10-Q

		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				June 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
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

1

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 August 2, 2019:
PG&E Corporation:	529,223,793
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 JUNE 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

3

4

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 Safety Plan	the wildfire mitigation plan for 2019 submitted by the Utility to the CPUC pursuant to SB 901
AB	Assembly Bill
ALJ	administrative law judge
ARO	asset retirement obligation
ASU	accounting standard update issued by the FASB (see below)
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
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
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
DOGGR	Division of Oil, Gas, and Geothermal Resources of the California Department of Conservation
DRP	Distribution Resource Plan
DTSC	Department of Toxic Substances Control
EPS	earnings per common share
EV	electric vehicle
FASB	Financial Accounting Standards Board
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
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

5

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
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
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
ROE	return on equity
ROU asset	right-of-use asset
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)
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
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
WPMA	wildfire 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 June 30,						Six Months Ended June 30,
(in millions, except per share amounts)	2019			2018			2019			2018
Operating Revenues
Electric	$	2,946		$	3,312		$	5,738		$	6,263
Natural gas	997			922			2,216			2,027
Total operating revenues	3,943			4,234			7,954			8,290
Operating Expenses
Cost of electricity	837			963			1,436			1,782
Cost of natural gas	108			79			447			368
Operating and maintenance	1,942			1,786			4,029			3,390
Wildfire-related claims, net of insurance recoveries	3,900			2,125			3,900			2,118
Depreciation, amortization, and decommissioning	796			746			1,593			1,498
Total operating expenses	7,583			5,699			11,405			9,156
Operating Loss	(3,640		)	(1,465		)	(3,451		)	(866		)
Interest income	22			12			44			21
Interest expense	(60		)	(226		)	(163		)	(446		)
Other income, net	66			106			137			214
Reorganization items, net	(56		)	—			(183		)	—
Loss Before Income Taxes	(3,668		)	(1,573		)	(3,616		)	(1,077		)
Income tax benefit	(1,119		)	(593		)	(1,203		)	(542		)
Net Loss	(2,549		)	(980		)	(2,413		)	(535		)
Preferred stock dividend requirement of subsidiary	4			4			7			7
Loss Attributable to Common Shareholders	$	(2,553	)	$	(984	)	$	(2,420	)	$	(542	)
Weighted Average Common Shares Outstanding, Basic	529			516			528			516
Weighted Average Common Shares Outstanding, Diluted	529			516			528			517
Net Loss Per Common Share, Basic	$	(4.83	)	$	(1.91	)	$	(4.58	)	$	(1.05	)
Net Loss Per Common Share, Diluted	$	(4.83	)	$	(1.91	)	$	(4.58	)	$	(1.05	)
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 June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Net Loss	$	(2,549	)	$	(980	)	$	(2,413	)	$	(535	)
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates)	—			—			—			—
Total other comprehensive income	—			—			—			—
Comprehensive Loss	(2,549		)	(980		)	(2,413		)	(535		)
Preferred stock dividend requirement of subsidiary	4			4			7			7
Comprehensive Loss Attributable to Common Shareholders	$	(2,553	)	$	(984	)	$	(2,420	)	$	(542	)
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)	June 30, 2019			December 31, 2018
ASSETS
Current Assets
Cash and cash equivalents	$	3,459		$	1,668
Accounts receivable:
Customers (net of allowance for doubtful accounts of $39 and $56 at respective dates)	1,260			1,148
Accrued unbilled revenue	991			1,000
Regulatory balancing accounts	1,884			1,435
Other	2,610			2,686
Regulatory assets	212			233
Inventories:
Gas stored underground and fuel oil	99			111
Materials and supplies	509			443
Income taxes receivable	18			23
Other	535			448
Total current assets	11,577			9,195
Property, Plant, and Equipment
Electric	60,967			59,150
Gas	22,428			21,556
Construction work in progress	2,563			2,564
Other	20			2
Total property, plant, and equipment	85,978			83,272
Accumulated depreciation	(25,727		)	(24,715		)
Net property, plant, and equipment	60,251			58,557
Other Noncurrent Assets
Regulatory assets	5,349			4,964
Nuclear decommissioning trusts	3,016			2,730
Operating lease right of use asset	2,662			—
Income taxes receivable	67			69
Other	1,465			1,480
Total other noncurrent assets	12,559			9,243
TOTAL ASSETS	$	84,387		$	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)	June 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	1,679			1,975
Regulatory balancing accounts	1,370			1,076
Other	593			464
Operating lease liabilities	546			—
Disputed claims and customer refunds	—			220
Interest payable	5			228
Wildfire-related claims	100			14,226
Other	1,418			1,512
Total current liabilities	5,711			41,695
Noncurrent Liabilities
Debtor-in-possession financing	1,500			—
Regulatory liabilities	9,038			8,539
Pension and other post-retirement benefits	1,996			2,119
Asset retirement obligations	6,111			5,994
Deferred income taxes	2,354			3,281
Operating lease liabilities	2,116			—
Other	2,357			2,464
Total noncurrent liabilities	25,472			22,397
Liabilities Subject to Compromise	42,610			—
Equity
Shareholders’ Equity
Common stock, no par value, authorized 800,000,000 shares; 529,223,793 and 520,338,710 shares outstanding at respective dates	13,014			12,910
Reinvested earnings	(2,663		)	(250		)
Accumulated other comprehensive loss	(9		)	(9		)
Total shareholders’ equity	10,342			12,651
Noncontrolling Interest - Preferred Stock of Subsidiary	252			252
Total equity	10,594			12,903
TOTAL LIABILITIES AND EQUITY	$	84,387		$	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)
	Six Months Ended June 30,
(in millions)	2019			2018
Cash Flows from Operating Activities
Net loss	$	(2,413	)	$	(535	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	1,593			1,498
Allowance for equity funds used during construction	(45		)	(63		)
Deferred income taxes and tax credits, net	(915		)	(145		)
Reorganization items, net (Note 2)	90			—
Other	53			104
Effect of changes in operating assets and liabilities:
Accounts receivable	(54		)	(11		)
Wildfire-related insurance receivable	35			(144		)
Inventories	(41		)	(6		)
Accounts payable	159			39
Wildfire-related claims	(14		)	2,299
Income taxes receivable/payable	5			—
Other current assets and liabilities	(15		)	(103		)
Regulatory assets, liabilities, and balancing accounts, net	(34		)	(12		)
Liabilities subject to compromise	4,221			—
Other noncurrent assets and liabilities	132			(168		)
Net cash provided by operating activities	2,757			2,753
Cash Flows from Investing Activities
Capital expenditures	(2,410		)	(2,897		)
Proceeds from sales and maturities of nuclear decommissioning trust investments	517			802
Purchases of nuclear decommissioning trust investments	(547		)	(815		)
Other	6			15
Net cash used in investing activities	(2,434		)	(2,895		)
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	(111		)	—
Borrowings under revolving credit facilities	—			700
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	—			350
Long-term debt matured or repurchased	—			(750		)
Common stock issued	85			82
Other	(6		)	10
Net cash provided by financing activities	1,468			210
Net change in cash, cash equivalents, and restricted cash	1,791			68
Cash, cash equivalents, and restricted cash at January 1	1,675			456
Cash, cash equivalents, and restricted cash at June 30	$	3,466		$	524
Less: Restricted cash and restricted cash equivalents included in other current assets	(7		)	$	(7	)
Cash and cash equivalents at June 30	$	3,459		$	517

11

Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(21	)	$	(394	)
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	$	836		$	317
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

