for the fourth quarter of 2019. As of the date of this filing, PG&E Corporation and the Utility do not expect to issue any similar customer credits in connection with any other PSPS events (whether past events or in the future). If PG&E Corporation or the Utility were to issue any credits, rebates or other payments in connection with any other PSPS events (whether past events or in the future), the aggregate amount of any such credits, rebates, or other payments could be substantial and could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the PSPS program has had an adverse impact on PG&E Corporation’s and the Utility’s reputation with customers, regulators and policymakers and future PSPS events may increase these negative perceptions. On October 28, 2019, the CPUC announced it would open a formal investigation of 2019 PSPS events, utility compliance with CPUC regulations and requirements, any resulting violations, and potential actions to ensure utilities are held accountable. PG&E Corporation and the Utility cannot predict the timing and outcome of such an investigation.

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•The Outcome of Other Enforcement, Litigation, and Regulatory Matters, and Other Government Proposals. The Utility’s financial results may continue to be impacted by the outcome of other current and future enforcement, litigation (to the extent not stayed as a result of the Chapter 11 Cases), and regulatory matters, including those described above as well as the outcome of the Locate and Mark OII, the outcome of the Safety Culture OII, the outcome of phase two of the ex parte OII, the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction, including the oversight of the Utility’s probation and the potential recommendations by the Monitor, and potential penalties in connection with the Utility’s safety and other self-reports. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) In addition, the Utility’s business profile and financial results could be impacted by the outcome of recent calls for municipalization of part or all of the Utility’s businesses and offers by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions. Finally, on November 1, 2019, the California Governor held a press conference covering various topics relevant to PG&E Corporation and the Utility. Among other statements, the California Governor noted that “If [PG&E Corporation and the Utility] are unable to secure [their] own fate and future . . . then the State will prepare itself as backup for a scenario where we do that job for them.” PG&E Corporation and the Utility cannot predict the nature, occurrence, timing or extent of any such “backup” scenario, and there can be no assurance that any such scenario would not involve significant ownership or management changes to PG&E Corporation or the Utility, including by the State of California.

•The Timing and Outcome of Ratemaking Proceedings. The Utility’s financial results may be impacted by the timing and outcome of its 2020 GRC, FERC TO18, TO19, and TO20 rate cases, 2020 cost of capital proceeding, and its ability to timely recover costs not currently in rates, including costs already incurred and future costs tracked in its CEMA, WEMA, FHPMA, WMPMA, and FRMMA that are incurred in connection with the Utility's 2019 Wildfire Mitigation Plan, the amount of which is substantial and is expected to increase.  The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, potential rate impacts, the Utility’s reputation, the regulatory and political environments, and other factors.  (See Notes 4 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and “Regulatory Matters” below.)

•The Utility’s Compliance with the CPUC Capital Structure. The CPUC’s capital structure decisions require the Utility to maintain a 52% equity ratio on average over the period that the authorized capital structure is in place, and to file an application for a waiver to the capital structure condition if an adverse financial event reduces its equity ratio by 1% or more. Due to the net charges recorded in connection with the 2018 Camp fire and the 2017 Northern California wildfires as of December 31, 2018, the Utility submitted to the CPUC an application for a waiver of the capital structure condition on February 28, 2019. The waiver is subject to CPUC approval. The CPUC’s decisions state that the Utility shall not be considered in violation of these conditions during the period the waiver application is pending resolution. The Utility is unable to predict the timing and outcome of its waiver application. (See “Regulatory Matters” below.)

•Personnel Changes. The Utility has recently experienced significant changes in leadership, in particular with the addition of a new Chief Executive Officer of the Utility, Andrew Vesey, and turnover at the position of head of gas operations. Although the appointment of Mr. Vesey is expected to bring strong leadership to both the gas and electric businesses, further management turnover may be disruptive to operations and impair PG&E Corporation’s and the Utility’s ability to execute their strategies and operational initiatives.

For more information about the factors and risks that could affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, or that could cause future results to differ from historical results, see “Item 1A. Risk Factors” in this Form 10-Q and the 2018 Form 10-K.  In addition, this quarterly report contains forward-looking statements that are necessarily subject to various risks and uncertainties.  These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report.  See the section entitled “Forward-Looking Statements” below for a list of some of the factors that may cause actual results to differ materially.  PG&E Corporation and the Utility are not able to predict all the factors that may affect future results and do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

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RESULTS OF OPERATIONS

PG&E Corporation

The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below.  The following table provides a summary of net income (loss) for the three and nine months ended September 30, 2019 and 2018:

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2019		2018		2019		2018
Consolidated Total	$	(1,619)	$	564	$	(4,039)	$	22
PG&E Corporation	(6)		(4)		(2)		(15)
Utility	$	(1,613)	$	568	$	(4,037)	$	37

PG&E Corporation’s net income (loss) primarily consists of income taxes, interest income on cash held, interest expense on long-term debt, and reorganization items.

Utility

The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2019 and 2018.  The table separately identifies 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.

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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, 2019						Three Months Ended September 30, 2018
	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	$	2,232	$	1,322	$	3,554	$	1,996	$	1,471	$	3,467
Natural gas operating revenues	714		164		878		778		137		915
Total operating revenues	2,946		1,486		4,432		2,774		1,608		4,382
Cost of electricity	—		1,070		1,070		—		1,256		1,256
Cost of natural gas	—		68		68		—		69		69
Operating and maintenance	1,816		392		2,208		1,247		364		1,611
Wildfire-related claims, net of insurance recoveries	2,548		—		2,548		(10)		—		(10)
Depreciation, amortization, and decommissioning	840		—		840		759		—		759
Total operating expenses	5,204		1,530		6,734		1,996		1,689		3,685
Operating income (loss)	(2,258)		(44)		(2,302)		778		(81)		697
Interest income	18		—		18		14		—		14
Interest expense	(52)		—		(52)		(229)		—		(229)
Other income, net	13		44		57		22		81		103
Reorganization items	(69)		—		(69)		—		—		—
Income (Loss) before income taxes	$	(2,348)	$	—	$	(2,348)	$	585	$	—	$	585
Income tax provision (benefit) (1)					(738)						14
Net income (loss)					(1,610)						571
Preferred stock dividend requirement					3						3
Income (Loss) Attributable to Common Stock					$	(1,613)					$	568

⁽¹⁾ This item impacted earnings for the three months ended September 30, 2019 and 2018.

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	Nine Months Ended September 30, 2019						Nine Months Ended September 30, 2018
	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	$	6,017	$	3,275	$	9,292	$	5,911	$	3,819	$	9,730
Natural gas operating revenues	2,300		794		3,094		2,268		674		2,942
Total operating revenues	8,317		4,069		12,386		8,179		4,493		12,672
Cost of electricity	—		2,506		2,506		—		3,038		3,038
Cost of natural gas	—		515		515		—		437		437
Operating and maintenance	5,071		1,181		6,252		3,742		1,260		5,002
Wildfire-related claims, net of insurance recoveries	6,448		—		6,448		2,108		—		2,108
Depreciation, amortization, and decommissioning	2,433		—		2,433		2,257		—		2,257
Total operating expenses	13,952		4,202		18,154		8,107		4,735		12,842
Operating income (loss)	(5,635)		(133)		(5,768)		72		(242)		(170)
Interest income	61		—		61		34		—		34
Interest expense	(213)		—		(213)		(668)		—		(668)
Other income, net	54		133		187		79		242		321
Reorganization items	(237)		—		(237)		—		—		—
Loss before income taxes	$	(5,970)	$	—	$	(5,970)	$	(483)	$	—	$	(483)
Income tax provision (benefit) (1)					(1,943)						(530)
Net income (loss)					(4,027)						47
Preferred stock dividend requirement					10						10
Income (Loss) Attributable to Common Stock					$	(4,037)					$	37

⁽¹⁾ This item impacted earnings for the nine months ended September 30, 2019 and 2018.

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, 2019 and 2018, focusing on revenues and expenses that impacted earnings for these periods. 

Operating Revenues

The Utility’s electric and natural gas operating revenues that impacted earnings increased by $172 million, or 6%, and $138 million, or 2% in the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018, primarily due to additional base revenues authorized in the 2017 GRC and 2019 GT&S rate cases.

Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings increased by $569 million, or 46%, in the three months ended September 30, 2019, compared to the same period in 2018, primarily due to $237 million in disallowed costs for previously incurred capital expenditures in excess of adopted amounts in the 2019 GT&S rate case, with no similar charges in the same period in 2018. Additionally, the Utility incurred $121 million in costs related to enhanced and accelerated inspections and repairs of transmission and distribution assets, with no similar charges in the same period in 2018. The Utility also incurred costs of $25 million and $15 million for legal and other costs and clean-up and repair costs, respectively, related to the 2018 Camp fire in the three months ended September 30, 2019, with no similar charges in the same period in 2018.

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The Utility’s operating and maintenance expenses that impacted earnings increased by $1.3 billion, or 36%, in the nine months ended September 30, 2019, compared to the same period in 2018, primarily due to $606 million related to enhanced and accelerated inspections and repairs of transmission and distribution assets, with no similar charges in the same period in 2018. Additionally, the Utility incurred costs of $265 million and $57 million for clean-up and repair costs and legal and other costs, respectively, relating to the 2018 Camp fire for the nine months ended September 30, 2019, with no similar charges in the same period in 2018. The Utility also incurred $237 million in disallowed costs for previously incurred capital expenditures in excess of adopted amounts in the 2019 GT&S rate case, with no similar charges in the same period in 2018.

Wildfire-related claims, net of insurance recoveries

Costs related to wildfires that impacted earnings increased by $2.6 billion, and $4.3 billion, in the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018. The Utility recognized pre-tax charges of $526 million and $2.0 billion associated with the 2018 Camp fire and 2017 Northern California wildfires, respectively, for the three months ended September 30, 2019, with no corresponding charges during the same period in 2018. The Utility recognized charges of $2.4 billion and $4.0 billion, associated with the 2018 Camp fire and the 2017 Northern California wildfires, respectively, for the nine months ended September 30, 2019, compared to charges of $2.1 billion, net of probable insurance recoveries of $385 million, associated with the 2017 Northern California wildfires during the same period in 2018.

(See “Item 1A. Risk Factors” in the 2018 Form 10-K and Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.)

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning expenses that impacted earnings increased by $81 million, or 11%, and $176 million, or 8%, in the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018, primarily due to capital additions and an increase in depreciation rates associated with the 2019 GT&S rate case.

Interest Income

There was no material change to interest income that impacted earnings for the periods presented.

Interest Expense

Interest expense that impacted earnings decreased by $177 million, or 77%, and $455 million, or 68% in the three and nine months ended September 30, 2019, respectively, compared to the same periods in 2018, primarily due to the cessation of interest accruals on outstanding pre-petition debt beginning January 29, 2019 in connection with the Chapter 11 Cases.

Other Income, Net

There were no material changes to other income, net, that impacted earnings for the periods presented.

Reorganization items, net

Reorganization items, net increased by $69 million and $237 million in the three and nine months ended September 30, 2019, respectively, with no corresponding charges during the same periods in 2018. The Utility recognized $83 million and $278 million, respectively, of expenses directly associated with the Utility’s Chapter 11 filing in the three and nine months ended September 30, 2019, partially offset by interest income of $14 million and $41 million, respectively.

(See “Item 1A. Risk Factors” in the 2018 Form 10-K and Note 2 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.)

Income Tax Provision (Benefit)

Income tax benefit increased by $752 million and $1.4 billion in the three and nine months ended September 30, 2019 as compared to the same periods in 2018. The increase in the income tax benefit was primarily the result of higher pre-tax loss in the three and nine months ended September 30, 2019, compared to the same periods in 2018.

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The following table reconciles the income tax expense at the federal statutory rate to the income tax provision:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Federal statutory income tax rate	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) in income tax rate resulting from:
State income tax (net of federal benefit) (1)	7.5	%	2.1	%	7.6	%	22.8	%
Effect of regulatory treatment of fixed asset differences (2)	2.4	%	(15.9)	%	3.8	%	56.4	%
Tax credits	0.1	%	(0.5)	%	0.1	%	1.9	%
Other, net	0.4	%	(4.2)	%	0.1	%	7.7	%
Effective tax rate	31.4	%	2.5	%	32.6	%	109.8	%

⁽¹⁾ Includes the effect of state flow-through ratemaking treatment.

⁽²⁾ Includes the effect of federal flow-through ratemaking treatment for certain property-related costs as authorized by various CPUC decisions.  All amounts are impacted by the level of income before income taxes.  The various CPUC rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related costs for federal tax purposes.  For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities.  Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse.  PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.  In 2018 and 2019, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 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

The Utility’s cost of electricity includes the 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.  The costs also include net sales (Utility owned generation and third parties) in the CAISO electricity markets. (See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)  The Utility’s total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility’s own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of electricity.

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2019		2018		2019		2018
Cost of purchased power, net (1)	$	1,001	$	1,174	$	2,296	$	2,846
Fuel used in generation facilities	69		82		210		192
Total cost of electricity	$	1,070	$	1,256	$	2,506	$	3,038

⁽¹⁾ Cost of purchased power, net decreased for the three and nine months ended September 30, 2019, compared to the same periods in 2018, primarily due to lower Utility electric customer demand, driven by customer departures to CCAs and DA providers, and by higher net sales in the CAISO electricity markets.

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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 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)  The Utility’s cost of natural gas is impacted by the market price of natural gas, changes in the cost of storage and transportation, and changes in customer demand. 

	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2019		2018		2019		2018
Cost of natural gas sold	$	42	$	45	$	433	$	355
Transportation cost of natural gas sold	26		24		82		82
Total cost of natural gas	$	68	$	69	$	515	$	437

Operating and Maintenance Expenses

The Utility’s operating expenses that did not impact earnings include certain costs that the Utility is authorized to recover as incurred such as pension contributions and public purpose programs costs.  If the Utility were to spend more than authorized amounts, these expenses could have an impact to earnings.

Other Income, Net

The Utility’s other income, net that did not impact earnings includes pension and other post-retirement benefit costs that fluctuate primarily from market and interest rate changes.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement. The DIP Credit Agreement provides for $5.5 billion in senior secured superpriority debtor in possession credit facilities in the form of (i) a revolving credit facility in an aggregate amount of $3.5 billion (the “DIP Revolving Facility”), including a $1.5 billion letter of credit subfacility, (ii) a term loan facility in an aggregate principal amount of $1.5 billion (the “DIP Initial Term Loan Facility”) and (iii) a delayed draw term loan facility in an aggregate principal amount of $500 million (the “DIP Delayed Draw Term Loan Facility,” together with the DIP Revolving Facility and the DIP Initial Term Loan Facility, the “DIP Facilities”), subject to the terms and conditions set forth therein. On March 27, 2019, the Bankruptcy Court approved the DIP Facilities on a final basis, authorizing the Utility to borrow up to the remainder of the DIP Revolving Facility (including the remainder of the $1.5 billion letter of credit subfacility), the DIP Initial Term Loan Facility and the DIP Delayed Draw Term Loan Facility, in each case subject to the terms and conditions of the DIP Credit Agreement. (For more information on the DIP Credit Agreement, see “DIP Credit Agreement” below and Note 5 of the Notes to the Consolidated Financial Statements in Item 1.)

For the duration of the Chapter 11 Cases, the Utility’s ability to fund operations, finance capital expenditures and pay other ongoing expenses and make distributions to PG&E Corporation will primarily depend on the levels of its operating cash flows and availability under the DIP Credit Agreement. The Utility expects that the DIP Facilities will provide it with sufficient liquidity to fund its ongoing operations, including its ability to provide safe service to customers, during the Chapter 11 Cases. For the duration of the Chapter 11 Cases, PG&E Corporation’s ability to fund operations and pay other ongoing expenses will primarily depend on cash on hand and intercompany transfers. In the event that PG&E Corporation’s and the Utility’s capital needs increase materially due to unexpected events or transactions, additional financing outside of the DIP Facilities may be required, which would be subject to approval by the Bankruptcy Court. Such approval is not assured. For more information on PG&E Corporation’s and the Utility’s material commitments for capital expenditures, see “Regulatory Matters” below.

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During 2018 and January 2019, PG&E Corporation’s and the Utility’s credit ratings were subject to multiple downgrades by Fitch, S&P and Moody’s including to ratings below investment grade and ultimately to “D” or low “C” ratings. In the first quarter of 2019, Moody’s and Fitch withdrew each of their credit ratings for PG&E Corporation and the Utility as a result of the Chapter 11 Cases. As a result of PG&E Corporation’s and the Utility’s credit ratings ceasing to be rated at investment grade, the Utility has been required to post additional collateral under its commodity purchase agreements and certain other obligations, and has been exposed to significant constraints on its customary trade credit. In addition, PG&E Corporation and the Utility may be required to post additional collateral in respect of certain other obligations, including workers’ compensation and environmental remediation obligations. (See Notes 8 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

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. 

Financial Resources

Acceleration of Pre-Petition Debt Obligations

The commencement of the Chapter 11 Cases constituted an event of default or termination event with respect to, and caused an automatic and immediate acceleration of, the Accelerated Direct Financial Obligations. Accordingly, as a result of the commencement of the Chapter 11 Cases, the principal amount of the Accelerated Direct Financial Obligations, together with accrued interest thereon, and in case of certain indebtedness, premium, if any, thereon, immediately became due and payable. However, any efforts to enforce such payment obligations are automatically stayed as of the Petition Date, and are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The material Accelerated Direct Financial Obligations include the Utility’s outstanding senior notes, agreements in respect of certain series of pollution control bonds, and PG&E Corporation’s term loan facility, as well as short-term borrowings under PG&E Corporation’s and the Utility’s revolving credit facilities and the Utility’s term loan facility disclosed in Note 5 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

DIP Credit Agreement

On February 1, 2019, the Utility borrowed $350 million under the DIP Revolving Facility. On April 3, 2019, the Utility borrowed $1.5 billion under the DIP Initial Term Loan Facility and received the proceeds of such borrowing, net of original issue discount and repayment of the $350 million in outstanding borrowings under the DIP Revolving Facility. The DIP Initial Term Loan Facility matures on December 31, 2020 (subject to an extension option described further below) and bears interest at a spread of 225 basis points over LIBOR.