(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

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 June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Operating Revenues
Electric	$	2,946		$	3,312		$	5,738		$	6,263
Natural gas	997			922			2,216			2,027
Total operating revenues	3,943			4,234			7,954			8,290
Operating Expenses
Cost of electricity	837			963			1,436			1,782
Cost of natural gas	108			79			447			368
Operating and maintenance	1,940			1,786			4,044			3,390
Wildfire-related claims, net of insurance recoveries	3,900			2,125			3,900			2,118
Depreciation, amortization, and decommissioning	796			746			1,593			1,498
Total operating expenses	7,581			5,699			11,420			9,156
Operating Loss	(3,638		)	(1,465		)	(3,466		)	(866		)
Interest income	22			11			43			20
Interest expense	(60		)	(222		)	(161		)	(439		)
Other income, net	64			108			130			217
Reorganization items, net	(57		)	—			(168		)	—
Loss Before Income Taxes	(3,669		)	(1,568		)	(3,622		)	(1,068		)
Income tax benefit	(1,119		)	(592		)	(1,205		)	(544		)
Net Loss	(2,550		)	(976		)	(2,417		)	(524		)
Preferred stock dividend requirement	4			4			7			7
Loss Attributable to Common Stock	$	(2,554	)	$	(980	)	$	(2,424	)	$	(531	)
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 June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Net Loss	$	(2,550	)	$	(976	)	$	(2,417	)	$	(524	)
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 Loss	$	(2,550	)	$	(975	)	$	(2,417	)	$	(523	)
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)	June 30, 2019			December 31, 2018
ASSETS
Current Assets
Cash and cash equivalents	$	3,036		$	1,295
Accounts receivable:
Customers (net of allowance for doubtful accounts of $39 and $56 at respective dates)	1,260			1,148
Accrued unbilled revenue	991			1,000
Regulatory balancing accounts	1,884			1,435
Other	2,621			2,688
Regulatory assets	212			233
Inventories:
Gas stored underground and fuel oil	99			111
Materials and supplies	509			443
Income taxes receivable	1			5
Other	535			448
Total current assets	11,148			8,806
Property, Plant, and Equipment
Electric	60,967			59,150
Gas	22,428			21,556
Construction work in progress	2,563			2,564
Other	18			—
Total property, plant, and equipment	85,976			83,270
Accumulated depreciation	(25,725		)	(24,713		)
Net property, plant, and equipment	60,251			58,557
Other Noncurrent Assets
Regulatory assets	5,349			4,964
Nuclear decommissioning trusts	3,016			2,730
Operating lease right of use asset	2,653			—
Income taxes receivable	66			66
Other	1,325			1,348
Total other noncurrent assets	12,409			9,108
TOTAL ASSETS	$	83,808		$	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)	June 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	1,678			1,972
Regulatory balancing accounts	1,370			1,076
Other	688			498
Operating lease liabilities	543			—
Disputed claims and customer refunds	—			220
Interest payable	5			227
Wildfire-related claims	100			14,226
Other	1,420			1,497
Total current liabilities	5,804			41,060
Noncurrent Liabilities
Debtor-in-possession financing	1,500			—
Regulatory liabilities	9,038			8,539
Pension and other post-retirement benefits	1,996			2,026
Asset retirement obligations	6,111			5,994
Deferred income taxes	2,474			3,405
Operating lease liabilities	2,110			—
Other	2,408			2,492
Total noncurrent liabilities	25,637			22,456
Liabilities Subject to Compromise	41,829			—
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	409			2,826
Accumulated other comprehensive income	(1		)	(1		)
Total shareholders’ equity	10,538			12,955
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	83,808		$	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)
	Six Months Ended June 30,
(in millions)	2019			2018
Cash Flows from Operating Activities
Net loss	$	(2,417	)	$	(524	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	1,593			1,498
Allowance for equity funds used during construction	(45		)	(63		)
Deferred income taxes and tax credits, net	(920		)	(149		)
Reorganization items, net (Note 2)	91			—
Other	34			57
Effect of changes in operating assets and liabilities:
Accounts receivable	(64		)	(11		)
Wildfire-related insurance receivable	35			(144		)
Inventories	(41		)	(6		)
Accounts payable	206			40
Wildfire-related claims	(14		)	2,299
Income taxes receivable/payable	4			—
Other current assets and liabilities	(8		)	(95		)
Regulatory assets, liabilities, and balancing accounts, net	(34		)	(12		)
Liabilities subject to compromise	4,215			—
Other noncurrent assets and liabilities	141			(168		)
Net cash provided by operating activities	2,776			2,722
Cash Flows from Investing Activities
Capital expenditures	(2,410		)	(2,897		)
Proceeds from sales and maturities of nuclear decommissioning trust investments	517			802
Purchases of nuclear decommissioning trust investments	(547		)	(815		)
Other	6			15
Net cash used in investing activities	(2,434		)	(2,895		)
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	(95		)	—
Borrowings under revolving credit facility	—			650
Net repayments of commercial paper, net of discount	—			(50		)
Short-term debt financing	—			250
Short-term debt matured	—			(250		)
Long-term debt matured or repurchased	—			(400		)
Other	(6		)	10
Net cash provided by financing activities	1,399			210
Net change in cash, cash equivalents, and restricted cash	1,741			37
Cash, cash equivalents, and restricted cash at January 1	1,302			454
Cash, cash equivalents, and restricted cash at June 30	$	3,043		$	491
Less: Restricted cash and restricted cash equivalents included in other current assets	(7		)	(7		)
Cash and cash equivalents at June 30	$	3,036		$	484

18

Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(19	)	$	(387	)
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	$	836		$	317
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

(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

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 (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented.  The information at December 31, 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 pre-petition liabilities. 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 Chapter 11, 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 filed 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 administered under a Chapter 11 plan of reorganization to be voted upon by creditors and other stakeholders, and approved by the Bankruptcy Court. However, under the Bankruptcy Code, regulatory or criminal proceedings are generally not subject to an automatic stay, and PG&E Corporation and the Utility expect these proceedings to continue 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

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.

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”). Pursuant to the Exclusivity Order, PG&E Corporation’s and the Utility’s Exclusive Filing Period is extended to, and including, September 26, 2019, and PG&E Corporation’s and the Utility’s Exclusive Solicitation Period is extended to, and including, November 26, 2019.

22

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 Filing Period and the Exclusive Solicitation Period.  The Ad Hoc Noteholder Committee annexed to its motion a “Term Sheet for Plan of Reorganization.”  On July 17, 2019, the Ad Hoc Noteholder Committee filed with the Bankruptcy Court an amended version of the term sheet, along with a commitment letter with respect to certain financings described therein.  Certain third parties have filed joinders and statements in support with the Bankruptcy Court with respect to the Ad Hoc Noteholder Committee’s motion, but such parties have not taken any position on the plan construct described by the term sheet.  These third parties include TURN, two collective bargaining units representing the Utility’s employees, and the UCC. 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.  Also on July 18, 2019, the Ad Hoc Group of Subrogation Claim Holders (the “Ad Hoc Subrogation Group”), the TCC, and certain owners of common stock of PG&E Corporation (the “Shareholder Group”) filed objections to the Ad Hoc Noteholder Committee’s motion with the Bankruptcy Court. At a hearing on July 24, 2019, the Bankruptcy Court granted an oral motion of the CPUC and the Governor’s office to adjourn the hearing on the Ad Hoc Noteholder Committee’s motion from July 24, 2019 to August 13, 2019, to allow PG&E Corporation and the Utility, the CPUC, the Governor’s office, and other parties in interest time to engage in discussions regarding the formulation of a potential protocol for the efficient submission and consideration of Chapter 11 plan proposals. The parties are due to provide a status update on these discussions to the Bankruptcy Court on August 9, 2019. On August 7, 2019, the Ad Hoc Noteholder Committee submitted a statement with the Bankruptcy Court, criticizing the protocol proposed by the CPUC and including as an exhibit its own proposed “Alternative Protocol” to govern a competitive plan process. In addition, the Ad Hoc Noteholder Committee annexed to its statement a second amended version of the term sheet and a revised version of the commitment letter.