Borrowings under the DIP Facilities are senior secured obligations of the Utility, secured by substantially all of the Utility’s assets and entitled to superpriority administrative expense claim status in the Utility’s Chapter 11 Case. The Utility’s obligations under the DIP Facilities are guaranteed by PG&E Corporation, and such guarantee is a senior secured obligation of PG&E Corporation, secured by substantially all of PG&E Corporation’s assets and entitled to superpriority administrative expense claim status in PG&E Corporation’s Chapter 11 Case. The DIP Facilities will mature on December 31, 2020, subject to the Utility’s option to extend the maturity to December 31, 2021 if certain terms and conditions are satisfied, including the payment of an extension fee. The Utility paid customary fees and expenses in connection with obtaining the DIP Facilities.

As of November 5, 2019, the Utility had outstanding borrowings of $1.5 billion under the DIP Initial Term Loan Facility, no outstanding borrowings under the DIP Delayed Draw Term Loan Facility or the DIP Revolving Facility and $713 million in face amount of letters of credit outstanding under the DIP Revolving Facility. As of November 5, 2019, there were undrawn commitments of $500 million and $2.8 billion on the DIP Delayed Draw Term Loan Facility and the DIP Revolving Facility, respectively. Pursuant to the terms of the DIP Credit Agreement, until such time as the DIP Delayed Draw Term Loan Facility has been drawn in full, or the commitments in respect thereof have terminated or expired, further borrowings under the DIP Revolving Facility are not permitted.

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CPUC Authorization of DIP Credit Agreement

On January 28, 2019, the CPUC granted the Utility exemptions from the requirement of prior CPUC approval for issuance of debt instruments for the incurrence of the DIP financing. The CPUC also indicated its position that the exemptions do not extend to the transfer of ownership of any Utility asset that is pledged as part of the DIP financing and that in the event of the Utility’s default under the DIP financing, the Utility would need to seek the CPUC’s approval to execute such a transfer. Further, the CPUC indicated that the Utility’s “expenditure of the initial DIP financing funds for any purposes may not be recovered from ratepayers without Commission approval in a future application for rate recovery” and that the Utility “bears the burden of demonstrating the reasonableness of any expenditure.”

Debt Commitment Letters

On October 11, 2019, PG&E Corporation and the Utility entered into the Debt Commitment Letters with the Commitment Parties, pursuant to which the Commitment Parties committed to provide $34.35 billion in bridge financing in the form of (a) a $27.35 billion senior secured bridge loan facility (the “OpCo Facility”) with the Utility or any domestic entity formed to hold all of the assets of the Utility upon emergence from bankruptcy as borrower thereunder and (b) a $7.0 billion senior unsecured bridge loan facility (together with the OpCo Facility, the “Facilities”) with PG&E Corporation or any domestic entity formed to hold all of the assets of PG&E Corporation upon emergence from bankruptcy as borrower thereunder, subject to the terms and conditions set forth therein. The commitments under the Debt Commitment Letters will expire on August 29, 2020, unless terminated earlier pursuant to the termination rights set forth in the Debt Commitment Letters. PG&E Corporation and the Utility will pay customary fees and expenses in connection with obtaining the Facilities. If the entire $34.35 billion of bridge commitments remain outstanding as of June 30, 2020, the aggregate commitment fees payable by PG&E Corporation and the Utility would be approximately $210 million.

In lieu of entering into the Facilities, PG&E Corporation and the Utility intend to obtain permanent financing on or prior to emergence from bankruptcy in the form of bank facilities, debt securities or a combination of the foregoing. (See "Plan of Reorganization, RSA, Equity Backstop Commitments and Debt Commitment Letters" in Note 2 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

On October 23, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking approval of the Backstop Commitment Letters, the Debt Commitment Letters and certain related matters. The hearing on PG&E Corporation’s and the Utility’s motion to approve the Backstop Commitment Letters, the Debt Commitment Letters and certain related matters is scheduled for November 19, 2019. PG&E Corporation and the Utility intend to seek an extension of the November 20, 2019 deadline for Bankruptcy Court approval of the Backstop Commitment Letters and the Debt Commitment Letters from the Backstop Parties and the Commitment Parties, respectively.

Equity Financings

There were no issuances under the PG&E Corporation February 2017 equity distribution agreement for the nine months ended September 30, 2019. 

During the nine months ended September 30, 2019, PG&E Corporation issued 8.9 million shares for cash proceeds of $85 million under the PG&E Corporation 401(k) plan. The proceeds from these sales were used for general corporate purposes. Beginning January 1, 2019, PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation.

PG&E Corporation expects to issue new shares of PG&E Corporation common stock for up to $14.0 billion of proceeds at or prior to emergence from Chapter 11 in order to finance the Proposed Plan. The structure, terms and conditions of any such equity issuance are expected to be determined by PG&E Corporation and the Utility at a later time in the Chapter 11 process, subject to the terms and conditions of the Backstop Commitment Letters. There can be no assurance that any such equity offering would be successful. In the event that such equity offerings (together with additional permitted capital sources) do not raise at least $14.0 billion of proceeds in the aggregate or if PG&E Corporation and the Utility do not otherwise consummate such offerings, then PG&E Corporation and the Utility may draw on the Backstop Commitments for equity funding to finance the transactions contemplated by the Proposed Plan, subject to satisfaction or waiver by the Backstop Parties of the conditions set forth therein. (See "Plan of Reorganization, RSA, Equity Backstop Commitments and Debt Commitment Letters" in Note 2 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

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Dividends

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018, due to the uncertainty related to the causes of and potential liabilities associated with the 2017 Northern California wildfires. PG&E Corporation does not expect to pay any cash dividends during the Chapter 11 Cases. (See Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) Also, on April 3, 2019, the court overseeing the Utility’s probation issued an order imposing new conditions of probation, including forgoing issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements” under applicable law and the Utility’s wildfire mitigation plan. (See “U.S. District Court Matters and Probation” in Item 1. Legal Proceedings and Item 7. MD&A.)

Utility Cash Flows

The Utility’s cash flows were as follows:

	Nine Months Ended September 30,
(in millions)	2019		2018
Net cash provided by operating activities	$	4,078	$	4,184
Net cash used in investing activities	(4,250)		(4,617)
Net cash provided by financing activities	1,416		357
Net change in cash, cash equivalents and restricted cash	$	1,244	$	(76)

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.  During the nine months ended September 30, 2019, net cash provided by operating activities decreased by $106 million compared to the same period in 2018.  This decrease was primarily due to an increase in amounts paid for reorganization items, and enhanced and accelerated inspections and repairs of transmission and distribution assets in 2019, with no similar payments in 2018, partially offset by amounts not paid due to the automatic stay as of the Petition Date.

The Utility will continue to operate its business as a debtor in possession under the jurisdiction of the Bankruptcy Court and in accordance with applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. Future cash flow from operating activities will be affected by various ongoing activities, including:

•the timing and amounts of costs, including fines and penalties, that may be incurred in connection with current and future enforcement, litigation, and regulatory matters (see “Enforcement and Litigation Matters” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and Part II, Item 1. Legal Proceedings for more information);

•the timing and amount of premium payments related to wildfire insurance (see “Wildfire Insurance” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 for more information);

•the Tax Act, which may accelerate the timing of federal tax payments and reduce revenue requirements, resulting in lower operating cash flows depending on the timing of wildfire payments;

•the timing and outcomes of the 2020 GRC, FERC TO18, TO19 and TO20 rate cases, 2020 Cost of Capital, NDCTP, and other ratemaking and regulatory proceedings; and

•the timing and amount of substantially increasing costs in connection with the 2019 Wildfire Mitigation Plan that are not currently being recovered in rates (see “Regulatory Matters” below for more information).

The Utility had material obligations outstanding as of the Petition Date, including claims related to the 2018 Camp fire and 2017 Northern California wildfires. Any efforts to enforce such payment obligations are automatically stayed as of the Petition Date, and are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Future cash flows will be materially impacted by the timing and outcome of the Chapter 11 Cases.

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Investing Activities

Net cash used in investing activities decreased by $367 million during the nine months ended September 30, 2019 as compared to the same period in 2018. The Utility’s investing activities primarily consist of the 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.

The Utility’s capital expenditures were approximately $6.5 billion in 2018. 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 $7.2 billion in capital expenditures in 2019, and between $5.7 billion and $7 billion annually from 2020 through 2023.

Financing Activities

Net cash provided by financing activities increased by $1.1 billion during the nine months ended September 30, 2019 as compared to the same period in 2018.  This increase was due to $1.5 billion of net borrowings under the DIP Initial Term Loan Facility in 2019, offset by $400 million of long-term debt that matured in 2018 with no corresponding activity in 2019.

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. 

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 Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.  The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. In addition, PG&E Corporation and the Utility are involved in other enforcement and litigation matters described in the 2018 Form 10-K and “Part II. Other Information, Item 1. Legal Proceedings.”

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC and other federal and state regulatory agencies.  The resolutions of the proceedings described below and other proceedings may affect PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. Discussed below are significant regulatory developments that have occurred since filing the 2018 Form 10-K.

Application for a Waiver of the Capital Structure Condition

The CPUC’s capital structure decisions require the Utility to maintain a 52% equity ratio on average over the period that the authorized capital structure is in place, and to file an application for a waiver to the capital structure condition if an adverse financial event reduces its equity ratio by 1% or more.  The CPUC’s decisions state that the Utility shall not be considered in violation of these conditions during the period the waiver application is pending resolution.  Due to the net charges recorded in connection with the 2018 Camp fire and the 2017 Northern California wildfires as of December 31, 2018, the Utility submitted to the CPUC an application for a waiver of the capital structure condition on February 28, 2019.  The waiver is subject to CPUC approval. On April 30, 2019, the CPUC held a prehearing conference, and on May 29, 2019, the CPUC issued a scoping memo and ruling on issues for briefing. On August 27, 2019, the Utility filed a motion to update the record to reflect additional charges recorded as of June 30, 2019 for the 2017 Northern California wildfires and the 2018 Camp fire, of $3.9 billion, as the result of which, the Utility’s equity ratio declined to approximately 34% at June 30, 2019. The Utility filed its opening briefs with the CPUC on August 30, 2019. The Utility is unable to predict the timing and outcome of its waiver application.

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2020 Cost of Capital Proceeding

On April 22, 2019, the Utility filed an application with the CPUC, requesting that the CPUC authorize the Utility's capital structure and rates of return for its electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base beginning on January 1, 2020.  In its application, the Utility requested that the CPUC approve the Utility’s proposed capital structure (i.e., the relative weightings of common equity, preferred equity, and debt), as well as the proposed return on equity, proposed cost of preferred stock, and proposed cost of debt. The Utility requested a 16% rate of return on equity for 2020, which reflected, among other things, the wildfire-related challenges that the Utility was facing.  The Utility also proposed to amend its cost of capital application with an updated cost of capital if the CPUC or the California legislature implemented actions to materially reduce the challenges that investor-owned utilities face in California in connection with the extreme wildfire risk.

AB 1054, enacted on July 12, 2019, provides for the establishment of the Wildfire Fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. On July 23, 2019, the Utility notified the CPUC of its election to participate in the Wildfire Fund. The Utility’s participation in the Wildfire Fund is subject to the conditions and limitations set forth in AB 1054 and approval by the Bankruptcy Court.

As a result of the expected effects of AB 1054 on the Utility’s wildfire-related risk profile, on August 1, 2019, in a supplemental cost of capital testimony, the Utility proposed to revise its rate of return on equity to 12%.

The following table compares the cost of capital currently authorized in the Utility’s 2019 GT&S rate case and the 2017 GRC, with those requested in the Utility’s 2020 cost of capital application, as updated by the Utility’s August 1, 2019 testimony to reflect a revised rate of return on equity:

	2019 Currently Authorized						2020 Requested (as revised)
	Cost		Capital Structure		Weighted Cost		Cost		Capital Structure		Weighted Cost
Return on common equity	10.25	%	52.00	%	5.33	%	12.00	%	52.00	%	6.24	%
Preferred stock	5.60	%	1.00	%	0.06	%	5.52	%	0.50	%	0.03	%
Long-term debt	4.89	%	47.00	%	2.30	%	5.16	%	47.50	%	2.45	%
Weighted average cost of capital					7.69	%					8.72	%

The proposed cost of capital and capital structure will be essential for the Utility to attract new investment capital to upgrade, maintain, and modernize its critical energy infrastructure. The Utility indicated in its application that, over the next four years (2019-2022), the Utility expects to fund up to $28 billion in energy infrastructure investments, including $21 billion in electric and gas safety, reliability and system hardening, $4 billion in new gas pipelines and electric powerlines, $1 billion in power generation, and $2 billion in information technology, equipment and facilities.

The Utility indicated in its supplemental cost of capital testimony that AB 1054 does not directly impact the Utility’s test year 2020 cost of debt. However, the cost of debt will be impacted by the Utility’s exit financing as part of its future Chapter 11 plan of reorganization. The supplemental cost of capital testimony did not address the Utility’s currently-effective formula rate for electric transmission rates, including the requested return on equity, which is pending at the FERC. The parties in the FERC proceeding are currently involved in settlement negotiations.

The CPUC is considering whether the Utility must file a new cost of capital application with the CPUC on or about the time it emerges from the Chapter 11 Cases.  The Utility requested in its cost of capital application that the annual cost of capital adjustment mechanism be continued, although its normal operation could be superseded by a new cost of capital application. (The annual cost of capital adjustment mechanism is a tool to modify the cost of long-term debt and cost of equity authorized by the CPUC based on changes in interest rates.) The Utility is unable to predict the timing and outcome of this proceeding.

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Revenue Requirements

For 2020, the Utility expects that the proposed cost of capital, if adopted, would result in revenue requirement increases of approximately $271 million for electric generation and distribution and $74 million for gas distribution operations, assuming 2017 authorized rate base amounts.  The revenues for the gas transmission and storage operations would increase by approximately $71 million, assuming 2020 authorized rate base amounts.  However, if the CPUC subsequently approves different electric and gas rate base amounts for the Utility in its 2020 GRC, which is currently pending before the CPUC, the revenue requirement changes resulting from the Utility’s requested 2020 ROE may differ from the amounts reflected in this cost of capital application.

The following table compares the revenue requirement amounts currently authorized in the Utility’s 2019 GT&S rate case and the 2017 GRC, with those requested in the Utility’s 2020 cost of capital application, as updated to reflect a revised rate of return on equity submitted to the CPUC on August 1, 2019:

Revenue Requirement (in millions)	Authorized in 2017 GRC and 2019 GT&S		Requested in 2020 Cost of Capital Application (as revised)
Electric generation and distribution	$	6,266	$	6,537
Gas distribution	1,739		1,813
Gas transmission and storage	1,431		1,502

As disclosed in “Application for a Waiver of the Capital Structure Condition” above, due to the net charges recorded in connection with the 2018 Camp fire and the 2017 Northern California wildfires as of December 31, 2018, on February 28, 2019, the Utility submitted to the CPUC an application for a waiver of the capital structure condition.  The 2020 cost of capital application does not modify that request.

On July 2, 2019, the assigned commissioner issued a scoping memo and ruling that, among other things, consolidated the Utility’s cost of capital proceeding with the 2020 cost of capital applications submitted to the CPUC by Southern California Edison Company, San Diego Gas & Electric Company, and Southern California Gas Company.  The scoping memo also identified the issues to be addressed within the proceeding and its schedule. On July 15, 2019, the assigned ALJ also issued a ruling directing the Utility and the other Applicants to submit supplemental testimony regarding AB 1054’s impact on financial risks and other issues within the scope of this proceeding by August 1, 2019. Rebuttal testimony was filed August 16, 2019, and additional rebuttal on testimony regarding the passage of AB 1054 was filed on August 21, 2019. A proposed decision is expected to be issued on November 27, 2019. The earliest a final decision would appear on the CPUC’s business meeting agenda is December 19, 2019.  The Utility is unable to predict the timing and outcome of this proceeding.

2017 General Rate Case

On May 11, 2017, the CPUC issued a final decision in the Utility’s 2017 GRC, which determined the annual amount of base revenues (or “revenue requirements”) that the Utility 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 final decision approved, with certain modifications, the settlement agreement that the Utility, PAO, TURN, and 12 other intervening parties jointly submitted to the CPUC on August 3, 2016. Consistent with the amounts proposed in the settlement agreement, the final decision approved a revenue requirement increase of $88 million for 2017, with additional increases of $444 million in 2018 and $361 million in 2019.

On September 24, 2018, the CPUC approved the Utility’s advice letter proposal to make a one-time reduction to revenues by approximately $21 million. This advice letter was directed by an ALJ ruling in response to the Utility’s $300 million expense reduction announcement in January 2017.

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Also, as a result of the Tax Act, on March 30, 2018, the Utility submitted to the CPUC a PFM of the CPUC’s final decision in the 2017 GRC proposing to reduce revenue requirements by $267 million and $296 million for 2018 and 2019, respectively, and increase rate base by $199 million and $425 million for 2018 and 2019, respectively. On August 15, 2019, a final decision on the PFM was issued directing the Utility to consult with the CPUC’s Energy Division to ensure that its calculations include the cost of removal component of book depreciation when calculating the amortization of protected excess deferred income taxes using the ARAM and to quantify the amount of unprotected excess deferred taxes, which can be returned to ratepayers without following the ARAM. In compliance with the decision, on September 13, 2019, the Utility filed an advice letter with the revised calculations and the length of time the revenue requirement reductions would be amortized in rates. On October 17, 2019, the CPUC approved the Utility’s advice letter approving a revised computation of the effects of the Tax Act on the revenue requirements, resulting in a $282 million reduction to the 2018 revenue requirement and a $291 million reduction to the 2019 revenue requirement. The Utility will incorporate these revenue requirement reductions into rates beginning on January 1, 2020 and later in 2020 along with other anticipated changes, such as the 2020 GRC Phase 1. The IRS is expected to provide additional guidance on ARAM. This IRS guidance may impact the Utility’s calculation of the related revenue requirement. It is uncertain when the IRS guidance may be issued.

The Utility provided an update of the cost effectiveness study for the SmartMeter^TM Upgrade project to the CPUC on July 10, 2017. On October 24, 2019, the CPUC adopted a final decision that finds (i) the July 10, 2017 study is a thorough and complete update of the cost-effectiveness of the project and (ii) the Utility should submit an updated version of the cost effectiveness study as a stand-alone exhibit in each GRC Phase I application that the Utility files in the future.

For more information on the 2017 GRC, see the 2018 Form 10-K.

2020 General Rate Case

On December 13, 2018, the Utility filed its 2020 GRC application with the CPUC. In the 2020 GRC, the Utility requested that the CPUC determine the annual amount of revenue requirements that the Utility will be authorized to collect from customers from 2020 through 2022 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 request also reflects an updated capital forecast for 2018 and 2019. The 2020 GRC application also includes recorded costs for 2017 and updated forecasts for the proposed mitigations for the period 2018 through 2022 for the Utility’s top safety-related risks as presented in the Utility’s November 2017 Risk Assessment Mitigation Phase report.

For 2020, the Utility requested base revenues of $9.6 billion, an increase of $1.1 billion, or 12.4%, as compared to authorized base revenues for 2019. The requested weighted average rate base for 2020 is approximately $30 billion, which corresponds to an increase of $2.7 billion over the 2019 authorized rate base of $27.3 billion. The Utility also requested that the CPUC establish a ratemaking mechanism that would increase the Utility’s authorized revenues in 2021 and 2022 by $454 million and $486 million, respectively. Over the 2020-2022 GRC period, the Utility plans to make average annual capital investments of approximately $4.5 billion in electric distribution, natural gas distribution, and electric generation infrastructure, and to improve safety, reliability, and customer service.

Line of Business: (in millions)	Amounts Requested in the GRC Application		Amounts Currently Authorized for 2019 (1)		Increase to 2019 Authorized Amounts
Electric distribution	$	5,113	$	4,364	$	749
Gas distribution	2,097		1,963		134
Electric generation	2,366		2,191		175
Total revenue requirements	$	9,576	$	8,518	$	1,058

⁽¹⁾ These amounts include revenues from the Utility’s 2017 GRC decision adjusted for attrition year increases, cost of capital, and reductions due to the Tax Act.

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Cost Category: (in millions)	Amounts Requested in the GRC Application		Amounts Currently Authorized for 2019 (1)		Increase (Decrease) to 2019 Authorized Amounts (2)
Operations and maintenance	$	2,156	$	1,946	$	210
Customer services	319		338		(19)
Administrative and general	1,315		953		361
Less: Revenue credits	(196)		(152)		(44)
Franchise fees, taxes other than income, and other adjustments	236		181		55
Depreciation, return, and income taxes	5,747		5,252		495
Total revenue requirements (2)	$	9,576	$	8,518	$	1,058

⁽¹⁾ These amounts include revenues from the Utility’s 2017 GRC decision adjusted for attrition year increases, cost of capital, and reductions due to the Tax Act.

⁽²⁾ These amounts may appear not to tie due to small rounding differences.

Revenue requirement drivers	Increase to 2019 Authorized Amounts
Community Wildfire Safety Program	6.8	%
Liability insurance (1)	3.2	%
Core gas and electric operations	2.4	%
Total proposed revenue requirement increase	12.4	%

⁽¹⁾ The Utility’s GRC forecast indicates that future liability insurance premium costs will be approximately $355 million in 2020.

Among other things, the Utility proposed to invest a total of approximately $5 billion (including approximately $3 billion for capital expenditures) between 2018 and 2022 on CWSP measures. Through this program, the Utility proposes to bolster wildfire prevention, risk monitoring, and emergency response efforts, add new and enhanced safety measures, increase vegetation management, and harden its electric system to help further reduce wildfire risks.

In addition, the Utility requested authorization to establish several new balancing accounts, including:

•a two-way electric and gas Risk Transfer Balancing Account to record the difference between the amounts adopted for liability insurance premiums and the Utility’s actual costs; this two-way account would allow the Utility to pass-through actual insurance costs for up to $2 billion in coverage and return to customers any overcollection if forecast costs exceed actuals costs; and

•a two-way Wildfire Mitigation Balancing Account to recover expenses and capital expenditures associated with the Utility’s wildfire mitigation activities of up to 115% of the Utility’s expense and capital expenditures forecasts; this would include the costs associated with overhead system hardening, enhanced vegetation management, and other costs of wildfire mitigation activities. For expense and capital expenditures that exceed the 115% threshold, the proposed balancing account would allow the Utility to track those incremental costs and seek recovery. Costs incurred that exceed the 115% threshold would be subject to reasonableness review in a future GRC or separate application.

This GRC proposal did not request funding for potential lawsuits or claims resulting from the 2018 Camp fire and 2017 Northern California wildfires. Also, the Utility is not seeking recovery of compensation of PG&E Corporation’s and the Utility’s officers. In addition, the Chapter 11 Cases may require a change to the scope of work that the Utility proposes to accomplish in the 2020 GRC period.

In its application, the Utility requested that the CPUC issue a final decision by March 2020 and that the 2020 GRC revenue requirement be effective January 1, 2020. On March 8, 2019, the CPUC issued a ruling addressing the schedule and scope of the 2020 GRC. The ruling indicates a proposed decision will be issued in the first quarter of 2020.

On March 25, 2019, the Utility submitted an update to the 2020 forecasted capital request for its corporate real estate to $170 million, which is a 55% decrease from its original capital request of approximately $380 million. The cost reductions were due to changes in the Utility's real estate strategy.

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On June 28, 2019, PAO submitted testimony recommending that the CPUC authorize a 2020 GRC revenue requirement of $503 million, or 5.9%, higher than the 2019 authorized level. PAO also recommended establishing a one-way balancing account for the Utility’s total GRC revenue requirement during the rate case term (2020 to 2022). On July 26, 2019, all other parties to the proceeding submitted testimony; none submitted an alternative revenue requirement recommendation.

On September 4, 2019, the Utility submitted its rebuttal testimony. In rebuttal testimony the Utility included updates to its CWSP and insurance proposals as follows:

•The Utility extended the timeline for its CWSP system hardening proposal from a 10-year program to a 14-year program and proposed to revise the number of overhead system hardening from 600 miles per year in 2020, 2021, and 2022 to 188 miles in 2020, 204 miles in 2021 and 376 miles in 2022.

•The Utility also updated its CWSP forecast to include undergrounding, which the Utility will consider on a project by project basis as part of its system hardening proposal.

•These revisions to the CWSP workplan result in an updated CWSP forecast of $4.2 billion from $4.1 billion for the period 2020 through 2022.

•The Utility revised its general liability insurance proposal to reduce the amount of general liability insurance coverage it may seek in a given year from $2 billion to $1.4 billion subject to the CPUC approving a self-insurance mechanism whereby the Utility would use any unspent revenues approved for liability insurance premiums to self-insure.

Evidentiary hearings occurred between September 23, 2019 and October 18, 2019. On November 1, 2019, the Utility submitted an update to its revenue requirement request to the CPUC. The revenue requirement update included errata, forecast updates disclosed throughout the proceeding, forecast concessions included in the Utility’s rebuttal testimony, and stipulations with various parties to the proceeding. The update reduced the Utility’s requested revenue requirement increases from $1.058 billion to $1.002 billion for test year 2020, from $454 million to $356 million for 2021, and from $486 million to $481 million for 2022. One additional day of evidentiary hearings was held on November 6, 2019. Opening briefs are due on November 22, 2019 and reply briefs are due on December 13, 2019.

On November 1, 2019, in accordance with AB 1054 and a ruling set forth by the assigned ALJs, the Utility submitted its proposal for removing from its revenue requirement request the forecasted equity return on its wildfire mitigations capital additions forecasts. The Utility estimated the reduction as $22 million in 2020, $57 million in 2021 and $105 million in 2022. These amounts will be adjusted to reflect the amounts approved by the CPUC in the final decision, including amounts adopted for 2021 and 2022.

The Utility cannot predict the timing and outcome of this matter.

For more information on the 2020 GRC, see the 2018 Form 10-K.

2015 Gas Transmission and Storage Rate Case

In its final decisions in the Utility’s 2015 GT&S rate case, the CPUC excluded from rate base $696 million of capital spending in 2011 through 2014. This was the amount recorded in excess of the amount adopted in the 2011 GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. The Utility would be required to take a charge in the future if the CPUC’s audit of 2011 through 2014 capital spending resulted in additional permanent disallowance. The audit is still in process. The Utility cannot predict the timing and outcome of the audit.

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As a result of the Tax Act, on March 30, 2018, the Utility submitted to the CPUC a PFM of the CPUC’s final decision in the 2015 GT&S rate case proposing to reduce revenue requirements by $58 million and increase rate base by $12 million for 2018 (excluding the impacts of an approximately $7 million increase in revenue requirement and a $60 million increase in rate base associated with the Utility’s private letter ruling advice letter approved by the CPUC on July 18, 2018). On August 15, 2019, a final decision on the PFM was issued directing the Utility to consult with the CPUC’s Energy Division to ensure that its calculations include the cost of removal component of book depreciation when calculating the amortization of protected excess deferred income taxes using the ARAM and to quantify the amount of unprotected excess deferred taxes, which can be returned to ratepayers without following the ARAM. In compliance with the decision, on September 13, 2019, the Utility filed an advice letter with the revised calculations and the length of time the revenue requirement reductions would be amortized in rates. On October 17, 2019, the CPUC approved the Utility’s advice letter approving a revised computation of the effects of the Tax Act on the revenue requirements, resulting in a $61 million reduction to the 2018 revenue requirement. The Utility will incorporate the revenue requirement reduction into rates beginning January 1, 2020. The IRS is expected to provide additional guidance on ARAM. This IRS guidance may impact the Utility's calculation of the related revenue requirement. It is uncertain when the IRS guidance may be issued.

For more information on the 2015 GT&S rate case, see the 2018 Form 10-K.

2019 Gas Transmission and Storage Rate Case

On September 12, 2019, the CPUC voted the final decision in the 2019 GT&S rate case of the Utility. By approving the decision, the CPUC adopted a 2019 revenue requirement of $1.332 billion compared to the Utility’s (revised) request of $1.485 billion. This corresponds to an increase of $31 million over the Utility’s 2018 authorized revenue requirement of $1.301 billion, compared to the $184 million increase requested by the Utility. The CPUC also adopted revenue requirements of $1.432 billion for 2020, $1.516 billion for 2021, and $1.580 billion for 2022, compared to the Utility’s request of $1.595 billion for 2020, $1.693 billion for 2021, and $1.679 billion for 2022.

The revenue requirement amounts requested by the Utility and the revenue requirement amounts in the decision are set forth in the following table:

Revenue Requirement (in millions)	2018 Currently Authorized		2019		2020		2021		2022
Utility’s Request	$	1,301	$	1,485	$	1,595	$	1,693	$	1,679
Decision	$	1,301	$	1,332	$	1,432	$	1,516	$	1,580

The decision removed from rate base approximately $304 million on a forecasted basis of pipeline replacement capital expenditures for the 2015-2018 period due to cost overruns; the Utility expects the final disallowance on a recorded cost basis to be approximately $237 million. Incorporating the forecast reduction, the decision adopted a rate base for 2019 of $4.46 billion, which corresponds to an increase of $0.75 billion over the 2018 adopted rate base of $3.71 billion. This is compared to the Utility’s rate base request of $4.75 billion for 2019. The decision adopted a rate base of $4.98 billion for 2020, $5.37 billion for 2021, and $5.71 billion for 2022.

The rate base amounts also exclude approximately $576 million of capital spending subject to audit by the CPUC (related to 2011 through 2014 expenditures in excess of amounts adopted in the 2011 GT&S rate case), pursuant to the 2015 GT&S rate case decision. The Utility is unable to predict whether the $576 million, or a portion thereof, will ultimately be approved by the CPUC and included in the Utility’s future rate base.

The decision adopted capital expenditures of $726 million for 2019, which corresponds to a decrease of $104 million over the Utility’s request of $830 million. The decision adopted a post-test year ratemaking joint stipulation proposed by the Utility and PAO. The joint stipulation results in adopted capital expenditures of $697 million in 2020, $597 million in 2021, and $570 million in 2022.

The decision adopted the Utility’s proposed Natural Gas Storage Strategy, with minor modifications related to the decommissioning or sale of the Utility’s Los Medanos and Pleasant Creek storage fields, and the decision adopted a two-way balancing account for storage costs, which will be subject to a reasonableness review in the next GT&S rate case. The decision retained a number of existing memorandum accounts and one-way balancing accounts, including a one-way expense balancing account for transmission integrity management, and adopted 19 new expense and capital one-way balancing and memorandum accounts.

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The decision also resolved the second phase of this proceeding, addressing the removal of officer compensation costs from the revenue requirement, which is required by California Senate Bill 901. On this matter, the decision adopted the joint stipulation offered by the Utility, PAO and TURN that reduces the Utility’s requested 2019 GT&S operating expenses by $1.428 million and capital expenditures by $0.455 million.

On October 23, 2019, the Utility filed an application for rehearing with the CPUC requesting the rehearing of the final decision. Specifically, issues identified by the Utility include the adopted disallowance associated with vintage pipe replacement, reduction in the Utility’s expense forecast for in-line inspections, and establishment of a memo account for Internal Corrosion Direct Assessment. The Utility cannot predict the timing and outcome of this matter.

For more information on the 2019 GT&S rate case, see the 2018 Form 10-K.

Transmission Owner Rate Cases

Transmission Owner Rate Cases for 2015 and 2016 (the “TO16” and “TO17” rate cases, respectively)

On January 8, 2018, the Ninth Circuit Court of Appeals issued an opinion granting an appeal of FERC’s decisions in the TO16 and TO17 rate cases that had granted the Utility a 50 basis point ROE incentive adder for its continued participation in the CAISO. Those rate case decisions were remanded to FERC for further proceedings consistent with the Court of Appeals’ opinion. If FERC concluded on remand that the Utility should no longer be authorized to receive the 50 basis point ROE incentive adder, the Utility would incur a refund obligation of $1 million and $8.5 million for TO16 and TO17, respectively. Alternatively, if FERC again concluded that the Utility should receive the 50 basis point ROE incentive adder and provides the additional explanation that the Ninth Circuit found the FERC’s prior decisions lacked, then the Utility would not owe any refunds for this issue for TO16 or TO17.

On February 28, 2018, the Utility filed a motion to establish procedures on remand requesting a hearing and additional briefing on the issues identified in the Ninth Circuit Court’s opinion. On August 20, 2018, FERC issued an order granting the Utility’s motion to allow for additional briefing. The order also consolidated the TO18 rate case with TO16 and TO17 for this issue. The Utility filed briefs on September 19, 2018 and reply briefs on October 10, 2018. On July 18, 2019, FERC issued its order on remand reaffirming its prior grant of the Utility’s request for the 50 basis point ROE adder. On August 16, 2019, a number of parties filed for rehearing of that order on remand. In the absence of FERC action within 30 days from the date the rehearing request was filed, the request for rehearing would be deemed denied by operation of law. As a result, on September 16, 2019, FERC extended the amount of time to consider the request for rehearing by issuing a tolling order for the limited purpose of further consideration of the matters raised in the request.

Transmission Owner Rate Case for 2017 (the “TO18” rate case)

On July 29, 2016, the Utility filed its TO18 rate case at the FERC requesting a 2017 retail electric transmission revenue requirement of $1.72 billion, a $387 million increase over the 2016 revenue requirement of $1.33 billion.  The forecasted network transmission rate base for 2017 was $6.7 billion.  The Utility sought a return on equity of 10.9%, which included an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO.  In the filing, the Utility forecasted that it would make investments of $1.30 billion in 2017 in various capital projects.

On September 30, 2016, the FERC issued an order accepting the Utility’s July 2016 filing and setting it for hearing, but held the hearing procedures in abeyance for settlement procedures.  The order set an effective date for rates of March 1, 2017 and made the rates subject to refund following resolution of the case.  On March 17, 2017, the FERC issued an order terminating the settlement procedures due to an impasse in the settlement negotiations reported by the parties.  During the hearings held in January 2018, the Utility, intervenors, and the FERC trial staff, addressed questions relating to return on equity, capital structure, depreciation rates, capital additions, rate base, operating and maintenance expense, administrative and general expense, and the allocation of common, general and intangible costs.