On July 23, 2019, the Ad Hoc Subrogation Group submitted its own motion, pursuant to section 1121(d)(1) of the Bankruptcy Code, to terminate the Exclusive Filing Period and the Exclusive Solicitation Period, which included as an exhibit a “Restructuring Term Sheet.” The hearing before the Bankruptcy Court on the Ad Hoc Subrogation Group’s motion is scheduled for August 13, 2019. 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. Also on August 6, 2019, the UCC filed a statement in opposition with respect to the Ad Hoc Subrogation Group’s motion, and the Shareholder Group filed an objection to the Ad Hoc Subrogation Group’s motion, both requesting that the motion be denied.

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.

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.

23

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 June 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 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 June 30, 2019:

(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Financing debt (2)	$	21,811	$	650	$	22,461
Wildfire-related claims (3)	18,012		—		18,012
Trade creditors	1,325		4		1,329
Non-qualified benefit plan	18		125		143
2001 bankruptcy disputed claims	221		—		221
Customer deposits & advances	278		—		278
Other	164		2		166
Total Liabilities Subject to Compromise	$	41,829	$	781	$	42,610

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

⁽²⁾ At June 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 $285 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. As described in Note 10 under the heading “Plan Support Agreements with Public Entities,” on June 18, 2019, PG&E Corporation and the Utility entered into agreements with certain local public entities to potentially resolve their wildfire-related claims through the Chapter 11 process.

24

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. 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. 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.

Numerous claims have been filed with the Bankruptcy Court against PG&E Corporation and the Utility relating to the period prior to the Petition Date and it is expected that new and amended claims will continue to be filed until the Bar Date, including claims amended to assign value to claims originally filed with no designated value. Through the claims resolution process, differences in amounts scheduled by PG&E Corporation and the Utility and claims filed by creditors will be investigated and resolved, including through the filing of objections with the Bankruptcy Court where appropriate. In light of the substantial number and amount of claims filed, the claims resolution process may take considerable time to complete and will likely continue after PG&E Corporation and the Utility emerge from bankruptcy. The ultimate number and amount of allowed claims is not determinable at this time.

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 $15 million and $78 million for PG&E Corporation and the Utility, respectively, during the six months ended June 30, 2019. Reorganization items, net for the three months ended June 30, 2019 and from the Petition Date through June 30, 2019 include the following:

	Three Months Ended June 30, 2019
(in millions)	Utility			PG&E Corporation (1)			PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	—		$	—		$	—
Legal and other	75			1			76
Interest income	(18		)	(3		)	(21		)
Adjustments to LSTC	—			—			—
Trustee fees (2)	—			1			1
Total reorganization items, net	$	57		$	(1	)	$	56

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

⁽²⁾ PG&E Corporation and the Utility incurred $416,667 and $250,000, respectively, in fees to the U.S. Trustee in the three months ended June 30, 2019.

	Petition Date Through June 30, 2019
(in millions)	Utility			PG&E Corporation (1)			PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	97		$	17		$	114
Legal and other	98			2			100
Interest income	(27		)	(5		)	(32		)
Adjustments to LSTC	—			—			—
Trustee fees (2)	—			1			1
Total reorganization items, net	$	168		$	15		$	183

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

⁽²⁾ PG&E Corporation and the Utility incurred $416,667 and $250,000, respectively, in fees to the U.S. Trustee through June 30, 2019.

25

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 June 30, 2019, contractual interest expense of $405 million related to LSTC has not been recorded in the financial statements. The portion of authorized revenues from the Petition Date through June 30, 2019 related to interest expense on pre-petition debt has been deferred as a non-current 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 & 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.

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. In addition, on June 26, 2019, the Utility filed a petition for review of those earlier FERC orders also in the Ninth Circuit.

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.

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. 

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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 June 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 June 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 six months ended June 30, 2019 and 2018 were as follows:

	Pension Benefits						Other Benefits
	Three Months Ended June 30,
(in millions)	2019			2018			2019			2018
Service cost for benefits earned (1)	$	111		$	129		$	14		$	17
Interest cost	190			172			19			18
Expected return on plan assets	(226		)	(256		)	(30		)	(32		)
Amortization of prior service cost	(2		)	(2		)	3			3
Amortization of net actuarial loss	—			2			(1		)	(2		)
Net periodic benefit cost	73			45			5			4
Regulatory account transfer (2)	10			39			—			—
Total	$	83		$	84		$	5		$	4

⁽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.

	Pension Benefits						Other Benefits
	Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Service cost for benefits earned (1)	$	222		$	257		$	28		$	33
Interest cost	379			344			38			35
Expected return on plan assets	(453		)	(511		)	(61		)	(65		)
Amortization of prior service cost	(3		)	(3		)	7			7
Amortization of net actuarial loss	1			3			(2		)	(3		)
Net periodic benefit cost	146			90			10			7
Regulatory account transfer (2)	21			77			—			—
Total	$	167		$	167		$	10		$	7

⁽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.

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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 June 30, 2019
Beginning balance	$	(21	)	$	17		$	(4	)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $1 and $1, respectively) (1)	(1		)	2			1
Amortization of net actuarial loss (net of taxes of $0 and $1, respectively) (1)	—			—			—
Regulatory account transfer (net of taxes of $1 and $0, respectively) (1)	1			(2		)	(1		)
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)	Three Months Ended June 30, 2018
Beginning balance	$	(30	)	$	17		$	(13	)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1 and $1, respectively)	(1		)	2			1
Amortization of net actuarial loss (net of taxes of $1 and $1, respectively)	1			(1		)	—
Regulatory account transfer (net of taxes of $0 and $0, respectively)	—			(1		)	(1		)
Net current period other comprehensive gain (loss)	—			—			—
Ending balance	$	(30	)	$	17		$	(13	)

⁽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)	Six Months Ended June 30, 2019
Beginning balance	$	(21	)	$	17		$	(4	)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $1 and $2, respectively) (1)	(2		)	5			3
Amortization of net actuarial loss (net of taxes of $0 and $1, respectively) (1)	1			(1		)	—
Regulatory account transfer (net of taxes of $1 and $1, respectively) (1)	1			(4		)	(3		)
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)	Six Months Ended June 30, 2018
Beginning balance	$	(25	)	$	17		$	(8	)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $1 and $2, respectively) (1)	(2		)	5			3
Amortization of net actuarial loss (net of taxes of $1 and $1, respectively) (1)	2			(2		)	—
Regulatory account transfer (net of taxes of $0 and $1, respectively) (1)	—			(3		)	(3		)
Reclassification of stranded income tax to retained earnings	(5		)	—			(5		)
Net current period other comprehensive gain (loss)	(5		)	—			(5		)
Ending balance	$	(30	)	$	17		$	(13	)

⁽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.

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.

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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.

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

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Electric
Revenue from contracts with customers
Residential	$	994		$	1,039		$	2,282		$	2,375
Commercial	1,135			1,234			2,088			2,307
Industrial	326			354			619			678
Agricultural	261			318			347			443
Public street and highway lighting	16			18			33			38
Other (1)	—			84			(309		)	(118		)
Total revenue from contracts with customers - electric	2,732			3,047			5,060			5,723
Regulatory balancing accounts (2)	214			265			678			540
Total electric operating revenue	$	2,946		$	3,312		$	5,738		$	6,263
Natural gas
Revenue from contracts with customers
Residential	$	343		$	452		$	1,515		$	1,410
Commercial	129			119			369			315
Transportation service only	304			264			686			560
Other (1)	(129		)	(128		)	(205		)	(179		)
Total revenue from contracts with customers - gas	647			707			2,365			2,106
Regulatory balancing accounts (2)	350			215			(149		)	(79		)
Total natural gas operating revenue	997			922			2,216			2,027
Total operating revenues	$	3,943		$	4,234		$	7,954		$	8,290

⁽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 amends the guidance relating to the definition of a lease, the recognition of lease assets and lease liabilities on the balance sheet, and the disclosure of key information about leasing arrangements.  Under the new standard, all lessees must recognize a ROU asset, reflecting the right to use the underlying asset for the lease term, and a lease liability, reflecting the obligation to make lease payments, on the balance sheet. Operating leases were previously not recognized on the balance sheet.  PG&E Corporation and the Utility adopted the ASU 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, the Corporation and Utility elected to not separate lease and non-lease components. Additionally, PG&E Corporation and the Utility have elected not to restate comparative periods upon adoption.

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PG&E Corporation and the Utility determine if an arrangement is a lease at inception. As most of the leases do not provide implicit discount rates, the Utility uses an estimate of its incremental secured borrowing rates based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities include only fixed lease payments. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Lease terms will only include options to extend or terminate the lease when it is reasonably certain that the Utility will exercise such options. The Utility recognizes lease expense in conformity with ratemaking.

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 six months ended June 30, 2019.

Cash payments arising from operating leases were $848 million for the six months ended June 30, 2019 and are presented within operating activities on the Condensed Consolidated Statement of Cash Flows. Cash payments for the principal portion of the financing lease liability will continue to be presented within financing activities. Variable lease payments not included in the financing lease liability, if any, are presented within operating activities. 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 fixed lease payments and excluding any variable lease payments. This amount is presented within the supplemental disclosures of noncash activities for the six months ended, June 30, 2019.

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, for terms between 5 years and 20 years. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land leases.

At June 30, 2019, the Utility’s operating 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 June 30, 2019		Six Months Ended June 30, 2019
Operating lease fixed cost	$	114	$	236
Operating lease variable cost	490		799
Total operating lease costs	$	604	$	1,035

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

(in millions)	June 30, 2019
2019 (1)	$	450
2020	679
2021	623
2022	548
2023	255
Thereafter	692
Total lease payments	3,247
Less imputed interest	(594		)
Total	$	2,653

⁽¹⁾ Represents the remaining expected operating lease payments from July 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)	June 30, 2019		December 31, 2018
Pension benefits (1)	$	1,928	$	1,947
Environmental compliance costs	997		1,013
Utility retained generation (2)	251		274
Price risk management	67		90
Unamortized loss, net of gain, on reacquired debt (3)	230		76
Catastrophic event memorandum account (4)	918		790
Wildfire expense memorandum account (5)	127		94
Fire hazard prevention memorandum account (6)	291		263
Fire risk mitigation memorandum account (7)	154		—
Other	386		417
Total long-term regulatory assets	$	5,349	$	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 the accelerated amortization of premiums and debt issuance costs on pre-petition debt.

⁽⁴⁾ 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.

⁽⁵⁾ Includes specific incremental wildfire liability costs the CPUC approved for tracking in June 2018. Recovery of WEMA costs are subject to CPUC review and approval.

⁽⁶⁾ 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.

⁽⁷⁾ Includes costs associated with the 2019 Wildfire Safety Plan. Recovery of FHPMA costs are subject to CPUC review and approval.

Current Regulatory Liabilities

Current regulatory liabilities are primarily comprised of the current portion of the tax reform adjustment recorded as a result of the Tax Act.

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Long-Term Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Liability Balance at
(in millions)	June 30, 2019		December 31, 2018
Cost of removal obligations (1)	$	6,233	$	5,981
Deferred income taxes (2)	4		283
Recoveries in excess of AROs (3)	472		356
Public purpose programs (4)	785		674
Employee benefit plans (5)	423		421
Other	1,121		824
Total long-term regulatory liabilities	$	9,038	$	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 net of amounts owed to customers for deferred taxes collected at higher rates before the Tax Act and amounts owed to the Utility for reversal of deferred taxes subject to flow-through treatment.

⁽³⁾ 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.)

⁽⁴⁾ 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.

⁽⁵⁾ 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)	June 30, 2019		December 31, 2018
Electric distribution	$	465	$	160
Electric transmission	91		128
Utility generation	92		79
Gas distribution and transmission	173		462
Energy procurement	654		168
Public purpose programs	97		111
Other	312		327
Total regulatory balancing accounts receivable	$	1,884	$	1,435

	Payable Balance at
(in millions)	June 30, 2019		December 31, 2018
Electric transmission	135		134
Gas distribution and transmission	6		9
Energy procurement	308		59
Public purpose programs	610		587
Other	311		287
Total regulatory balancing accounts payable	$	1,370	$	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 June 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	$	—	$	521	$	3,479

⁽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 June 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	June 30, 2019		December 31, 2018
Debt Subject to Compromise (1)
PG&E Corporation
Borrowings under Pre-Petition Credit Facilities
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)	2,965		2,965
Other borrowings:
Term Loan - Stated Maturity: 2019	variable rate(10)	250		250
Total Borrowings under Pre-Petition Credit Facility Subject to Compromise		3,215		3,215
Total Utility Debt Subject to Compromise		21,603		21,425
Total PG&E Corporation Consolidated Debt Subject to Compromise		$	22,253	$	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 $285 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 June 30, 2019, the contractual LIBOR-based interest rate on loans was 3.87%.

⁽³⁾ At June 30, 2019, the contractual LIBOR-based interest rate on the term loan was 3.60%.

⁽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.

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⁽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 June 30, 2019, the contractual interest rate on the letter of credit facility supporting these bonds was 7.70%.

⁽⁷⁾ At June 30, 2019, the contractual interest rate on the letter of credit facility supporting these bonds ranged from 7.70% to 7.83%.

⁽⁸⁾ Also includes $79 million in letters of credit.

⁽⁹⁾ At June 30, 2019, the contractual LIBOR-based interest rate on the loans was 3.67%.

⁽¹⁰⁾ At June 30, 2019, the contractual LIBOR-based interest rate on the term loan was 3.00%.

NOTE 6: EQUITY

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

PG&E Corporation issued common stock under the PG&E Corporation 401(k) plan and share-based compensation plans.  During the six months ended June 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.

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 June 30,						Six Months Ended June 30,
(in millions, except per share amounts)	2019			2018			2019			2018
Loss attributable to common shareholders	$	(2,553	)	$	(984	)	$	(2,420	)	$	(542	)
Weighted average common shares outstanding, basic	529			516			528			516
Add incremental shares from assumed conversions:
Employee share-based compensation	—			—			—			1
Weighted average common shares outstanding, diluted	529			516			528			517
Total loss per common share, diluted	$	(4.83	)	$	(1.91	)	$	(4.58	)	$	(1.05	)

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.

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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.