Additionally, on March 31, 2017, intervenors in the TO18 rate case filed a complaint at the FERC alleging that the Utility failed to justify its proposed rate increase in the TO18 rate case. On November 16, 2017, the FERC dismissed the complaint. On December 18, 2017, the complainants filed a request for a rehearing of that order, which the FERC denied on May 17, 2018.

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On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case proposing a ROE of 9.13% compared to the Utility’s request of 10.90%, and an estimated composite depreciation rate of 2.96% compared to the Utility’s request of 3.25%. The ALJ also rejected the Utility’s method of allocating common plant between CPUC and FERC jurisdiction. In addition, the ALJ proposed to reduce forecasted capital and expense spending to actual costs incurred for the rate case period. Further, the ALJ proposed to remove certain items from the Utility’s rate base and revenue requirement. The Utility and intervenors filed initial briefs on October 31, 2018, and reply briefs on November 20, 2018, in response to the ALJ’s initial decision. The Utility expects FERC to issue a decision in late-2019, but expects one or more parties to seek rehearing of that decision and then appeal it to the courts. The Utility is unable to predict the timing of when a final decision will be issued.

Transmission Owner Rate Case for 2018 (the “TO19” rate case)

On July 27, 2017, the Utility filed its TO19 rate case at the FERC requesting a 2018 retail electric transmission revenue requirement of $1.79 billion, a $74 million increase over the proposed 2017 revenue requirement of $1.72 billion. The forecasted network transmission rate base for 2018 was $6.9 billion.  The Utility sought 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 be held in abeyance pending settlement discussion among the parties. On May 14, 2018, the Utility filed a proposal to reflect the impact of the Tax Act on its TO tariff rates effective March 1, 2018, in the resolution of the TO19 rate case. The tax impact reduces the TO19 requested revenue requirement from $1.79 billion to $1.66 billion.

On September 29, 2017, intervenors in the TO19 rate case filed a complaint at the FERC alleging that the Utility failed to justify its proposed rate increase in the TO19 rate case. On October 17, 2017, the Utility requested that the FERC dismiss the complaint. On May 17, 2018, the FERC issued an order setting the complaint for hearing, initiating settlement judge procedures, and consolidating with the TO19 proceeding.

On September 21, 2018, the Utility filed an all-party settlement with FERC in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon the issuance of a final, non-appealable TO18 decision. Additionally, if FERC were to determine that the Utility was not entitled to the 50 basis point incentive adder for the Utility’s continued CAISO participation, then the Utility would be obligated to make a refund to customers of approximately $25 million. On December 20, 2018, FERC issued an order approving the all-party settlement. Additionally, on July 18, 2019, FERC issued an order on remand reaffirming its grant of the Utility’s request for the 50 basis point incentive adder for continued CAISO participation. On September 30, 2019, FERC issued an order on rehearing that denied a pending request for rehearing of the FERC’s decision granting the 50 basis point ROE adder in the TO19 proceeding.

Transmission Owner Rate Case for 2019 (the “TO20” rate case)

On October 1, 2018, the Utility filed its TO20 rate case at FERC requesting approval of a formula rate for the costs associated with the Utility’s electric transmission facilities. On November 30, 2018, the FERC issued an order accepting the Utility’s October 2018 filing, subject to hearings and refund, and established May 1, 2019 as the effective date for rate changes. FERC also ordered that the hearings will be held in abeyance pending settlement discussions among the parties. The Utility is unable to predict the timing and outcome of settlement discussions.

The formula rate replaces the “stated rate” methodology that the Utility used in its previous TO rate case filings. The formula rate methodology still includes an authorized revenue requirement and rate base for a given year, but it also provides for an annual update of the following year’s revenue requirement and rates in accordance with the terms of the FERC-approved formula. Under the formula rate mechanism, transmission revenue requirements will be updated to the actual cost of service annually as part of the true-up process. Differences between amounts collected and determined under the formula rate will be either collected from or refunded to customers.

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In the filing, the Utility forecasts a 2019 retail electric transmission revenue requirement of $1.96 billion. The proposed amount reflects an approximately 9.5% increase over the as-filed TO19 requested revenue requirement of $1.79 billion (a subsequent reduction to $1.66 billion was identified as a result of the Tax Act). The Utility forecasts that it will make investments of approximately $1.1 billion and $0.7 billion for 2018 and 2019, respectively, for various capital projects to be placed in service before the end of 2019. Including projects to be placed in service beyond 2019, the Utility forecasts total electric transmission capital expenditures of $1.4 billion in 2018 and $1.4 billion in 2019. The Utility’s forecasted rate base for 2019 is approximately $8 billion on a weighted average basis, compared to the Utility’s forecasted rate base of $6.9 billion in 2018. The Utility has requested that FERC approve a 12.5% return on equity (which includes an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO), an increase from the 10.75% (also inclusive of a 50 basis point CAISO incentive adder) requested in its TO19 rate case. The parties conducted settlement conferences on March 14-15, 2019, June 13-14, 2019, August 13-14, 2019, and October 28-29, 2019.

On May 9, 2019, the Utility filed an application with the FERC requesting revisions to its TO20 rate case formula rate model to remove the impact of the non-cash wildfire-related charges on the ratio of common equity to total capital. The Utility indicates in its application that, because of the recording of the non-cash wildfire-related charges in connection with the 2017 Northern California wildfires and the 2018 Camp fire, the Utility’s financial statements reflected a ratio of common equity to total capital of approximately 41% as of December 31, 2018. The Utility indicates that the proposed revisions adjust the equity ratio to accurately reflect how the Utility financed the capital projects that are included in rate base. The Utility’s current rate base was financed with an equity ratio of approximately 52%, rather than the 41% equity ratio. In addition, on May 9, 2019, the Utility submitted a request to the FERC to exclude the wildfire charge from the Utility’s capital structure for the purpose of calculating its allowance for funds used during construction effective January 1, 2019.

On July 10, 2019, the FERC accepted the Utility’s revisions to the formula rate to become effective December 9, 2019, subject to refund, established hearing and settlement judge procedures, and reflected it with the Utility's TO20 case.

The Utility expects to file an annual update to its TO tariff on or before December 1 of each year beginning in December 2019, for rates and charges to become effective January 1 of the following year, consistent with the formula rate.

For more information on the TO rate cases, see the 2018 Form 10-K.

Nuclear Decommissioning Cost Triennial Proceeding

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 a result of changes in assumptions such as 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.

On December 13, 2018, the Utility submitted its 2018 NDCTP application, which includes a Diablo Canyon site-specific decommissioning cost estimate of $4.8 billion to decommission the Diablo Canyon facilities.

On February 14, 2019, the CPUC issued a scoping memo addressing the scope of the Utility’s 2018 NDCTP application to include the reasonableness of the Diablo Canyon decommissioning cost estimate, ratemaking proposals, proposed Diablo Canyon milestone framework, plans to address host community needs, reasonableness of Humboldt Bay Power Plant decommissioning costs, and reasonableness of performing Diablo Canyon planning activities pre-shutdown, including the proposed rate of recovery of these pre-planning activities addressed in the Utility’s application for authorization to establish the Diablo Canyon decommissioning planning memorandum account (the “Diablo Canyon DPM account application”).

On March 7, 2019, the CPUC amended the scoping memo to combine the Diablo Canyon DPM account application, which seeks authorization for the Utility to establish the Diablo Canyon Decommissioning Memorandum Account to track funding for Diablo Canyon pre-shutdown decommissioning planning activities, with the 2018 NDCTP. The CPUC approved the Utility to establish an interim mechanism to track decommissioning planning activity expenses in the Diablo Canyon Decommissioning Memorandum Account. Any Memorandum Account recovery of such expenses is subject to the authorization and approval of the CPUC, which will be discussed in this year’s NDCTP. The assigned ALJ deferred the decision of cost recovery until after the NRC addresses the Utility’s December 13, 2018 exemption request, in which the Utility requested an exemption to allow the Utility to withdraw from the NDT to fund decommissioning planning activities. The CPUC held public participation hearings on August 7 and 8, 2019 for residents and organizations in and near San Luis Obispo in connection with the Utility’s request.

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On September 10, 2019, the NRC issued a letter granting the Utility’s request for an exemption and authorizing the Utility to access the NDT for up to $187.8 million on decommissioning planning activities. On October 4, 2019, the Utility submitted supplemental testimony to the NRC addressing how it proposes to modify its request in light of the NRC exemption and the Utility’s proposed disposition of and ratemaking treatment of the planned Baywood Feed, a 12-kilovolt transmission line.

Opening briefs are due November 21, 2019 and reply briefs are due on December 13, 2019.

The Utility seeks to collect $383.7 million and $3.9 million for the funding of the Diablo Canyon tax qualified trust and Humboldt Bay tax qualified trust, respectively, commencing January 1, 2020. Additionally, the Utility seeks cost recovery of pre-planning activities commencing January 1, 2020, of $30 million for the three-year period 2020 to 2022, and a $44 million revenue requirements for the two-year period 2023 to 2024; by an annual expense only balancing account. The Utility is also defending the reasonableness and prudence of the $398.4 million spent for Humboldt Bay Power Plant decommissioning project costs completed to date.

Petition for Modification of CPUC Decision Approving Retirement of Diablo Canyon Power Plant

On June 20, 2016, the Utility entered into a joint proposal with certain parties, including the Alliance for Nuclear Responsibility, to retire Diablo Canyon’s two nuclear power reactor units at the expiration of their current operating licenses in 2024 and 2025. On January 11, 2018, the CPUC approved the planned retirement by 2024 and 2025, but required legislative authorization for certain key aspects of the joint proposal. On November 29, 2018, in response to SB 1090, the CPUC issued a further decision addressing the key remaining goals of the Diablo Canyon joint proposal agreement.

On October 1, 2019, the Alliance for Nuclear Responsibility filed a PFM of the CPUC’s January 11, 2018 decision approving the planned retirement of Diablo Canyon. The PFM argues that above-market costs attributable to Diablo Canyon under the Power Charge Indifference Adjustment methodology, when combined with decreasing bundled load by PG&E, create material changed circumstances that undermine the reasonableness of incurring costs to operate Diablo Canyon until its retirement. On October 31, 2019, the Utility filed a joint response with Friends of the Earth, Natural Resources Defense Council, Coalition of California Utility Employees, and IBEW Local 1245, which argued that modification of the CPUC's initial decision is not warranted and is not in the public interest.

For more information on the planned retirement of Diablo Canyon, see the 2018 Form 10-K.

Wildfire Expense Memorandum Account

On June 21, 2018, the CPUC issued a decision granting the Utility’s request to establish a WEMA to track specific incremental wildfire liability costs effective as of July 26, 2017. In the WEMA, the Utility can record costs related to wildfires, including: (1) payments to satisfy wildfire claims, including any deductibles, co-insurance and other insurance expenses paid by the Utility but excluding costs that have already been forecasted and adopted in the Utility’s GRC; (2) outside legal costs incurred in the defense of wildfire claims; (3) insurance premium costs not in rates; and (4) the cost of financing these amounts.  Insurance proceeds, as well as any payments received from third parties, or through FERC authorized rates, will be credited to the WEMA as they are received.  The WEMA will not include the Utility’s costs for fire response and infrastructure costs, which are tracked in the CEMA.  The decision does not grant the Utility rate recovery of any wildfire-related costs. Any such rate recovery would require CPUC authorization in a separate proceeding. (See Notes 4 and 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

As of September 30, 2019, the Condensed Consolidated Financial Statements include long-term regulatory assets of $143 million, consisting of insurance premium costs that are probable of recovery (see “Long-Term Regulatory Assets” in Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1). Should PG&E Corporation and the Utility conclude in future periods that recovery of insurance premiums in excess of amounts included in authorized revenue requirements is no longer probable, PG&E Corporation and the Utility will record a charge in the period such conclusion is reached.

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Catastrophic Event Memorandum Account Applications

The CPUC allows utilities to recover the reasonable, incremental costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities through a CEMA. In 2014, the CPUC directed the Utility to perform additional fire prevention and vegetation management work in response to the severe drought in California. The costs associated with this work are also tracked in the CEMA. While the Utility believes such costs are recoverable through CEMA, its CEMA applications are subject to CPUC review and approval. For more information, see “Long-Term Regulatory Assets” in Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

2019 CEMA Application

On September 13, 2019, the Utility submitted to the CPUC its 2019 CEMA application requesting cost recovery of $159.3 million in connection with thirteen catastrophic events that included twelve wildfires and one storm for declared emergencies from mid-2017 through 2018. The 2019 CEMA application does not include costs related to the 2015 Butte fire, the 2017 Northern California wildfires, or the 2018 Camp fire. A prehearing conference was held on November 4, 2019.

PG&E Corporation and the Utility are unable to predict the timing and outcome of this overall proceeding.

2018 CEMA Application

On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and storm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation. The 2018 CEMA application originally sought cost recovery of $555 million on a forecast basis, for additional tree mortality and fire risk mitigation work anticipated in 2018 and 2019, subject to true-up if actual costs were greater or less than the forecast. However, on April 25, 2019, the CPUC adopted a decision denying cost recovery on a forecast basis for the 2018 and 2019 costs requested.

On April 25, 2019, the CPUC approved the Utility’s request for interim rate relief, allowing for recovery of $373 million of costs (63% of the total costs incurred in 2016 and 2017), compared to $588 million requested by the Utility. The interim rate relief was implemented on October 1, 2019. Costs included in the interim rate relief are subject to audit and refund. On July 1, 2019, the Utility filed a motion requesting approval to: (i) revise the 2018 CEMA testimony and workpapers to exclude forecast costs, (ii) include 2018 recorded tree mortality and fire risk reduction costs, and (iii) assist with the hiring of an independent auditor for the recorded tree mortality costs included in the 2018 CEMA. The assigned commissioner and ALJs issued three separate rulings on July 31, 2019, granting the Utility’s requests pertaining to the removal of the forecast costs and revisions, the inclusion of 2018 recorded tree mortality costs, and directed the Utility to assist with the hiring of an independent auditor in conjunction with the CPUC Energy Division. On August 7, 2019, the Utility filed a Revised Application, Revised Testimony and Revised Workpapers, reflecting a new revenue requirement request of $669 million. The $669 million incorporates (i) the removal of forecast tree mortality costs (reduction of approximately $555 million); (ii) inclusion of the 2018 Tree Mortality and Fire Risk Reduction activities (increase of approximately $90 million); and (iii) other corrections and updates found since the filing (reduction of approximately $9 million), as compared to the Utility’s original request of $1.14 billion.

The 2018 CEMA application does not include costs related to the 2015 Butte fire, the 2017 Northern California wildfires, or the 2018 Camp fire.

PG&E Corporation and the Utility are unable to predict the timing and outcome of the overall proceeding.

Fire Hazard Prevention Memorandum Account

The CPUC allows utilities to track and record costs associated with implementing regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. The Utility currently is authorized to track such costs in the FHPMA through the end of 2019. While the Utility believes such costs are recoverable, rate recovery requires CPUC reasonableness review and authorization in a separate proceeding or through a GRC.

For the amount recorded to this memorandum account as of September 30, 2019, see “Long-Term Regulatory Assets” in Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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Fire Risk Mitigation Memorandum Account

On March 12, 2019, the CPUC approved the Utility’s FRMMA to track costs incurred beginning January 1, 2019, for fire risk mitigation activities that are not otherwise covered in revenue requirements. The FRMMA was authorized by SB 901 and AB 1054 to capture mitigation costs of activities not included in a CPUC approved Wildfire Mitigation Plan.  The Utility has proposed that the FRMMA continue after the approval of its 2019 Wildfire Mitigation Plan to record costs of wildfire mitigation activities that were beyond the initial identified scope of work.

While the Utility intends to seek recovery of the FRMMA balance in a future application, rate recovery requires CPUC reasonableness review and authorization in a separate proceeding or through a GRC. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 Wildfire Mitigation Plan recorded in the FRMMA, which the Utility expects will be substantial.

For the amount recorded to this memorandum account as of September 30, 2019, see “Long-Term Regulatory Assets” in Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Wildfire Mitigation Plan Memorandum Account

On June 5, 2019, the Utility submitted an advice letter to establish the WMPMA (also called the Wildfire Plan Memorandum Account) effective May 30, 2019. The purpose of the WMPMA is to track costs incurred to implement the Utility’s Wildfire Mitigation Plan, as required by SB 901 and AB 1054. The WMPMA is required to be established upon approval of a utility’s wildfire mitigation plan to track costs incurred to implement the plan. The CPUC approved the memorandum account on August 5, 2019, so the Utility will record any costs incurred in implementing an approved Wildfire Mitigation Plan as of the effective date, June 5, 2019.

The Utility anticipates that the recovery of the costs recorded to the WMPMA would occur through a general rate case or future application at which time the CPUC would review the costs for reasonableness as required by SB 901. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 Wildfire Mitigation Plan recorded in the WMPMA, which the Utility expects will be substantial.

For the amount recorded to this memorandum account as of September 30, 2019, see “Long-Term Regulatory Assets” in Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Other Regulatory Proceedings

2019 Wildfire Mitigation Plan

On October 25, 2018, the CPUC opened an OIR to implement the provisions of SB 901 related to electric utility wildfire mitigation plans. This OIR provided guidance on the form and content of the initial wildfire mitigation plans, provided a venue for review of the initial plans, and developed and refined the content of and process for review and implementation of wildfire mitigation plans to be filed in future years. In this proceeding the CPUC will consider, among other things, how to interpret and apply SB 901’s list of required plan elements, as well as whether additional elements beyond those required in SB 901 should be included in the wildfire mitigation plans. SB 901 also requires, among other things, that such plans include a description of the preventive strategies and programs to be adopted by an electrical corporation to minimize the risk of its electrical lines and equipment causing catastrophic wildfires, including the consideration of dynamic climate change risks, plans for vegetation management, and plans for inspections of the electrical corporation’s electrical infrastructure. The scope of this proceeding does not include utility recovery of costs related to wildfire mitigation plans, which SB 901 requires to be addressed in separate rate recovery applications.