Volume of Derivative Activity

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

		Contract Volume at
Underlying Product	Instruments	June 30, 2019	December 31, 2018
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	174,575,917	177,750,349
	Options	16,455,000	13,735,405
Electricity (Megawatt-hours)	Forwards, Futures and Swaps	2,999,616	3,833,490
	Options	912,033	—
	Congestion Revenue Rights (3)	329,571,344	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 June 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	$	47		$	(4	)	$	48	$	91
Other noncurrent assets – other	161			—			—		161
Current liabilities – other	(25		)	4			3		(18		)
Noncurrent liabilities – other	(67		)	—			—		(67		)
Total commodity risk	$	116		$	—		$	51	$	167

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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 June 30, 2019, the Utility satisfied its obligations related to the credit-risk related contingency features.

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.

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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
	June 30, 2019
(in millions)	Level 1		Level 2		Level 3		Netting (1)			Total
Assets:
Short-term investments	$	3,402	$	—	$	—	$	—		$	3,402
Nuclear decommissioning trusts
Short-term investments	16		—		—		—			16
Global equity securities	1,959		—		—		—			1,959
Fixed-income securities	815		698		—		—			1,513
Assets measured at NAV	—		—		—		—			19
Total nuclear decommissioning trusts (2)	2,790		698		—		—			3,507
Price risk management instruments (Note 8)
Electricity	—		13		192		20			225
Gas	—		3		—		24			27
Total price risk management instruments	—		16		192		44			252
Rabbi trusts
Fixed-income securities	—		98		—		—			98
Life insurance contracts	—		71		—		—			71
Total rabbi trusts	—		169		—		—			169
Long-term disability trust
Short-term investments	5		—		—		—			5
Assets measured at NAV	—		—		—		—			142
Total long-term disability trust	5		—		—		—			147
TOTAL ASSETS	$	6,197	$	883	$	192	$	44		$	7,477
Liabilities:
Price risk management instruments (Note 8)
Electricity	$	—	$	4	$	83	$	(4	)	$	83
Gas	2		3		—		(3		)	2
TOTAL LIABILITIES	$	2	$	7	$	83	$	(7	)	$	85

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

⁽²⁾ Represents amount before deducting $491 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 six months ended June 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)	June 30, 2019
Fair Value Measurement	Assets		Liabilities		Valuation Technique	Unobservable Input	Range (1)
Congestion revenue rights	$	191	$	64	Market approach	CRR auction prices	$(13.11) - 22.76
Power purchase agreements	$	1	$	19	Discounted cash flow	Forward prices	$ 19.68 - 38.80

 ⁽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 six months ended June 30, 2019 and 2018:

	Price Risk Management Instruments
(in millions)	2019			2018
Asset (liability) balance as of April 1	$	129		$	40
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)	(20		)	(6		)
Asset (liability) balance as of June 30	$	109		$	34

⁽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 (liability) balance as of January 1	$	95	$	42
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)	14		(8		)
Asset (liability) balance as of June 30	$	109	$	34

⁽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 to approximate their carrying values at June 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 June 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		1,500		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 4.

⁽²⁾ The Utility drew $350 million from the DIP Revolving Facility on February 1, 2019 which was subsequently repaid on April 3, 2019 using certain of the proceeds of the DIP Initial Term Loan Facility.

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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 June 30, 2019	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Total Fair Value
Nuclear decommissioning trusts
Short-term investments	$	16	$	—	$	—		$	16
Global equity securities	496		1,486		(4		)	1,978
Fixed-income securities	1,431		84		(2		)	1,513
Total (1)	$	1,943	$	1,570	$	(6	)	$	3,507
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 $491 million and $408 million for the periods ended June 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)	June 30, 2019
Less than 1 year	$	26
1–5 years	541
5–10 years	340
More than 10 years	606
Total maturities of fixed-income securities	$	1,513

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

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	171		$	308		$	517		$	802
Gross realized gains on securities	56			11			22			48
Gross realized losses on securities	(26		)	(5		)	(7		)	(9		)

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 June 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)	June 30, 2019		December 31, 2018
2015 Butte fire	$	212	$	226
2017 Northern California wildfires	5,500		3,500
2018 Camp fire	12,400		10,500
Total wildfire-related claims (1)	$	18,112	$	14,226

⁽¹⁾ On the Petition Date, all wildfire-related claims were classified as LSTC and all pending litigation was stayed. As of June 30, 2019, $100 million was reclassified from LSTC to current liabilities - wildfire-related claims to reflect Bankruptcy Court approval of contributions to the Wildfire Assistance Fund.

In addition, during the three and six months ended June 30, 2019, the Utility incurred legal and other costs of $19 million and $32 million, respectively, related to the 2018 Camp fire, with no corresponding costs in the same periods in 2018. During the three and six months ended June 30, 2019, the Utility incurred legal and other costs of $7 million and $41 million, respectively, related to the 2017 Northern California wildfires, as compared to $46 million and $68 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 July 9, 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. (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations of the 2018 Camp fire.) As of the date of this filing, this 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 issued 19 investigation reports and two supplementary investigation reports that include its determination of the causes of 21 of the 2017 Northern California wildfires, and alleged that all of these fires, with the exception of the Tubbs fire, involved the Utility’s equipment.

During the second quarter of 2018, Cal Fire issued news releases announcing its determination on the causes of 16 of the 2017 Northern California wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket and Atlas fires, located in Mendocino, Lake, Butte, Sonoma, Humboldt, Nevada and Napa counties). According to the Cal Fire news releases:

• the La Porte, McCourtney, Lobo and Honey fires “were caused by trees coming into contact with power lines,” and

• the Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket and Atlas fires “were caused by electric power and distribution lines, conductors and the failure of power poles.”

Cal Fire stated in its news releases that the McCourtney, Lobo, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fire investigations, and the investigation related to the Honey fire, have been referred to the appropriate county District Attorney’s offices for review “due to evidence of alleged violations of state law.” (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations by the District Attorneys’ offices related to these fires.)

Also during the second quarter of 2018, Cal Fire released its investigation reports related to the Redwood, Cherokee, 37, Nuns and La Porte fires. Cal Fire did not refer these fires to District Attorney offices for investigation.

On October 9, 2018, Cal Fire issued a news release announcing the results of its investigation into the Cascade fire, located in Yuba County, concluding that the Cascade fire “was started by sagging power lines coming into contact during heavy winds” and that “the power line in question was owned by Pacific Gas and Electric Company.” On October 10, 2018, Cal Fire released its investigation report related to the Cascade fire. (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations of the Cascade fire by the Office of the District Attorney of Yuba County.)

On January 24, 2019, Cal Fire issued a news release and its investigation report into the cause of the Tubbs fire. Cal Fire has determined that the Tubbs fire was caused by a private electrical system adjacent to a residential structure.

During the second quarter of 2019, Cal Fire released its investigation reports related to the Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires. The Cal Fire investigation report for the Adobe fire included as Attachment 42.1 a “Supplementary Investigation Report” concerning the Pressley fire. The Cal Fire investigator concludes in the Supplementary Investigation Report that the Pressley fire was started by an ember cast from the Adobe fire.

On July 24, 2019, the CPUC released copies of Cal Fire’s investigation report related to the Point fire and supplementary investigation reports related to the Youngs fire, which Cal Fire had not previously released publicly, as attachments to the SED’s own investigative reports for those fires. (The Youngs fire is the fire that the Utility has previously referred to as the Maacama fire.) The Cal Fire investigation report for the Point fire alleges that the fire was caused by a tree limb that broke off in high winds and fell into a power line, causing the power line to contact the ground. The Cal Fire investigators in the Youngs supplementary reports conclude that the fire was caused by a tree that fell into a power line, severing the line.

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Cal Fire has not yet released its investigation reports related to the McCourtney and Lobo 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.

As described in Note 11, on June 27, 2019, the CPUC issued an OII disclosing 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. 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, relating to matters such as the Utility’s vegetation management procedures and practices, its use of recloser devices in high fire risk areas, its pro-active de-energization of powerlines during times of high fire danger and its recordkeeping and other practices.

Further, the SED is conducting investigations into certain of the other 2017 Northern California wildfires, including the McCourtney and Lobo fires. Various other entities may also be investigating certain of the fires. It is uncertain when the investigations will be complete and whether the SED will release any preliminary findings before its investigations are 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.

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.

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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 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, the TCC has submitted a motion to the Bankruptcy Court seeking relief from the automatic stay to enable certain plaintiffs to pursue their claims outside of the Chapter 11 process, as further described under the heading “Motions to Lift the Automatic Stay for Certain Tubbs Fire-Related Claims” below. PG&E Corporation and the Utility have opposed such motions.

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 were 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. 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, certain holders of subrogation claims have submitted motions to the Bankruptcy Court seeking relief from the automatic stay in order to pursue their claims outside of the Chapter 11 process, as further described under the heading “Motions to Lift the Automatic Stay for Certain Tubbs Fire-Related Claims” below. PG&E Corporation and the Utility have opposed such motions.

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 were 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. 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. It is expected that numerous wildfire-related claims will be filed against PG&E Corporation and the Utility in connection with the 2018 Camp fire and the 2017 Northern California wildfires through the Bar Date. 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 and the 2017 Northern California wildfires, as further described under the heading “Motion for the Establishment of Wildfire Claims Estimation Procedures” below.

PG&E Corporation and the Utility are continuing to review the evidence concerning the 2018 Camp fire and 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 or to the McCourtney and Lobo investigation reports prepared by Cal Fire. PG&E Corporation and the Utility and 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, regulatory proceedings and any potential enforcement proceedings, all of which could take a number of years to resolve. The timing and outcome of these and other potential proceedings are uncertain.

PG&E Corporation and the Utility, as part of their efforts to emerge from bankruptcy, are engaged in discussions with holders of claims related to the 2017 Northern California wildfires and the 2018 Camp fire in an attempt to reach a global settlement of such claims. As discussed under the heading “Plan Support Agreements with Public Entities,” PG&E Corporation and the Utility have entered into agreements with certain government entity claimholders to potentially resolve their wildfire-related claims. The most recent settlement offers made by PG&E Corporation and the Utility to subrogated insurance claimholders and individual claimholders as of the date of this filing are discussed in further detail below under the heading “2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge.” PG&E Corporation and the Utility cannot predict the outcome or timing of discussions with other claimholders.  Even if discussions with claimholders were successful, the consummation of such a global settlement would likely be contingent on numerous uncertain conditions, including Bankruptcy Court approval and governmental action.

On March 16, 2018, PG&E Corporation and the Utility filed a demurrer to the inverse condemnation cause of action in the 2017 Northern California wildfires litigation. On May 21, 2018, the court overruled the motion. On July 20, 2018, PG&E Corporation and the Utility filed a writ in the Court of Appeal requesting appellate review of the trial court’s decision, which was denied on September 17, 2018. On September 27, 2018, PG&E Corporation and the Utility filed a petition for review to the California Supreme Court. On November 14, 2018, the California Supreme Court denied PG&E Corporation’s and the Utility’s petition for review.

Motions to Lift the Automatic Stay for Certain Tubbs Fire-Related Claims

On July 2, 2019, the TCC submitted a motion, pursuant to section 362(d)(1) of the Bankruptcy Code, for entry of an order terminating the automatic stay to permit certain individual plaintiffs (the “Tubbs Preference 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 the Tubbs Preference 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 July 19, 2019, PG&E Corporation and the Utility filed an objection to the motions of the TCC and the Ad Hoc Subrogation Group, requesting that the motions be denied. Also on July 19, 2019, the UCC and the Shareholder Group filed objections to the motions of the TCC and the Ad Hoc Subrogation Group with the Bankruptcy Court, requesting that the motions be denied. The Shareholder Group also joined in PG&E Corporation’s and the Utility’s objection to the motions of the TCC and the Ad Hoc Subrogation Group.

On July 22, 2019, the Bankruptcy Court issued an order continuing the hearings on the TCC’s and the Ad Hoc Subrogation Group’s motions for relief from the automatic stay to August 14, 2019.

Motion for the Establishment of Wildfire Claims Estimation Procedures

On July 18, 2019, PG&E Corporation and the Utility submitted a motion, pursuant to sections 105(a) and 502(c) of the Bankruptcy Code, for entry of an order establishing procedures and schedules for the estimation of PG&E Corporation’s and the Utility’s aggregate liability for contingent and/or unliquidated claims arising out of the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (which are collectively referred to in this paragraph as “wildfire claims”). In the motion, PG&E Corporation and the Utility proposed, among other things, the following general parameters of the estimation process:

• First, the Bankruptcy Court would address the legal issue of whether, pursuant to the state law doctrine of inverse condemnation, PG&E Corporation and the Utility may be held strictly liable for wildfire claims asserting property damages even where PG&E Corporation or the Utility were not negligent.

• Second, the Bankruptcy Court would schedule a hearing on the limited issue of causation of the Tubbs fire on October 7, 2019, or as soon as possible thereafter.

• Third, following the Bar Date, the Bankruptcy Court would determine the aggregate value of the wildfire claims in a hearing proposed to be scheduled for early December 2019. This phase of the estimation process would involve the resolution of questions around the likelihood of success of the wildfire claims on issues such as negligence, the recoverability of certain categories of damages and the aggregate estimate of overall damages based upon sampling of claims and expert testimony. In the motion, PG&E Corporation and the Utility indicated that they are prepared to agree that, as part of the proposed estimation process, they will not contest causation with respect to any wildfire for which Cal Fire has concluded that PG&E Corporation and the Utility are responsible, including the 2018 Camp fire and the 2017 Northern California wildfires identified above, except the Tubbs fire.

The motion is expected to be heard by the Bankruptcy Court on August 14, 2019. On August 7, 2019, certain third parties filed joinders and statements in support with the Bankruptcy Court with respect to PG&E Corporation’s and the Utility’s motion, including the Ad Hoc Noteholder Committee, the UCC and the Shareholder Group. Also on August 7, 2019, certain third parties filed objections to PG&E Corporation’s and the Utility’s motion with the Bankruptcy Court, including the City and County of San Francisco, the Ad Hoc Subrogation Group and the TCC. The objection of the City and County of San Francisco is limited to PG&E Corporation’s and the Utility’s proposal for the Bankruptcy Court to address the legal issue of whether, under the doctrine of inverse condemnation, PG&E Corporation and the Utility may be held strictly liable for wildfire claims asserting property damages even where it was not negligent.

Plan Support Agreements with Public Entities

On June 18, 2019, PG&E Corporation and the Utility entered into PSAs with certain local 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”). PG&E Corporation and the Utility’s Chapter 11 plan of reorganization currently is under development and has not yet been filed with the Bankruptcy Court.  PG&E Corporation and the Utility have entered into a PSA with each of the following public entities or group of public entities, as applicable: 

• the City of Clearlake, the City of Napa, the City of Santa Rosa, the County of Lake, the Lake County Sanitation District, the County of Mendocino, Napa County, the County of Nevada, the County of Sonoma, the Sonoma County Agricultural Preservation and Open Space District, the Sonoma County Community Development Commission, the Sonoma County Water Agency, the Sonoma Valley County Sanitation District and the County of Yuba (collectively, the “2017 Northern California Wildfire Public Entities”);

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• the Town of Paradise;

• the County of Butte;

• the Paradise Recreation & Park District;

• the County of Yuba; and

• the Calaveras County Water District. 