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On February 6, 2019, the Utility filed its wildfire mitigation plan (the “2019 Wildfire Mitigation Plan”) with the CPUC. The 2019 Wildfire Mitigation Plan describes forecasted work and investments in 2019 that are designed to help further reduce the potential for wildfire ignitions associated with the Utility’s electrical equipment in high fire-threat areas. The 2019 Wildfire Mitigation Plan specifically addresses wildfire risk factors that occur most frequently and have potential to start or spread a fire. The 2019 Wildfire Mitigation Plan focuses on the measures the Utility proposes to take in 2019, but includes longer-term plans, while acknowledging that the Utility may modify these plans based upon new information or conditions as the Utility implements these measures. The new and ongoing safety measures being pursued include:

•installing nearly 600 new, high-definition cameras, made available to Cal Fire and local fire officials, in high fire-threat areas by 2022, increasing coverage across high fire-threat areas to more than 90%;

•adding approximately 1,300 additional new weather stations by 2022, at a density of one station roughly every 20 circuit miles in high fire-threat areas;

•conducting enhanced safety inspections of electric infrastructure in high-fire threat areas, including approximately 735,000 electric towers and poles across approximately 5,700 transmission line miles and 25,200 distribution line miles;

•further enhancing vegetation management efforts across high and extreme fire-threat areas to address vegetation that poses higher potential for wildfire risk, such as removing or trimming trees from particular “at-risk” tree species that have exhibited a higher pattern of failing;

•continuing to disable automatic reclosing in high fire-threat areas during wildfire season and periods of high fire-risk and upgrading reclosers and circuit breakers in high fire-threat areas with remote control capabilities;

•expanding the PSPS to include all transmission and distribution lines in Tier 2 and Tier 3 High Fire-Threat District areas;

•installing stronger and more resilient poles and covered power lines, including targeted undergrounding, starting in areas with the highest fire risk, ultimately upgrading and strengthening approximately 7,100 miles over the next 10 years; and

•partnering with additional communities in high fire-threat areas to create new resilience zones that can power central community resources during a PSPS.

On February 12, February 14, and April 25, 2019, the Utility filed amendments to the 2019 Wildfire Mitigation Plan with the CPUC to correct inadvertent errors in the cost table attached to the 2019 Wildfire Mitigation Plan; refine language in the 2019 Wildfire Mitigation Plan; and modify certain 2019 Wildfire Mitigation Plan targets in light of external conditions, enhance other targets based on early learnings, and clarify targets to minimize the potential for misinterpretation, respectively.

On May 30, 2019, the CPUC approved two decisions related to the Utility’s 2019 Wildfire Mitigation Plan. The first decision was specific to the Utility’s plan and generally approved the plan, subject to certain reporting, data gathering, and other requirements set forth in the decision. The Utility-specific decision did not approve the amendment filed by the Utility on April 25, 2019. The second decision was a guidance decision for all of the utilities that submitted wildfire mitigation plans. This guidance decision included additional reporting, data gathering, and other requirements and provided that the Utility’s April 25th amendment will be examined in Phase 2 of this proceeding. 

On June 14, 2019, the assigned commissioner and ALJ issued a decision implementing Phase 2 of the OIR, announcing Phase 2 workshops to develop metrics and templates to evaluate the Utility’s 2019 Wildfire Mitigation Plan and report data consistently and a process for submission of the 2020 plans. The decision also announced that the CPUC would evaluate the Utility’s April 25th amendment in Phase 2, as well as the process for independent evaluation of the Utility’s compliance with its 2019 plan.

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On August 23, 2019, the CPUC approved the Utility’s Initial Safety Certification, which under AB 1054 entitles the Utility to certain benefits, including eligibility for a cap on wildfire fund reimbursement and for a reformed prudent manager standard. The Utility satisfied the required elements for its Initial Safety Certificate, as follows: (i) the electrical corporation has an approved wildfire mitigation plan, (ii) the electrical corporation is in good standing, which can be satisfied by the electrical corporation having agreed to implement the findings of its most recent safety culture assessment, if applicable, (iii) the electrical corporation has established a safety committee of its board of directors composed of members with relevant safety experience, and (iv) the electrical corporation has established board-of-director-level reporting to the CPUC on safety issues. The Initial Safety Certification is valid for twelve months.

On September 18, 2019, the CPUC issued a scoping memo and ruling for Phase 2 setting the scope and procedural schedule. The scope of the proceeding will largely focus on the evaluation and enforcement of wildfire mitigation plans and the implementation of AB 1054 and AB 111. Parties have an opportunity to request the CPUC hold evidentiary hearings in this phase. If the CPUC allows, evidentiary hearings will begin December 9, 2019. The Utility currently expects to file its 2020 Wildfire Mitigation Plan in early 2020. The timing is subject to change.

PG&E Corporation and the Utility are unable to predict the timing and outcome of this proceeding. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 Wildfire Mitigation Plan recorded in the FRMMA and WMPMA, which the Utility expects will be substantial.

OIR Regarding Criteria and Methodology for Wildfire Cost Recovery Pursuant to Senate Bill 901

SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT. SB 901 does not authorize securitization with respect to possible 2018 Camp fire costs.

On January 10, 2019, the CPUC adopted an OIR, which establishes a process to develop criteria and a methodology to inform determinations of the CHT in future applications under Section 451.2(a) of the Public Utilities Code for recovery of costs related to the 2017 Northern California wildfires.

On March 29, 2019, the assigned commissioner issued a scoping memo, which confirmed that the CPUC in this proceeding would establish a CHT methodology applicable only to 2017 fires, to be invoked in connection with a future application for cost recovery, and would not determine a specific financial outcome in this proceeding.

On July 8, 2019, the CPUC issued a decision in the CHT proceeding. The CPUC decision provides that “[a]n electrical corporation that has filed for relief under chapter 11 of the Bankruptcy Code may not access the Stress Test to recover costs in an application under Section 451.2(b), because the Commission cannot determine the corporation’s ‘financial status,’ which includes, among other considerations, its capital structure, liquidity needs, and liabilities, as required by Section 451.2(b).” This determination effectively bars PG&E Corporation and the Utility from access to relief under the CHT during the pendency of the Chapter 11 Cases. On August 7, 2019, the Utility submitted to the CPUC an application for rehearing of the decision. The Utility indicated in its application, among other things, that the CPUC’s decision “is contrary to law because it bars a utility that has filed for Chapter 11 from accessing the CHT, requires a utility to file a cost recovery application before the CHT will be determined, and erects ratepayer protection mechanisms as an extra-statutory hurdle for accessing the CHT.” The Utility also argued that the CPUC should apply the CHT methodology to costs related to the 2018 Camp fire.

The decision otherwise adopts a methodology to determine the CHT based on: (1) the maximum additional debt that a utility can take on and maintain a minimum investment grade credit rating; (2) excess cash available to the utility; (3) a potential maximum regulatory adjustment of either 20% of the CHT or 5% of the total disallowed wildfire liabilities, whichever is greater; and (4) an adjustment to preserve for ratepayers any tax benefits associated with the CHT. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers as part of an application under section 451.2(b).

Failure to obtain a substantial or full recovery of costs related to wildfires could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.

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OII to Consider PG&E Corporation’s and the Utility’s Proposed Plan of Reorganization

On October 4, 2019, the CPUC issued an OII to consider the ratemaking and other implications “that will result from the confirmation of a plan of reorganization and other regulatory approvals necessary to resolve” the Chapter 11 Cases (the “Chapter 11 Proceedings OII”). The Chapter 11 Proceedings OII indicates that the proceeding will “afford parties the opportunity to be heard and comment on” any CPUC “regulatory review resulting from a proposed plan of reorganization (including any amendments) filed with the Commission, any proposed settlement agreement resolving [the Chapter 11 Cases] between PG&E and Commission staff filed in connection with a plan, any regulatory approvals required pursuant to Public Utilities Code Section 3292 in order for PG&E to become eligible to participate in the wildfire fund established pursuant to Assembly Bill 1054 (AB) 1054, any other regulatory approvals required by AB 1054, and any other matters that may need to be decided by [the CPUC] in connection with a plan.” The OII anticipates that the proceeding “will serve as a venue for review of a proposed plan and all attendant issues identified as within the scope of this proceeding.” The CPUC “expects to render its decision sufficiently in advance of the June 30, 2020 statutory deadline contained in AB 1054 to allow the Bankruptcy Court to address and approve any modifications made to the plan pursuant to Commission orders.”

On October 11, 2019, the Utility filed a response to the OII. In its response, among other things, the Utility proposed that an appropriate schedule for consideration of the Proposed Plan and the TCC/Ad Hoc Noteholder Plan would include evidentiary hearings in February and March of 2020, a proposed decision on each proposed plan by April 15, 2020 and final decisions by the CPUC on each proposed plan by May 14, 2020. The response explained the Utility's view that the TCC/Ad Hoc Noteholder Plan is significantly flawed and would be contrary to the public interest.

On October 18, 2019, other parties filed responses to the OII, including the Ad Hoc Noteholder Committee. In its response, the Ad Hoc Noteholder Committee argued that the TCC/Ad Hoc Noteholder Plan meets the requirements of AB 1054, that PG&E Corporation’s and the Utility’s Proposed Plan as well as the TCC/Ad Hoc Noteholder Plan constitute a change in control that should be subject to review under Public Utilities Code section 854, and that PG&E Corporation’s and the Utility’s previous changes in share ownership and management should also be evaluated under Public Utilities Code section 854.

The CPUC held a prehearing conference on October 23, 2019, at which the assigned ALJ reserved decision on scoping and scheduling issues.

The OII states that the CPUC preliminarily expects evidentiary hearings to be conducted, commencing no later than February 2020.

Wildfire Fund Non-Bypassable Charge

In response to directives in AB 1054, on July 26, 2019, the CPUC opened a new rulemaking to consider the authorization of a non-bypassable charge to support the Wildfire Fund.  On October 24, 2019, the CPUC issued a final decision finding that the imposition of the non-bypassable charge is just and reasonable. In addition, the decision affirmed that the Utility and its customers will not pay an allocated share of the adopted wildfire charge revenue requirement unless and until the Utility participates in the Wildfire Fund. The decision also continues the same allocation of the wildfire charge revenue requirement among the investor-owned utilities as previously adopted for the Department of Water Resources power and bond charge revenue requirements. The decision proposes revenue requirements for the Utility of $404.6 million, which is based on average annual collections and shall expire at the end of the year 2035.

Transportation Electrification

California law SB 350 requires the CPUC, in consultation with the California Air Resources Board and the CEC, to direct 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 that 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.

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On May 31, 2018, the CPUC issued a final decision approving the Utility’s two-to-five year program proposals for actual expenditures up to approximately $269 million (including $198 million of capital expenditures), to support utility-owned make-ready infrastructure supporting public fast charging and medium to heavy-duty fleets. In the EV Fleet program, the Utility has a goal of providing make-ready infrastructure at 700 sites supporting 6,500 vehicles, conducting operation and maintenance of installed infrastructure, and educating customers on the benefits of electric vehicles. The final decision gives customers the option of self-funding, installing, owning, and maintaining the make-ready infrastructure installed beyond the customer meter in lieu of utility ownership, after which they would receive a utility rebate for a portion of those costs. The EV Fast Charge program has a goal to install utility-owned make-ready infrastructure at approximately 52 public charging sites amounting to roughly 234 DC fast chargers.

On December 19, 2018, the CPUC initiated a new Rulemaking for vehicle electrification matters (R.18-12-006). This new proceeding will include issues related to utility rate designs supporting transportation electrification and hydrogen fueling stations, a framework for IOUs’ transportation electrification investments, and vehicle-grid integration. A prehearing conference for this rulemaking was held on March 1, 2019. On May 2, 2019, the assigned commissioner issued a scoping memo and ruling for the proceeding, which sets forth the category, issues to be addressed, and schedule of the proceeding.

Electric Distribution Resources Plan

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

As part of the Utility’s DRP approach, on June 1, 2018, the Utility filed its first annual distribution grid needs assessment report with the CPUC, and on September 4, 2018, the Utility filed its first distribution deferral opportunity report. The distribution deferral report proposes cost effective electric distribution investments that can be deferred through deployment of dispatchable third-party-owned DERs, or non-wire alternative solutions, to operate during specific grid events.  The Utility convened a distribution planning advisory group comprised of CPUC staff, ratepayer and environmental advocates, and DER market participants, to review and provide advisory input to the Utility on its distribution deferral identification process and to identify distribution deferral opportunities.  After incorporating the advisory group’s input, on November 28, 2018, the Utility filed a proposal with the CPUC for competitively procuring distribution services from third-party owned DERs to defer selected distribution projects.  Following the CPUC’s approval of the Utility’s procurement plan on February 5, 2019, the Utility launched a competitive solicitation and is currently evaluating offers. The Utility’s next annual distribution grid was assessed and distribution deferral opportunity reports were filed and served on August 15, 2019. On November 15, 2019, the Utility will file a proposal with the CPUC for competitively procuring distribution services from third-party owned DERs to defer selected distribution projects.

On March 26, 2018, the CPUC issued a final decision requiring the Utility to include a grid modernization plan for integrating DERs in the Utility’s GRC.  The grid modernization plan for DERs must include a narrative 10-year vision for investments needed to support DER growth, while ensuring safety and service reliability.  On June 25, 2018, the Utility hosted a public grid modernization workshop for integrating DERs to provide a high-level overview of its vision and 10-year plan and incorporate stakeholder input.  On December 13, 2018, the Utility filed its 2020 GRC Application, which includes the Utility’s grid modernization vision and plan. On June 28, 2019, PAO submitted testimony recommending changes to the Utility’s grid modernization vision and plan in the Utility’s 2020 GRC application. See summary of PAO’s overall 2020 GRC testimony in “2020 General Rate Case” above.

OIR to Consider Strategies and Guidance for Climate Change Adaptation

On April 26, 2018, the CPUC opened an OIR to consider strategies for integrating climate change adaptation matters into relevant CPUC proceedings. On October 10, 2018, the CPUC issued a scoping memo, establishing two phases for this proceeding, and determined a procedural schedule. Scope of Phase 1 is on how to integrate climate change adaptation into the IOUs’ existing planning and operations to avoid or mitigate projected utility safety and reliability vulnerability to forecasted climate change impacts. Phase 2 will be scoped at a later time, but it is not expected to apply to the Utility. On October 24, 2019, the CPUC adopted a final decision extending the statutory deadline of this proceeding to September 30, 2020.

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On September 16, 2019, the assigned commissioner issued a proposed decision in this proceeding addressing some of the issues scoped in Phase 1. On October 24, 2019, the CPUC adopted another final decision that defines climate change adaptation for California’s energy utilities as “adjustment in natural and human systems to a new or changing environment. Adaptation to climate change for energy utilities regulated by the CPUC refers to adjustment in utility systems using strategic and data-driven consideration of actual or expected climatic impacts and stimuli or their effects on utility planning, facilities maintenance and construction, and communications, to maintain safe, reliable, affordable and resilient operations.” In addition, the data guidance developed in the final decision applies to all climate impact, climate risk, and climate vulnerability analyses undertaken by the investor-owned utilities with respect to their infrastructure assets, operations, and customer impacts. Finally, the final decision requires the energy utilities to adhere to the same climate scenarios and projections used in the most recent California Statewide Climate Change Assessment when analyzing climate impacts, climate risk, and climate vulnerability of utility systems, operations, and customers.

The remaining issues in Phase 1 of this proceeding include guidance on how utilities should incorporate climate adaptation into their investment plans program design and operations; how climate change might affect vulnerable and disadvantaged communities; and into which specific commission proceedings and activities climate adaptation should be incorporated, including development of specific procedures. Such issues will be considered in a subsequent decision anticipated no earlier than mid-2020.

OIR to Examine Utility De-energization of Power Lines in Dangerous Conditions

On December 13, 2018, the CPUC opened an OIR to examine the notification, mitigation, and reporting requirements on electric utilities when de-energizing power lines in case of dangerous conditions that threaten life or property in California. This proceeding has focused on the following issues:

•examining conditions in which proactive and planned de-energization is practiced;

•developing best practices and ensuring an orderly and effective set of criteria for evaluating de-energization programs;

•ensuring electric utilities coordinate with state and local level first responders, and align their systems with the Standardized Emergency Management System framework;

•mitigating the impact of de-energization on vulnerable populations;

•examining whether there are ways to reduce the need for de-energization;

•ensuring effective notice to affected stakeholders of possible de-energization and follow-up notice of actual de-energization; and

•ensuring consistency in notice and reporting of de-energization events.

On May 30, 2019, the CPUC approved a decision for phase one of this proceeding, which adopted de-energization communication and notification guidelines for the electric IOUs along with updates to requirements established in Resolution ESRB-8. The CPUC also provided clarity on phase two issues; however, a final determination of phase two issues will be conveyed in the phase two scoping memo. Phase two will take a more comprehensive look at de-energization practices, including mitigation, additional coordination across agencies, further refinements to findings in phase one, re-energization practices, and other matters.

On August 14, 2019, the former CPUC president issued a phase two scoping memo. However, subsequent to the October PSPS events, on November 1, 2019, the assigned ALJ issued a ruling suspending the schedule and scope of the proceeding and indicating that the current CPUC president will issue an amended phase two scoping memo in the near future in order to refocus the direction of the proceeding. The Utility is unable to predict the timing and outcome of this proceeding.

OIR to Develop a Risk-Based Decision-Making Framework to Evaluate Safety and Reliability Improvements and Revise the GRC Plan

On October 4, 2019, the assigned commissioner issued a proposed decision that, if adopted, would provide for a four-year GRC cycle and combine the Utility’s future GRC and GT&S rate cases. Specifically, the current three-year GRC cycle would be changed to a four-year cycle, beginning with the Utility’s 2023 GRC. The proposed decision’s schedule would call for the RAMP submittal in March 2020, followed by the GRC application in March 2021.

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As modified by the proposed decision, the filing date for GRC applications would be moved up six months from September 1 to March 1 of the year that is two years prior to the test year. This earlier submittal would be designed to provide additional time to the CPUC’s PAO to complete its review, and for the ALJ to prepare a proposed decision that could be voted upon prior to the test year. As mentioned above, the Utility would also be required to combine its currently-separate GRC and GT&S rate cases into a single rate case application beginning with its March 2020 RAMP submittal and the GRC application due to be filed in March 2021 for its 2023 test year.

The proposed decision would also deny a recommendation from the CPUC staff to open a new rulemaking to revisit its policies on the Utility’s recovery of income tax expenses and related rate base issues.

The Utility expects that a final decision could be issued, at the earliest, on November 7, 2019.

LEGISLATIVE AND REGULATORY INITIATIVES

Senate Bill 901

SB 901, signed into law on September 21, 2018, requires the CPUC to establish a CHT, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the CHT. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the CHT. SB 901 does not authorize securitization with respect to possible 2018 Camp fire costs.

On January 10, 2019, the CPUC adopted an OIR, which establishes a process to develop criteria and a methodology to inform determinations of the CHT in future applications under Section 451.2(a) of the Public Utilities Code for recovery of costs related to the 2017 Northern California wildfires. On March 29, 2019, the assigned commissioner issued a scoping memo, which confirmed that the CPUC in this proceeding would establish a CHT methodology applicable only to 2017 fires, to be invoked in connection with a future application for cost recovery, and would not determine a specific financial outcome in this proceeding. On July 8, 2019, the CPUC issued a decision in the OIR, which establishes a methodology to establish the CHT in future applications under Section 451.2(a), but determines that a utility that has filed for relief under Chapter 11 cannot access the CHT. On August 7, 2019, the Utility submitted to the CPUC an application for rehearing of the decision. The Utility indicated in its application, among other things, that the CPUC’s decision “is contrary to law because it bars a utility that has filed for Chapter 11 from accessing the CHT, requires a utility to file a cost recovery application before the CHT will be determined, and erects ratepayer protection mechanisms as an extra-statutory hurdle for accessing the CHT.” The Utility also argued that the CPUC should apply the CHT methodology to costs related to the 2018 Camp fire.

(See “Regulatory Matters - OIR to Implement Public Utilities Code Section 451.2 Regarding Criteria and Methodology for Wildfire Cost Recovery Pursuant to Senate Bill 901” above.)

In addition, SB 901 requires utilities to submit annual wildfire mitigation plans for approval by the CPUC on a schedule to be established by the CPUC.  The wildfire mitigation plan must include the components specified in SB 901, such as identification and prioritization of wildfire risks, and drivers for those risks; plans for vegetation management; actions to harden the system, prepare for, and respond to events; and protocols for disabling reclosers and deenergizing the system.  The CPUC has three months to approve a utility’s plan, with the ability to extend the deadline.  The CPUC will conduct an annual compliance review, which will be supported by an independent evaluator’s report.  The CPUC will complete the compliance review within 18 months.  SB 901 establishes factors to be considered by the CPUC when setting penalties for failure to substantially comply with the plan.  Costs associated with the wildfire mitigation plan are tracked in a memorandum account, and the costs of implementing the plan will be assessed in each utility’s GRC proceeding, or other application proceedings.  The Utility is unable to predict the timing or outcome of the CPUC’s review of the wildfire mitigation plan, the results of the CPUC compliance review of wildfire mitigation plan implementation, or the timing or extent of cost recovery for wildfire mitigation plan activities.

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Assembly Bill 1054

On July 12, 2019, the California Governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Eligible claims are claims for third party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any calendar year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to section 3293 of the Public Utilities Code, added by AB 1054.

Each of California’s large investor-owned electric utility companies that are not currently subject to Chapter 11 (Southern California Edison and San Diego Gas & Electric Company) has elected to participate in the Wildfire Fund to be established under AB 1054. On July 23, 2019, the Utility notified the CPUC of its intent to participate in the Wildfire Fund (which participation is subject to the conditions set forth in AB 1054, including those conditions outlined below).

The Wildfire Fund to be established under AB 1054 will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment. Electric utility companies that draw from the fund will only be required to repay amounts that are determined by the CPUC in an application for cost recovery not to be just and reasonable, subject to a rolling three-year disallowance cap equal to 20% of the electric utility company’s transmission and distribution equity rate base. For the Utility, this disallowance cap is expected to be approximately $2.3 billion for the three-year period starting in 2019, subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable will not need to be repaid to the fund, resulting in a draw-down of the fund. The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the Department of Water Resources charge to ratepayers, (ii) $7.5 billion in initial contributions from California’s three investor-owned electric utility companies and (iii) $300 million in annual contributions paid by California’s three investor-owned electric utility companies. The contributions from the investor-owned electric utility companies will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from ratepayers. The costs of the initial and annual contributions are allocated among the three investor-owned electric utility companies pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable utility’s service territory classified as high fire threat districts and adjusted to account for risk mitigation efforts. The Utility’s initial Wildfire Fund allocation metric is expected to be 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million). In addition, all initial and annual contributions will be excluded from the measurement of the Utility’s authorized capital structure. The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies.

AB 1054 provides that the Wildfire Fund will be established when Southern California Edison and San Diego Gas & Electric Company provide their initial contributions. On September 11, 2019, Southern California Edison and San Diego Gas & Electric Company notified the CPUC that each had provided its respective initial contribution to the Wildfire Fund.

In order to participate in the Wildfire Fund, within 60 days of the effective date of AB 1054, the Utility must obtain the Bankruptcy Court’s approval of the Utility’s election to pay the initial and annual Wildfire Fund contributions upon emergence from Chapter 11. The Utility would then be required to pay its share of the initial contribution to the Wildfire Fund upon emergence from Chapter 11, and meet certain eligibility requirements listed below, in order to participate in the Wildfire Fund. In such event (assuming the Utility satisfies the eligibility and other requirements set forth in AB 1054), the Wildfire Fund will be available to the Utility to pay for eligible claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11, subject to a limit of 40% of the amount of such claims. The balance of any such claims would need to be addressed through the Chapter 11 Cases. There are several additional eligibility requirements for the Utility, including that by June 30, 2020, the following conditions are satisfied:

•the Utility’s Chapter 11 Case has been resolved pursuant to a plan of reorganization or similar document not subject to a stay;

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•the Bankruptcy Court has determined that the resolution of the Utility’s Chapter 11 Case provides funding or otherwise provides for the satisfaction of any pre-petition wildfire claims asserted against the Utility in the Chapter 11 Case, in the amounts agreed upon in any settlement agreements, authorized by the Bankruptcy Court through an estimation process or otherwise allowed by the Bankruptcy Court;

•the CPUC has approved the Utility’s plan of reorganization and other documents resolving its Chapter 11 Case, including the Utility’s resulting governance structure as being acceptable in light of the Utility’s safety history, criminal probation, recent financial condition and other factors deemed relevant by the CPUC;

•the CPUC has determined that the Utility’s plan of reorganization and other documents resolving its Chapter 11 Case are (i) consistent with California’s climate goals as required pursuant to the California Renewables Portfolio Standard Program and related procurement requirements and (ii) neutral, on average, to the Utility’s ratepayers; and

•the CPUC has determined that the Utility’s plan of reorganization and other documents resolving its Chapter 11 Case recognize the contributions of ratepayers, if any, and compensate them accordingly through mechanisms approved by the CPUC, which may include sharing of value appreciation.

On August 23, 2019, the CPUC granted the Utility its Initial Safety Certification, which is valid for 12 months. While not a requirement for participation in the Wildfire Fund, a valid safety certification allows the Utility to benefit from AB 1054’s disallowance cap. (See “2019 Wildfire Mitigation Plan” above.)

On August 7, 2019, PG&E Corporation and the Utility submitted a motion with the Bankruptcy Court for the entry of an order authorizing PG&E Corporation and the Utility to participate in the Wildfire Fund and to make any initial and annual contributions to the Wildfire Fund upon emergence from Chapter 11. On August 26, 2019, the Bankruptcy Court entered an order granting such authorizations.

If the Utility satisfies the requirements to participate in the Wildfire Fund, the Utility will be required to fund its initial contribution upon its emergence from Chapter 11. The Utility’s required contributions to the Wildfire Fund will be substantial. Participation in the Wildfire Fund is expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.  The Utility is currently evaluating the tax treatment of the required initial and annual contributions.  The timing and amount of any potential charges associated with shareholder contributions would also depend on various factors, including the timing of resolution of the Chapter 11 Cases, the expected life of the Wildfire Fund, and the impact of future wildfires on the Wildfire Fund's claims passing capacity. The Proposed Plan filed with the Bankruptcy Court on September 23, 2019 would provide for the financing of such required contributions, but there can be no assurance that PG&E Corporation and the Utility will successfully consummate or implement any such plan, which will ultimately require Bankruptcy Court, creditor and regulatory approval. Further, there can be no assurance that the expected benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs.

The Utility expects to record its required contributions as an asset and amortize the asset over the estimated life of the Wildfire Fund. The Wildfire Fund asset will be further adjusted for impairment as the assets are used to pay eligible claims, which will result in decreases to the assets available for coverage of future events. AB 1054 does not establish a definite term of the Wildfire Fund; therefore, this accounting treatment is subject to significant judgments and estimates. The assumptions create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The most significant estimate is the number and severity of catastrophic fires that could occur in California within the participating electric utilities’ service territories during the term of the Wildfire Fund. The Utility intends to utilize historical, publicly available fire-loss data as a starting point; however, future fire-loss can be difficult to estimate due to uncertainties around the impacts of climate change, land use changes, and mitigation efforts by the California electric utility companies. Other assumptions include the estimated cost of wildfires caused by other electric utilities, the amount at which wildfire claims will be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires, the level of future insurance coverage held by the electric utilities, and the future transmission and distribution equity rate base growth of other electric utilities. Significant changes in any of these estimates could materially impact the amortization period. There could also be a significant delay between the occurrence of a wildfire and the timing of which the Utility recognizes impairment for the reduction in future coverage, due to the lack of data available to the Utility following a catastrophic event, especially if the wildfire occurs in the service territory of another electric utility. As of September 30, 2019, the Utility has not reflected the required contributions in its Condensed Consolidated Financial Statements as it has not yet satisfied all of the Wildfire Fund eligibility criteria pursuant to AB 1054.

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AB 1054 includes certain modifications to the “just and reasonable” standard to be utilized by the CPUC in determining applications for recovery of wildfire-related costs. These modifications will apply to wildfires occurring following the effective date of AB 1054. AB 1054 provides that costs and expenses arising from any such wildfires “are just and reasonable if the conduct of the electrical corporation related to the ignition was consistent with actions that a reasonable utility would have undertaken in good faith under similar circumstances, at the relevant point in time, and based on the information available to the electrical corporation at the relevant point of time.” Further, in applying such standard, the CPUC is directed to take into account factors “both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds.” Finally, AB 1054 modifies the circumstances under which an electric utility company bears the burden of demonstrating that its conduct was reasonable in accordance with the above standard.

AB 1054 also provides that the first $5.0 billion expended in the aggregate by California’s three investor-owned electric utility companies on fire risk mitigation capital expenditures included in their respective approved wildfire mitigation plans will be excluded from their respective equity rate bases. The $5.0 billion of capital expenditures will be allocated among the investor-owned electric utility companies in accordance with their Wildfire Fund allocation metrics (described above). AB 1054 contemplates that such capital expenditures may be securitized through a customer charge.

Power Charge Indifference Adjustment OIR

In 2017, the CPUC initiated the PCIA Rulemaking to make refinements to the PCIA, a cost recovery mechanism to ensure that customers that leave the Utility’s bundled service for a non-Utility provider pay their fair share of the above market costs associated with long-term power purchase commitments and utility-owned generation made on their behalf. The above market costs of the Utility’s generation portfolio are calculated using benchmarks for brown power, resource adequacy (RA) and renewable portfolio standard (RPS) attributes. On October 11, 2018, the CPUC approved a Phase 1 decision to modify the PCIA methodology establishing:

•calculation of the PCIA rate using benchmark values that more closely resemble actual market prices for RA and RPS;

•continued recovery of legacy utility-owned generation costs from CCA customers;

•elimination of the 10-year limit on PCIA cost recovery for post-2002 utility owned generation and certain storage costs; and

•an annual true-up of the PCIA rate based on actual market sales.

The Utility implemented a revised PCIA reflecting this decision in rates as of July 1, 2019.

On December 19, 2018, the CPUC initiated Phase 2 of the PCIA proceeding to address unresolved issues from Phase 1, separated into three Working Groups. In Working Group 1, the CPUC directed parties to (1) establish the method to annually update the RA and RPS price benchmarks, (2) determine the process for the annual true-up of PCIA rates to reflect actual market outcomes, and (3) determine the proper billing factors for setting the PCIA rate. A Proposed Decision was issued on September 6, 2019. On October 10, 2019, the CPUC approved a final decision that:

•approves a methodology for annually setting the price benchmark for RA and RPS based on market transactions of all load-serving entities occurring within the past 12 months;

•values any unsold RA and RPS transactions at zero for calculating the PCIA true-up at year end, meaning that bundled customers are not responsible for paying for RA and RPS attributes that are not needed for compliance; and

•establishes that the PCIA rates shall be calculated using the forecasted sales of customers in a particular billing group, rather than using system-level sales, to prevent a persistent undercollection of PCIA rates.

In Working Group 2, the CPUC ordered parties to develop a framework evaluating and approving a prepayment application, whereby departed load customers could eliminate their PCIA rate through an up-front payment. The working group is still discussing proposals. A proposed decision is expected in Q1 2020.

Lastly, in Working Group 3 the CPUC directed parties to develop structures and rules governing how the Utility addresses excess resources in its portfolio due to load loss to CCA and DA, including standards for active management of the utility’s portfolios. The working group is still discussing proposals. A proposed decision is expected in Q2 2020.

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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; the reporting and reduction of carbon dioxide and other 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 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q, as well as “Item 1A. Risk Factors” and Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 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 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1).  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 MD&A “Contractual Commitments” in Item 7 of the 2018 Form 10-K.

Off-Balance Sheet Arrangements

PG&E Corporation and the Utility do not have 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 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 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 risks associated with adverse changes in commodity prices, interest rates, and counterparty credit.

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 risk mitigation purposes 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 are discussed in detail in the 2018 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, 2019.

RECENT DEVELOPMENTS

New Chief Executive Officer of the Utility and Board Members

On August 19, 2019, Andrew M. Vesey became the Chief Executive Officer and President of the Utility. On September 11, 2019, Mr. Vesey was elected to the Board of Directors of the Utility.

On October 11, 2019, William L. Smith and John M. Woolard were elected to the Boards of Directors of PG&E Corporation and the Utility.

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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.  In addition to those items listed below, 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, AROs, and pension and other post-retirement 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 2018 Form 10-K.

Liabilities Subject to Compromise

As a result of the commencement of the Chapter 11 Cases, the payment of pre-petition liabilities is subject to compromise or other treatment pursuant to a plan of reorganization. The determination of how liabilities will ultimately be settled or treated cannot be made until the Bankruptcy Court confirms a Chapter 11 plan of reorganization and such plan becomes effective. Accordingly, the ultimate amount of such liabilities is not determinable at this time. GAAP requires pre-petition liabilities that are subject to compromise to be reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for different amounts. The amounts currently classified as LSTC are preliminary and may be subject to future adjustments depending on Bankruptcy Court actions, further developments with respect to disputed claims, determinations of the secured status of certain claims, the values of any collateral securing such claims, rejection of executory contracts, continued reconciliation or other events.