For purposes of each PSA, the local public entities that are party to such PSA are referred to herein as “Supporting Public Entities.”

Each PSA provides that PG&E Corporation and the Utility’s Chapter 11 plan of reorganization will include, among other things, the following elements: 

• following the effective date of PG&E Corporation and the Utility’s Chapter 11 plan of reorganization, PG&E Corporation and the Utility will remit a Settlement Amount (as defined below) in the amount set forth below to the applicable Supporting Public Entities in full and final satisfaction and discharge of their Public Entity Wildfire Claims, and

• subject to the Supporting Public Entities voting affirmatively to accept PG&E Corporation and the Utility’s Chapter 11 plan of reorganization, following the effective date of PG&E Corporation and the Utility’s Chapter 11 plan of reorganization, PG&E Corporation and the Utility will create and promptly fund $10.0 million to a segregated fund to be used by the Supporting Public Entities collectively in connection with the defense or resolution of claims against the Supporting Public Entities by third parties relating to the wildfires noted above (“Third Party Claims”). 

The “Settlement Amount” set forth in each PSA is as follows: 

• for the 2017 Northern California Wildfire Public Entities, $415.0 million (which amount will be allocated among such entities),

• for the Town of Paradise, $270.0 million,

• for the County of Butte, $252.0 million,

• for the Paradise Recreation & Park District, $47.5 million,

• for the County of Yuba, $12.5 million, and

• for the Calaveras County Water District, $3.0 million.

Each PSA provides that, subject to certain terms and conditions, the Supporting Public Entities will support PG&E Corporation and the Utility’s Chapter 11 plan of reorganization with respect to its treatment of their respective Public Entity Wildfire Claims, including by voting to accept PG&E Corporation and the Utility’s Chapter 11 plan of reorganization in the Chapter 11 Cases.

Each PSA may be terminated by the applicable Supporting Public Entities under certain circumstances, including:

• if the Federal Emergency Management Agency or the OES fails to agree that no reimbursement is required from the Supporting Public Entities on account of assistance rendered by either agency in connection with the wildfires noted above, and

• by any individual Supporting Public Entity, if a material amount of Third Party Claims is filed against such Supporting Public Entity and such Third Party Claims are not released pursuant to PG&E Corporation and the Utility’s Chapter 11 plan of reorganization. 

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Each PSA may be terminated by PG&E Corporation and the Utility under certain circumstances, including if:

• PG&E Corporation and the Utility do not obtain the consent, or the waiver of the lack of consent as a defense, of their insurance carriers for the policy years 2017 and 2018,

• the Board of Directors of either PG&E Corporation or the Utility determines in good faith that continued performance under the PSA would be inconsistent with the exercise of its fiduciary duties, and

• any Supporting Public Entity terminates a PSA, in which case PG&E Corporation and the Utility may terminate any other PSA.

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. These claims reflect insured property losses only. 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.

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, 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 wildfire-related claims that will be filed in the Chapter 11 Cases, 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 treated and whether such claims will be allowed, and 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. 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, which amount does not include potential punitive damages, fines and penalties or damages related to claims that have not manifested yet. 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, and 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. 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.

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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.

2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge

Following accounting rules, PG&E Corporation and the Utility record a liability when a loss is probable and reasonably estimable. In accordance with U.S. generally accepted accounting principles, 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 is the amount within the range that is a better estimate than any other amount 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.

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. Based on additional facts and circumstances available to the Utility as of the date of this filing, including the entry into the PSAs and the status of PG&E Corporation’s and the Utility’s efforts to reach a resolution with other holders of wildfire-related claims, PG&E Corporation and the Utility recorded an additional charge for claims in connection with the 2018 Camp fire in the amount of $1.9 billion for the three months ended June 30, 2019.

The aggregate liability of $12.4 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 total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. 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 2018 Camp fire may change, which could result in material increases to the loss accrued.

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The $12.4 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.

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. Based on additional facts and circumstances available to the Utility as of the date of this filing, including additional information from Cal Fire, the entry into the PSAs and the status of PG&E Corporation’s and the Utility’s efforts to reach a resolution with other holders of wildfire-related claims, 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 June 30, 2019.

The aggregate liability of $5.5 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.

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. However, as a result of PG&E Corporation’s and the Utility’s most recent settlement offer to holders of claims related to the Tubbs and 37 fires as of the date of this filing, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with such fires. With respect to 17 of the other 19 of the 2017 Northern California wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, Blue, Pocket, Atlas, Cascade, Point and Sonoma/Napa merged fires (which include the Nuns, Norrbom, Adobe, Partrick and Pythian 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. With respect to 2 of the other 19 of the 2017 Northern California wildfires (the Youngs and Pressley fires), PG&E Corporation and the Utility have 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 based on information that became available to PG&E Corporation and the Utility after the filing of their last Quarterly Report on Form 10-Q.

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 total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. 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 $5.5 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.

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Additional Information Related to 2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge

The aggregate liability of $17.9 billion for claims in connection with the 2018 Camp fire and the 2017 Northern California wildfires is comprised of (i) $8.5 billion for subrogated insurance claimholders, (ii) $7.5 billion for individual claimholders (including those with uninsured and underinsured property losses, among other claims), (iii) $1.0 billion for the Supporting Public Entities with respect to their Public Entity Wildfire Claims pursuant to the PSAs and (iv) $900 million for clean-up and fire suppression costs. The aggregate liabilities of $8.5 billion for subrogated insurance claimholders and $7.5 billion for individual claimholders are based on PG&E Corporation’s and the Utility’s estimates of probable loss developed from data and other information available to PG&E Corporation and the Utility and PG&E Corporation’s and the Utility’s most recent settlement offers to representatives of such claimholders as of the date of this filing. PG&E Corporation and the Utility cannot predict the outcome or timing of discussions with such claimholders. With respect to the $1.0 billion liability for claims held by the Supporting Public Entities, while PG&E Corporation and the Utility previously disclosed the existence of claims asserted by such entities, PG&E Corporation and the Utility had not previously taken a charge related to these claims as the amount of the liability could not be reasonably estimated. As described above, the aggregate liability of $17.9 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.)

As of the date of this filing, PG&E Corporation and the Utility believe that the settlement discussions with representatives of subrogated insurance claimholders are in a particularly critical period of the negotiation. PG&E Corporation and the Utility believe that the potential exists for material developments in the negotiation in the near term. Accordingly, if PG&E Corporation, the Utility and such claimholders reach agreement, PG&E Corporation’s and the Utility’s probable loss contingency for the subrogated insurance claims may increase by a material amount, which would result in an additional accrual above the $8.5 billion reflected in this filing. Any such increase could be substantial and could be taken in the third quarter of 2019. In their motion submitted to the Bankruptcy Court on July 23, 2019, the Ad Hoc Subrogation Group stated that holders of subrogated insurance claims hold in excess of $20 billion of wildfire-related claims against PG&E Corporation and the Utility. In the “Restructuring Term Sheet” attached to such motion, the Ad Hoc Subrogation Group proposed terms for a plan of reorganization that would settle all such subrogated insurance claims for consideration valued at $15.8 billion. PG&E Corporation and the Utility cannot predict the outcome or timing of discussions with such claimholders.

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 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.