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

See the discussion above in Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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 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.  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:

•the risks and uncertainties associated with the Chapter 11 Cases, including, but not limited to, the ability to develop, consummate, and implement a plan of reorganization with respect to PG&E Corporation and the Utility, which could be adversely affected by the termination of the Exclusive Periods as to the TCC and the Ad Hoc Noteholder Committee; the ability to obtain applicable Bankruptcy Court, creditor or regulatory approvals; the effect of any alternative proposals, views or objections related to the plan of reorganization; potential complexities that may arise in connection with concurrent proceedings involving the Bankruptcy Court, the U.S. District Court, the California state court, the CPUC, and the FERC; increased costs related to the Chapter 11 Cases; the ability to obtain sufficient financing sources for ongoing and future operations; the ability to satisfy the conditions precedent to financing under the Backstop Commitment Letters and the Debt Commitment Letters and the risk that such agreements may be terminated; disruptions to PG&E Corporation’s and the Utility’s business and operations and the potential impact on regulatory compliance;

•whether, in light of the CPUC July 8, 2019 final decision in the CHT OIR that excludes companies in Chapter 11 from accessing the CHT, the Utility will be able to obtain a substantial recovery of costs related to the 2017 Northern California wildfires;

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•restrictions on PG&E Corporation’s and the Utility’s ability to pursue strategic and operational initiatives for the duration of the Chapter 11 Cases;

•PG&E Corporation’s and the Utility’s historical financial information not being indicative of future financial performance as a result of the Chapter 11 Cases;

•the potential delay in emergence from bankruptcy if PG&E Corporation and the Utility are not able to develop and consummate a consensual plan of reorganization and are forced to engage in a contested proceeding;

•the possibility that the DIP Credit Agreement is not sufficient to fund PG&E Corporation’s and the Utility’s cash requirements through their emergence from bankruptcy;

•the possibility that PG&E Corporation and the Utility may not be able to obtain exit financing on favorable terms or at all;

•the impact of AB 1054 on potential losses in connection with future wildfires;

•the outcome of the U.S. District Court matters and probation;

•the impact of the 2018 Camp fire and the 2017 Northern California wildfires, including whether the Utility will be able to timely recover costs incurred in connection with the wildfires in excess of the Utility’s currently authorized revenue requirements; the timing and outcome of the remaining wildfire investigations and the extent to which the Utility will have liability associated with these fires; the timing and amount of insurance recoveries; the timing and outcome of the 2017 Northern California Wildfires OII and potential liabilities in connection with fines or penalties that could be imposed on the Utility if the CPUC or any other law enforcement agency were to bring an enforcement action, including a criminal proceeding, and determined that the Utility failed to comply with applicable laws and regulations;

•the risks and uncertainties associated with the 2019 Kincade fire;

•the timing and outcome of any potential settlement with holders of wildfire-related claims;

•the ability of PG&E Corporation and the Utility to finance costs, expenses and other possible losses in respect of claims related to the 2018 Camp fire and the 2017 Northern California wildfires, through securitization mechanisms or otherwise, which potential financings are not addressed by AB 1054 as it only applies to wildfires occurring after July 12, 2019;

•the timing and outcome of claims arising from the 2015 Butte fire, including claims by the OES; the timing and outcome of any proceeding to recover related costs in excess of insurance through rates; and whether any regulatory enforcement proceedings in connection with the 2015 Butte fire will be opened and any additional fines or penalties imposed on the Utility;

•whether PG&E Corporation and the Utility are able to successfully challenge the application of the doctrine of inverse condemnation to the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire;

•the timing and outcome of future regulatory and legislative developments in connection with SB 901, including future wildfire reforms, inverse condemnation reform, and other wildfire mitigation measures or other reforms targeted at the Utility;

•the outcome of the Utility’s CWSP that the Utility has developed in coordination with first responders, civic and community leaders, and customers, to help reduce wildfire threats and improve safety as a result of climate-driven wildfires and extreme weather, including the Utility’s ability to comply with the targets and metrics set forth in the 2019 Wildfire Mitigation Plan; and the cost of the program, including any costs in connection with PSPS events, and the timing and outcome of any proceeding to recover such cost through rates;

•whether the Utility will be able to obtain full recovery of its significantly increased insurance premiums, and the timing of any such recovery;

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•whether the Utility can obtain wildfire insurance at a reasonable cost in the future, or at all, and whether insurance coverage is adequate for future losses or claims;

•increased employee attrition as a result of the filing of the Chapter 11 Cases;

•the timing and outcomes of the 2019 GT&S rate case, 2020 GRC, FERC TO18, TO19, and TO20 rate cases, 2018 CEMA, future applications for WEMA, FHPMA and FRMMA, future cost of capital proceeding, and other ratemaking and regulatory proceedings;

•the outcome of the probation and the monitorship imposed by the federal court after the Utility’s conviction in the federal criminal trial in 2017, the timing and outcomes of the debarment proceeding, potential reliability penalties or sanctions from the North American Electric Reliability Corporation, 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, ex parte communications, and the ultimate amount of fines, penalties, and remedial costs that the Utility may incur in connection with the outcomes;

•the effects on PG&E Corporation’s and the Utility’s reputations caused by matters such as the CPUC’s investigations of natural gas and electric incidents, the 2018 Camp fire and 2017 Northern California wildfires, locate and mark, improper communications between the CPUC and the Utility, the Utility’s ongoing enhanced and accelerated inspection of its electric transmission and distribution assets, and the implementation of the Utility’s PSPS program;

•the implementation of the Safety Culture OII decision approved on November 29, 2018, and the outcome of the proceeding, and future legislative or regulatory actions that may be taken, such as requiring the Utility to separate its electric and natural gas businesses, or restructure into separate entities, or undertake some other corporate restructuring, or transfer ownership of the Utility’s assets to municipalities or other public entities, or implement corporate governance changes;

•whether the Utility can control its costs within the authorized levels of spending, and timely recover its costs through rates; whether the Utility can continue implementing 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 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 October 1, 2018 request for rehearing of FERC’s denial of the complaint filed by the CPUC and certain other parties 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 to allow for greater participation and input from interested parties; and the timing and ultimate outcome of the Ninth Circuit Court of Appeals decision on January 8, 2018, to reverse FERC’s decision granting the Utility a 50 basis point ROE incentive adder for continued participation in the CAISO and remanding the case to FERC for further proceedings;

•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 cybersecurity, environmental laws and regulations; and the outcome of existing and future SED notices of violations;

•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 impact of SB 100, which was signed into law on September 10, 2018, that increases the percentage from 50% to 60% of California’s electricity portfolio that must come from renewables by 2030; and establishes state policy that 100% of all retail electricity sales must come from renewable portfolio standard-eligible or carbon-free resources by 2045;

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•how the CPUC and the California Air Resources Board 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;

•the impact of the California governor’s executive order issued on January 26, 2018, to implement a new target of five million zero-emission vehicles on the road in California by 2030;

•the ultimate amount of unrecoverable environmental costs the Utility incurs associated with the Utility’s natural gas compressor station site located near Hinkley, California and the Utility’s fossil fuel-fired generation sites;

•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 potential actions, such as legislation, taken by state agencies that may affect the Utility’s ability to continue operating Diablo Canyon until its planned retirement;

•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 adequacy 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;

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

•the breakdown or failure of equipment that can cause damages, including fires, and unplanned outages; and whether the Utility will be subject to investigations, penalties, and other costs in connection with such events;

•the impact that reductions in Utility customer demand for electricity and natural gas, driven by customer departures to CCAs and DA providers, 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 its natural gas and electric services;

•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;

•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 and on acceptable terms;

•the impact of 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 uncertainty in connection with the 2018 Camp fire and the 2017 Northern California wildfires, the ultimate outcomes of the CPUC’s pending investigations, and other enforcement matters will impact the Utility’s ability to make distributions to PG&E Corporation;

•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;

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•changes in the regulatory and economic environment, including potential changes affecting renewable energy sources and associated tax credits, as a result of the current federal administration; and

•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 the outcome of the forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity, and cash flows, see Item 1A. Risk Factors below and a detailed discussion of these matters contained elsewhere in MD&A. 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.

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. 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 “Chapter 11,” “Wildfire Updates” and “News & Events: Events & Presentations” tabs, respectively, in order to publicly disseminate such information. It is possible that any of these filings or information included therein could be deemed to be material information. The information contained on such 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.

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 MD&A and in Note 8 and Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

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, 2019, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures 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, and (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, 2019, 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 proceedings, PG&E Corporation and the Utility are parties to various lawsuits and regulatory proceedings in the ordinary course of their business. For more information regarding PG&E Corporation’s and the Utility’s legal proceedings and contingencies, see Notes 2, 10, and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and Part I, MD&A: “Enforcement and Litigation Matters.”

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U.S. District Court Matters and Probation

On August 9, 2016, the jury in the federal criminal trial against the Utility in the United States District Court for the Northern District of California, in San Francisco, found the Utility guilty on 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 January 26, 2017, the court imposed a sentence on the Utility in connection with the conviction. The court sentenced the Utility to a five-year corporate probation period, oversight by the Monitor for a period of five years, with the ability to apply for early termination after three years, a fine of $3 million to be paid to the federal government, certain advertising requirements, and community service.

The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period. As part of the probation, the Utility has retained the Monitor at the Utility’s expense. The goal of the Monitor is to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations, and to maintain effective ethics, compliance and safety related incentive programs on a Utility-wide basis.

On November 27, 2018, the court overseeing the Utility’s probation issued an order requiring that the Utility, the United States Attorney’s Office for the Northern District of California (the “USAO”) and the Monitor provide written answers to a series of questions regarding the Utility’s compliance with the terms of its probation, including what requirements of the Utility’s probation “might be implicated were any wildfire started by reckless operation or maintenance of PG&E power lines” or “might be implicated by any inaccurate, slow, or failed reporting of information about any wildfire by PG&E.” The court also ordered the Utility to provide “an accurate and complete statement of the role, if any, of PG&E in causing and reporting the recent 2018 Camp fire in Butte County and all other wildfires in California” since January 2017 (“Question 4 of the November 27 Order”). On December 5, 2018, the court issued an order requesting that the Office of the California Attorney General advise the court of its view on “the extent to which, if at all, the reckless operation or maintenance of PG&E power lines would constitute a crime under California law.” The responses of the Attorney General were submitted on December 28, 2018, and the responses of the Utility, the USAO and the Monitor were submitted on December 31, 2018.

On January 3, 2019, the court issued a new order requiring that the Utility provide further information regarding the 2017 Atlas fire.  The court noted that “[t]his order postpones the question of the adequacy of PG&E’s response” to Question 4 of the November 27 Order.  On January 4, 2019, the court issued another order requiring that the Utility provide, “with respect to each of the eighteen October 2017 Northern California wildfires that [Cal Fire] has attributed to [the Utility’s] facilities,” information regarding the wind conditions in the vicinity of each fire’s origin and information about the equipment allegedly involved in each fire’s ignition.  The responses of the Utility were submitted on January 10, 2019.

On January 9, 2019, the court ordered the Utility to appear in court on January 30, 2019, as a result of the court’s finding that “there is probable cause to believe there has been a violation of the conditions of supervision” with respect to reporting requirements related to the 2017 Honey fire.  In addition, on January 9, 2019, the court issued an order (the “January 9 Order”) proposing to add new conditions of probation that would require the Utility, among other things, to:

•prior to June 21, 2019, “re-inspect all of its electrical grid and remove or trim all trees that could fall onto its power lines, poles or equipment in high-wind conditions, . . . identify and fix all conductors that might swing together and arc due to slack and/or other circumstances under high-wind conditions[,] identify and fix damaged or weakened poles, transformers, fuses and other connectors [and] identify and fix any other condition anywhere in its grid similar to any condition that contributed to any previous wildfires,”

•“document the foregoing inspections and the work done and . . . rate each segment’s safety under various wind conditions,” and

•at all times from and after June 21, 2019, “supply electricity only through those parts of its electrical grid it has determined to be safe under the wind conditions then prevailing.”

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The Utility was ordered to show cause by January 23, 2019 as to why the Utility’s conditions of probation should not be modified as proposed.  The Utility’s response was submitted on January 23, 2019. The court requested that Cal Fire file a public statement, and invited the CPUC to comment, by January 25, 2019.  On January 30, 2019, the court found that the Utility had violated a condition of its probation with respect to reporting requirements related to the 2017 Honey fire. The court issued an order stating that a sentencing hearing on the probation violation will be set at a later date. Also, on January 30, 2019, the court ordered the Utility to submit to the court on February 6, 2019 the 2019 Wildfire Mitigation Plan that the Utility was required to submit to the CPUC by February 6, 2019 in accordance with SB 901, and invited interested parties to comment on such plan by February 20, 2019. In addition, on February 14, 2019, the court ordered the Utility to provide additional information, including on its vegetation clearance requirements. The Utility submitted its response to the court on February 22, 2019.

On March 5, 2019, the court issued an order proposing to add new conditions of probation that would require the Utility, among other things, to:

•“fully comply with all applicable laws concerning vegetation management and clearance requirements;”

•“fully comply with the specific targets and metrics set forth in its wildfire mitigation plan, including with respect to enhanced vegetation management;”

•submit to “regular, unannounced inspections” by the Monitor “of PG&E’s vegetation management efforts and equipment inspection, enhancement, and repair efforts” in connection with a requirement that the Monitor “assess PG&E’s wildfire mitigation and wildfire safety work;”

•“maintain traceable, verifiable, accurate, and complete records of its vegetation management efforts” and report to the Monitor monthly on its vegetation management status and progress; and

•“ensure that sufficient resources, financial and personnel, including contractors and employees, are allocated to achieve the foregoing” and to forgo issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements as set forth above.”

The court ordered all parties to show cause by March 22, 2019, as to why the Utility’s conditions of probation should not be modified as proposed. The responses of the Utility, the USAO, Cal Fire, the CPUC, and non-party victims were filed on March 22, 2019. At a hearing on April 2, 2019, the court indicated it would impose the new conditions of probation proposed on March 5, 2019, on the Utility, and on April 3, 2019, the Court issued an order imposing the new terms though amended the second condition to clarify that “[f]or purposes of this condition, the operative wildfire mitigation plan will be the plan ultimately approved by the CPUC.”

Also, on April 2, 2019, the court directed the parties to submit briefing by April 16, 2019, regarding whether the court can extend the term of probation beyond five years in light of the violation that has been adjudicated and whether the Monitor reports should be made public. The responses of the Utility, the USAO, and the Monitor were filed on April 16, 2019. The Utility’s response contended that the term of probation may not be extended beyond five years and the USAO’s response contended that whether the term of probation could be extended beyond five years was an open legal issue.

The court held a sentencing hearing on the probation violation related to reporting requirements in connection with the 2017 Honey fire on May 7, 2019. After that hearing, the court imposed two additional conditions of probation by order dated May 14, 2019: (1) requiring that PG&E Corporation’s Board of Directors, Chief Executive Officer, senior executives, the Monitor and U.S. Probation Officer visit the towns of Paradise and San Bruno “to gain a firsthand understanding of the harm inflicted on those communities;” and (2) requiring that a committee of PG&E Corporation’s Board of Directors assume responsibility for tracking progress of the 2019 Wildfire Mitigation Plan and the additional terms of probation regarding wildfire safety, reporting in writing to the full Board at least quarterly. The court also stated that it was not going to rule at this time on whether the court has authority to extend probation and would leave that question “in abeyance.” The court did not discuss whether the Monitor reports should be made public. Members of PG&E Corporation’s Board of Directors and senior management attended site visits to the Town of Paradise on June 7, 2019 and the City of San Bruno on July 16, 2019, which were coordinated by the U.S. Probation Officer overseeing the Utility’s probation. In addition, the Compliance and Public Policy Committee, a committee of PG&E Corporation’s Board of Directors, will be responsible for tracking the Utility’s progress against the Utility’s wildfire mitigation plan, as approved by the CPUC, and compliance with the terms of the Utility’s probation regarding wildfire safety.

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On July 10, 2019, the court ordered the Utility to respond to a Wall Street Journal article titled “PG&E Knew for Years Its Lines Could Spark Wildfires, and Didn’t Fix Them” on a paragraph-by-paragraph basis, stating the extent to which each paragraph in the article is accurate.  The court also ordered the Utility to disclose all political contributions made by the Utility since January 1, 2017, and provide additional explanations regarding those contributions and dividends distributed prior to filing the Chapter 11 Cases. The Utility filed its response with the court on July 31, 2019. In the response, the Utility disagreed with the Wall Street Journal article’s suggestion that the Utility knew of the specific maintenance conditions that caused the 2018 Camp fire and nonetheless deferred work that would have addressed those conditions.

On July 26, 2019, the Monitor submitted a letter to the court regarding its VM field inspections, which were designed to evaluate the Utility’s compliance with aspects of its publicly-filed Wildfire Mitigation Plan’s EVM. The Monitor’s letter, which was filed on the public docket on August 14, 2019, provided its preliminary observations and preliminary findings, which included that (1) the Utility’s contractors had missed trees that should have been identified and worked under the EVM program; and (2) the Utility’s systems for recording, tracking and assigning EVM work were inconsistent and may have been contributing to the missed work. In its September 3, 2019 response to the Monitor’s letter, the Utility detailed its plan to address the concerns raised by the Monitor. The Monitor’s concerns and the Utility’s response were discussed at a hearing on September 17, 2019.

During the September 17, 2019 hearing, the court asked the Utility to provide information about: (1) its preparation for high wind season; and (2) the number of fires 10 acres or greater allegedly caused by the Utility to date in 2019. The Utility responded on October 1, 2019 by describing its efforts to strengthen its programs and infrastructure to maximize safety and mitigate the potential wildfire risk during high wind season. The Utility also responded that as of September 17, 2019, the Utility’s equipment may have contributed to nine ignitions in 2019 that resulted in fires 10 acres or greater. Two of these fires were potentially caused by vegetation and one was potentially caused by equipment. On October 2, 2019, the court asked the Utility for further information regarding the three fires potentially caused by vegetation and equipment. In its response, which was filed on October 9, 2019, the Utility provided information regarding certain fires, including but not limited to total acreage of the fire, ignition date, and potential causes.

On October 8, 2019, the court held a hearing related to the Utility’s San Bruno community service. An additional related hearing is scheduled for November 12, 2019.

On October 14, 2019, the court issued a request for information in connection with the PSPS event the Utility initiated on October 9, 2019 that shut off power to approximately 738,000 customers in 34 counties across Northern and Central California, asking the Utility to file a statement setting forth, among other information, “how many trees and limbs fell or blew onto the deenergized lines and how many of those would likely have caused arcing had the power been left on.” The Utility’s response was filed on October 30, 2019.

On November 4, 2019, the court issued a request for information in connection with PSPS events the Utility initiated in late October of 2019, asking the Utility to file a statement setting forth, among other information, the same type of information requested on October 14, 2019 in connection with the PSPS event initiated on October 9, 2019. The Utility’s response is due on November 29, 2019.

Order Instituting an Investigation into PG&E Corporation’s and 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 “Safety Culture OII”). The CPUC directed the SED to 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 operations, including its record of safety incidents. The SED engaged a consultant to assist in the SED’s investigation and the preparation of a report containing the SED’s assessment, and subsequently, to report on the implementation by the Utility of the consultant’s recommendations.

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On May 8, 2017, the CPUC released the consultant’s report, accompanied by a scoping memo and ruling that directed the CPUC to evaluate the safety recommendations of the consultant and to consider all necessary measures, including, but not limited to, a potential reduction of the Utility’s return on equity. On November 17, 2017, the CPUC issued a further scoping memo and procedural schedule that directed the Utility to file testimony addressing a number of issues including: adoption of the safety recommendations from the consultant, the Utility’s implementation process for the safety recommendations of the consultant, the Utility’s Board of Director’s actions and initiatives related to safety culture and the consultant’s recommendations, the Utility’s corrective action program, and the Utility’s response to certain specified safety incidents that occurred in 2013 through 2015.

The Utility’s testimony was submitted to the CPUC on January 8, 2018 and stated that the Utility agrees with all the recommendations of the consultant and supports their adoption by the CPUC. Other parties’ responsive testimony was submitted on February 16, 2018, followed by the Utility’s rebuttal testimony on February 23, 2018.

On November 29, 2018, the CPUC issued a decision that directed the Utility to implement the recommendations set forth in the May 2017 consultant report no later than July 1, 2019, and to submit quarterly reports on the Utility’s implementation status beginning in the fourth quarter of 2018.

On December 21, 2018, the CPUC issued another scoping memo and ruling expanding the proceeding and directing that the CPUC “will examine [PG&E’s] current corporate governance, structure, and operations to determine if the utility is positioned to provide safe electrical and gas service, and will review alternatives to the current management and operational structures of providing electric and gas service in Northern California.”

The CPUC alleged that the Utility has had “serious safety problems with both its gas and electric operations for many years” and that despite penalties and other remedial measures in connection with these problems, PG&E Corporation and the Utility have failed to develop “a comprehensive enterprise-wide approach to addressing safety.” The scoping memo outlined a number of proposals to address the CPUC’s concerns regarding PG&E Corporation’s and the Utility’s safety culture, including, but not limited to, (i) replacement of all or part of PG&E Corporation’s and the Utility’s existing boards of directors and corporate management, (ii) separating the Utility’s gas and electric distribution and transmission businesses into separate companies, (iii) reorganizing the Utility into regional subsidiaries based on regional distinctions, (iv) reconstituting the Utility as a publicly owned utility or utilities, (v) providing for entities other than the Utility to provide generation services, and (vi) conditioning the Utility’s return on equity on safety performance. The scoping memo did not propose penalties and stated that this phase “is not a punitive phase.” The Utility submitted its background filing to the CPUC on January 16, 2019 and opening comments were filed on February 13, 2019. The Utility and other parties filed reply comments on February 28, 2019. Subsequently, the CPUC held workshops on some of the topics raised in the scoping memo on April 15, 2019 and April 26, 2019.

On June 13, 2019, the CPUC issued a decision that directed PG&E Corporation and the Utility to provide information about the safety experience and qualifications of each of the directors on their boards. PG&E Corporation and the Utility provided such information on July 3, 2019. The decision also established a Commission Advisory Panel on Corporate Governance.

On June 18, 2019, the CPUC issued a ruling requesting comments from parties on four proposals that it stated may improve the safety culture of PG&E Corporation and the Utility. The four proposals are: separating the Utility into gas and electric utilities (including, as one possibility, sale of the gas assets to a third party); establishing periodic review of the Utility’s certificate of convenience and necessity; modifying or eliminating PG&E Corporation’s holding company structure; and linking the Utility’s rate of return or return on equity to safety performance metrics.

Opening comments on the ruling were filed on July 19, 2019 and reply comments were filed on August 2, 2019.

Diablo Canyon Power Plant

For more information regarding the status of 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 2018 Form 10-K.

ITEM 1A. RISK FACTORS

For information about the significant risks that could affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, see the section of the 2018 Form 10-K and PG&E Corporation’s and the Utility’s combined Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2019 entitled “Risk Factors,” as supplemented below, and the section of this quarterly report entitled “Forward-Looking Statements.”

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PG&E Corporation’s and the Utility’s financial results could be materially affected as a result of legislative and regulatory developments.

The Utility’s financial results could be materially affected as a result of SB 901 adopted in 2018 by the California legislature. In December 2018, the CPUC opened an OIR in connection with SB 901 that will adopt criteria and a methodology for use by the CPUC in future applications for cost recovery of wildfire costs. On July 8, 2019, the CPUC issued a decision in the CHT proceeding.  The CPUC decision provides that “[a]n electrical corporation that has filed for relief under chapter 11 of the Bankruptcy Code may not access the Stress Test to recover costs in an application under Section 451.2(b), because the Commission cannot determine the corporation’s ‘financial status,’ which includes, among other considerations, its capital structure, liquidity needs, and liabilities, as required by Section 451.2(b).”  This determination effectively bars PG&E Corporation and the Utility from access to relief under the CHT during the pendency of the Chapter 11 Cases.  On August 7, 2019, the Utility submitted to the CPUC an application for rehearing of the decision. Failure to obtain a substantial or full recovery of costs related to wildfires could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. (See “Regulatory Matters - Other Regulatory Proceedings” in Item 2. MD&A.)

In addition, SB 901 requires utilities to submit annual wildfire mitigation plans for approval by the CPUC on a schedule to be established by the CPUC.  SB 901 establishes factors to be considered by the CPUC when setting penalties for failure to substantially comply with the plan.  The Utility is unable to predict the timing or outcome of the CPUC’s review of the wildfire mitigation plan, the results of the CPUC compliance review of wildfire mitigation plan implementation, or the timing or extent of cost recovery for wildfire mitigation plan activities. Failure to substantially comply with the plan could result in fines and other penalties imposed on the Utility that could be material.  (See “Regulatory Matters – Other Regulatory Proceedings” in Item 2. MD&A.)

On July 12, 2019, the California Governor signed into law AB 1054, a bill which, among other policy reforms, provides for the establishment of a statewide fund that would be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment. Although PG&E Corporation and the Utility have delivered notice to the CPUC electing to participate in the Wildfire Fund, the impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including the Utility’s eligibility to access relief under the Wildfire Fund (which is dependent on, among other things, the Chapter 11 Cases being resolved by June 30, 2020 pursuant to a plan or similar document not subject to a stay and the Utility making its initial contribution thereto), the Utility’s ability to demonstrate to the CPUC that wildfire-related costs paid from the Wildfire Fund are just and reasonable, subject to a disallowance cap and that the Wildfire Fund has sufficient remaining funds. Failure to meet the eligibility conditions to access relief under the Wildfire Fund, including the Chapter 11 Cases being resolved by June 30, 2020 and the Utility making its initial contribution thereto, would preclude PG&E Corporation and the Utility from accessing the Wildfire Fund for future wildfire-related claims and any related benefits, including the disallowance cap.

The costs of participating in the Wildfire Fund (should the Utility be eligible to do so) are expected to exceed $6.7 billion. The Utility is currently evaluating the accounting and tax treatment of the required initial and annual contributions.  The timing and amount of any potential charges associated with shareholder contributions would also depend on various factors, including the final determination of an allocation of contributions among the Utility and California’s other large electric utility companies (San Diego Gas & Electric Company and Southern California Edison Company) and the timing of resolution of the Chapter 11 Cases. In addition, there could also be a significant delay between the occurrence of a wildfire and the timing of which the Utility recognizes impairment for the reduction in future coverage, due to the lack of data available to the Utility following a catastrophic event, especially if the wildfire occurs in the service territory of another participating electric utility. Participation in the Wildfire Fund is expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows, and there can be no assurance that the benefits of participating in the Wildfire Fund ultimately outweigh these substantial costs.

Finally, AB 1054 does not apply to wildfires with an ignition date prior to the effective date of AB 1054. PG&E Corporation and the Utility may be dependent on additional legislative measures in order to facilitate the financing of costs, expenses and other possible losses in respect of claims related to the 2018 Camp fire and the 2017 Northern California wildfires. There can be no assurance that any such legislative measures will be enacted or enacted in a form that would materially address PG&E Corporation’s and the Utility’s financing needs.

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Also, in June 2018, the State of California enacted the CCPA, which will come into effect on January 1, 2020, with a 12-month look-back period requiring compliance by January 1, 2019. On October 11, 2019, the State of California announced proposed regulations which provide guidance on the requirements of the CCPA. The CCPA requires companies that process information on California residents to make new disclosures to consumers about their data collection, use and sharing practices, allows consumers to opt out of certain data sharing with third parties and provides a new cause of action for data breaches. The CCPA provides for financial penalties in the event of non-compliance and statutory damages in the event of a data security breach. However, California legislators have stated that they intend to propose amendments to the CCPA, and it remains unclear what, if any, modifications will be made to the CCPA. Failure to comply with the CCPA could result in fines imposed on PG&E Corporation and the Utility that could be material.

The Utility’s insurance coverage may not be sufficient to cover losses caused by an operating failure or catastrophic events, including severe weather events, or may not be available at a reasonable cost, or available at all.

The Utility has experienced increased costs and difficulties in obtaining insurance coverage for wildfires and other risks that could arise from the Utility’s ordinary operations.  PG&E Corporation, the Utility or its contractors and customers could continue to experience coverage reductions and/or increased insurance costs in future years.  No assurance can be given that future losses will not exceed the limits of the Utility’s insurance coverage.  Uninsured losses and increases in the cost of insurance may not be recoverable in customer rates.  A loss that is not fully insured or cannot be recovered in customer rates could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

As a result of the potential application to investor-owned utilities of a strict liability standard under the doctrine of inverse condemnation, recent losses recorded by insurance companies, the risk of increased wildfires including as a result of climate change, the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire, the Utility may not be able to obtain sufficient insurance coverage in the future at a reasonable cost, 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.

If the amount of insurance is insufficient or otherwise unavailable, or if the Utility is unable to obtain insurance at a reasonable cost or recover in rates the costs of any uninsured losses, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

PG&E Corporation’s and the Utility’s financial results could be materially affected as a result of the Utility’s implementation of its PSPS program.

As outlined in the 2019 Wildfire Mitigation Plan, PG&E Corporation and the Utility have adopted the PSPS program to proactively de-energize lines that traverse areas under elevated and extreme risks for wildfire when forecasts predict extreme fire-threat conditions. Approximately 5.4 million electric customer premises may potentially be impacted by PSPS events.

Since September 2019, PG&E Corporation and the Utility have carried out several PSPS events. On October 9, 2019, PG&E Corporation and the Utility initiated a PSPS event that shut off power to approximately 738,000 customers in 34 counties across Northern and Central California. By October 12, 2019, all of the customers impacted had their power restored. In response, on October 14, 2019, the California Governor issued a letter to PG&E Corporation describing the “scope and duration” of the outage as “unacceptable” and stating that he had asked the CPUC to “conduct a comprehensive review” of this PSPS event. In addition, the Governor urged that PG&E Corporation and the Utility “provide affected customers an automatic credit or rebate of $100 per residential customer and $250 per small business” and that such rebates “should be funded by shareholders, not ratepayers.” Also on October 14, 2019, the CPUC published a letter to the Utility, in which it described the Utility’s “failures in execution,” combined with the magnitude of the October 9, 2019 PSPS event, as having created “an unacceptable situation that should never be repeated.” The CPUC directed the Utility to “perform an after-action review and take immediate corrective actions” detailed in the letter. On October 18, 2019, the CPUC held an emergency meeting that included, among other parties, certain directors and officers of PG&E Corporation and the Utility, to discuss the PSPS event and the Utility’s PSPS program. Separately, on October 14, 2019, the court overseeing the Utility’s probation issued a request for information on the October 9, 2019 PSPS event, asking the Utility to file a statement setting forth, among other information, “how many trees and limbs fell or blew onto the deenergized lines and how many of those would likely have caused arcing had the power been left on.” On October 28, 2019, the CPUC announced that it would open a formal investigation of 2019 PSPS events, utility compliance with CPUC regulations and requirements, any resulting violations, and potential actions to ensure utilities are held accountable.

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PG&E Corporation and the Utility cannot predict the timing and outcome of such an investigation. PG&E Corporation and the Utility could be subject to additional investigations, regulatory proceedings or other enforcement actions as well as to litigation and claims by customers as a result of the Utility’s implementation of its PSPS program, including with respect to the October 9, 2019 PSPS event, which could result in fines, penalties, customer rebates or other payments. On October 29, 2019, PG&E Corporation and the Utility announced that they would issue credits to customers as suggested by the Governor with respect to the October 9, 2019 PSPS event. PG&E Corporation and the Utility estimate that such credit will result in an approximately $90 million charge for the fourth quarter of 2019. As of the date of this filing, PG&E Corporation and the Utility do not expect to issue any similar customer credits in connection with any other PSPS events (whether past events or in the future). The amount of any fines, penalties, customer rebates or other payments (if PG&E Corporation or the Utility were to issue any credits, rebates or other payments in connection with any other PSPS events (whether past events or in the future)) could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the PSPS program has had an adverse impact on PG&E Corporation’s and the Utility’s reputation with customers, regulators and policymakers and future PSPS events may increase these negative perceptions.

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

During the quarter ended September 30, 2019, PG&E Corporation did not make any equity contributions to the Utility. Also during the quarter ended September 30, 2019, PG&E Corporation did not make any sales of unregistered equity securities in reliance on an exemption from registration under the Securities Act of 1933, as amended.

Issuer Purchases of Equity Securities

During the quarter ended September 30, 2019, 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, 2019, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

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ITEM 6. EXHIBITS

EXHIBIT INDEX

3.1	Bylaws of Pacific Gas and Electric Company, amended as of October 11, 2019
10.1	Amendment No. 1 to Settlement Agreement, dated September 3, 2019, by and between PG&E Corporation and BlueMountain Capital Management, LLC
10.2	Pacific Gas and Electric Company Commitment Letter dated October 4, 2019 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 11, 2019 (File No. 1-02348, Exhibit 10.1)
10.3	PG&E Corporation Commitment Letter dated October 4, 2019 (incorporated by reference to PG&E Corporation’s Form 8-K dated October 11, 2019 (File No. 1-12609, Exhibit 10.2.)
***10.4	Form of Chapter 11 Plan Backstop Commitment Letter (incorporated by reference to PG&E Corporation’s Form 8-K dated September 30, 2019 (File No. 1-12609), Exhibit 10.1)
****10.5	Restructuring Support Agreement dated as of September 22, 2019, by and among PG&E Corporation, Pacific Gas and Electric Company, certain affiliates of American International Group, Inc., Allstate Insurance Company and certain affiliates, BG Group A Creditors, BG Group B Creditors, certain affiliates of Farmers Insurance Exchange, California Insurance Guarantee Association, Hartford Accident & Indemnity Company and certain affiliates, certain affiliates of Liberty Mutual Insurance Company, Nationwide Mutual Insurance Company and certain affiliates, State Farm Mutual Automobile Insurance Company, State Farm County Mutual Insurance Company of Texas, State Farm Fire and Casualty Company, State Farm General Insurance Company, TLFI Investments, LLC (in its capacity as holder of an economic interest in certain Subrogation Claims), The Travelers Indemnity Company and certain of its property and casualty insurance affiliates, and certain affiliates of United Services Automobile Association (incorporated by reference to PG&E Corporation’s Form 8-K dated September 22, 2019 (File No. 1-12609, Exhibit 10.1)
10.6	Agency Appointment and Assumption Agreement dated as of September 13, 2019, by and among Wilmington Trust, National Association, in its capacity as Successor Agent, PG&E Corporation, as borrower, and the Lenders signatory thereto, constituting the Required Lenders
*10.7	Offer Letter between Pacific Gas and Electric Company and Andrew M. Vesey dated July 30, 2019
31.1	Certifications of Principal Executive Officer and Principal Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certifications of Principal Executive Officers and Principal Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
**32.1	Certifications of Principal Executive Officer and Principal Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
**32.2	Certifications of Principal Executive Officers and 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 - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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

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*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.

***This Form of Chapter 11 Plan Backstop Commitment Letter is substantially similar in all material respects to each Chapter 11 Plan Backstop Commitment Letter that is otherwise required to be filed as an exhibit, except as to the Backstop Party and the amount of such Backstop Party’s Backstop Commitment Amount (as defined in the Chapter 11 Plan Backstop Commitment Letter). In accordance with instruction no. 2 to Item 601 of Regulation S-K, the registrant has filed the form of such Chapter 11 Plan Backstop Commitment Letter, with a schedule identifying the Chapter 11 Plan Backstop Commitment Letters omitted and setting forth the material details in which each Chapter 11 Plan Backstop Commitment Letter differs from the form that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any Chapter 11 Plan Backstop Commitment Letter so omitted.

****In accordance with Item 601(a)(5) of Regulation S-K, certain schedules or similar attachments to this exhibit have been omitted from this filing. Such omitted schedules or similar attachments include information about the Subrogation Claims held by each Consenting Subrogation Creditor. The registrant agrees to furnish a supplemental copy of any omitted schedule or similar attachment to the Securities and Exchange Commission upon request.

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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
Executive Vice President and Chief Financial Officer
(duly authorized officer and principal financial officer)

PACIFIC GAS AND ELECTRIC COMPANY

/s/ DAVID S. THOMASON

David S. Thomason
Vice President, Chief Financial Officer and Controller
(duly authorized officer and principal financial officer)

Dated: November 7, 2019

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