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 June 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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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 following table presents changes in the insurance receivable for the six months ended June 30, 2019. The balance for insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:

(in millions)	Insurance Receivable
2018 Camp fire
Balance at December 31, 2018	$	1,380
Accrued insurance recoveries	—
Reimbursements	—
Balance at June 30, 2019	$	1,380
2017 Northern California wildfires
Balance at December 31, 2018	$	829
Accrued insurance recoveries	—
Reimbursements	—
Balance at June 30, 2019	$	829

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 customer harm threshold, 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 (the “Customer Harm Threshold”). 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 Customer Harm Threshold. 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 Customer Harm Threshold 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 Customer Harm Threshold 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 Customer Harm Threshold 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 Customer Harm Threshold 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 [Customer Harm Threshold], requires a utility to file a cost recovery application before the CHT [Customer Harm Threshold] will be determined, and erects ratepayer protection mechanisms as an extra-statutory hurdle for accessing the CHT [Customer Harm Threshold].” The Utility also argued that the CPUC should apply the Customer Harm Threshold methodology to costs related to the 2018 Camp fire.

The decision otherwise adopts a methodology to determine the Customer Harm Threshold 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 Customer Harm Threshold 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 Customer Harm Threshold. 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. 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. 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. 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.

Wildfire-Related Securities Class Action Litigation

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 federal 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.

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, and PG&E Corporation and the Utility are currently seeking an order from the Bankruptcy Court to extend the stay to the officer, director, and underwriter defendants.

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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.”

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 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.

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.

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Clean-up and Repair Costs

The Utility incurred costs of $655 million for clean-up and repair of the Utility’s facilities (including $236 million in capital expenditures) through June 30, 2019, in connection with the 2018 Camp fire. The Utility also incurred costs of $334 million for clean-up and repair of the Utility’s facilities (including $161 million in capital expenditures) through June 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 June 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 June 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 will consist of $105 million deposited into a segregated account to be controlled by an independent third-party administrator appointed by the Bankruptcy Court, who will disburse and administer the funds. The administrator will be responsible for developing the specific eligibility requirements and application procedures for the distribution of the Wildfire Assistance Fund to eligible claimants. 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.

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.

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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.

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.

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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.

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. 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. It is expected that numerous wildfire-related claims will be filed against PG&E Corporation and the Utility in connection with the 2015 Butte fire through the Bar Date. 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 2015 Butte fire, as further described under the heading “Motion for the Establishment of Wildfire Claims Estimation Procedures” above.

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.

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.

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PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets included liabilities for 2015 Butte fire third-party claims of $226 million and $212 million as of December 31, 2018 and June 30, 2019, respectively, reflecting payments of $14 million in January 2019, prior to the Petition Date. As of June 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 June 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 $85 million and $50 million as of December 31, 2018 and June 30, 2019, respectively, reflecting reimbursements of $35 million during the six months ended June 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.

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.

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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 Safety 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. As of April 30, 2019, to the Utility’s knowledge, no parties have submitted comments to the court on the 2019 Wildfire Safety Plan.

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;”

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• “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’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’s Board of Directors assume responsibility for tracking progress of the 2019 Wildfire Safety 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.

CPUC and FERC Matters

Order Instituting an Investigation 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.”

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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 requires 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 is 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 must 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.

The OII also indicates that the assigned commissioner shall set a prehearing conference for 45 to 60 days after the initiation of the proceeding or as soon as practicable after the CPUC makes the assignment. The assigned commissioner will also issue a scoping memo setting forth the scope of the proceeding and establishing a procedural schedule.

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.

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.

Order Instituting an Investigation 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.

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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.

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 reach a partial stipulation in order to streamline the proceeding.  On April 24, 2019, the Utility provided notice of a settlement conference and the parties have continued 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 the Utility’s 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. The parties continue settlement discussions. In accordance with the current procedural schedule issued by the ALJ on June 27, 2019, intervenor testimony is due August 16, 2019, and the Utility’s reply testimony is due September 18, 2019.  The SED’s rebuttal testimony is due October 4, 2019.  Evidentiary hearings are scheduled for October 21 to 25, 2019.

Based on the information available to PG&E Corporation and the Utility as of the date of this filing, PG&E Corporation and the Utility believe it is probable that the Utility will incur penalties, including fines or other remedies. Accordingly, PG&E Corporation and the Utility recorded a charge during the quarter ended June 30, 2019 for an amount that is not material, which corresponds to the lower end of the range of PG&E Corporation's and the Utility's reasonably estimated losses and is subject to change based on additional information.  PG&E Corporation and the Utility are unable to determine a better estimate within such range 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.

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.

Order Instituting an Investigation 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 (formerly known as the Office of Ratepayer Advocates or ORA), the SED, and TURN.

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.

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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 June 30, 2019, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets include an $16 million accrual 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 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 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.

At June 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. 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)	June 30, 2019		December 31, 2018
Topock natural gas compressor station	$	346	$	369
Hinkley natural gas compressor station	142		146
Former manufactured gas plant sites owned by the Utility or third parties (1)	580		520
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	112		111
Fossil fuel-fired generation facilities and sites (3)	125		137
Total environmental remediation liability	$	1,305	$	1,283

⁽¹⁾ Primarily driven by the following sites: Vallejo, San Francisco East Harbor, Napa, Beach Street, San Francisco North Beach, and San Rafael MGP-Bio Marin MGP.

⁽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 June 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 June 30, 2019, the Utility expected to recover $960 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 $302 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 2019 and finalized in 2020. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $139 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 $528 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 $98 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 $86 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. For the period from August 1, 2019 through July 31, 2020, PG&E Corporation and the Utility have secured approximately $430 million for general wildfire liability (subject to an initial self-insured retention of $10 million per occurrence). PG&E Corporation and the Utility continue to pursue additional insurance coverage for the period from August 1, 2019 through July 30, 2020. 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 July 31, 2020 (consisting of the $430 million general wildfire liability coverage described above and $520 million for non-wildfire general liability) is approximately $190 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 June 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 $5 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 June 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 six months ended June 30, 2019.

NOTE 12: SUBSEQUENT EVENTS

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.

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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.

AB 1054 provides that the Wildfire Fund will be established when Southern California Edison and San Diego Gas & Electric Company provide their initial contributions.

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;

• 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 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. The motion is expected to be heard on August 28, 2019, and objections and other responses are due August 21, 2019.

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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 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.  The Utility is currently developing a Chapter 11 plan of reorganization that would provide for the financing of such required contributions, but there can be no assurance that PG&E Corporation and the Utility will successfully develop, 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.

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

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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.

Summary of Changes in Net Income and Earnings per Share

PG&E Corporation’s net loss was $2,553 million and $2,420 million in the three and six months ended June 30, 2019, respectively, compared to net losses of $984 million and $542 million in the same periods in 2018. PG&E Corporation recognized charges of $1.9 billion and $2.0 billion, net of probable insurance recoveries, associated with the 2018 Camp fire and the 2017 Northern California wildfires, respectively, for the three and six months ended June 30, 2019, compared to charges of $2.1 billion, net of probable insurance recoveries, associated with the 2017 Northern California wildfires during the same periods in 2018.

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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 expect 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. Although PG&E Corporation and the Utility have currently retained the exclusive rights to file a plan of reorganization until September 26, 2019 and to solicit acceptances thereof until November 26, 2019, the Ad Hoc Noteholder Committee and the Ad Hoc Subrogation Group have submitted motions to the Bankruptcy Court for the entry of orders terminating these exclusive rights. If these rights are terminated, there could be 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.

• 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, cash flow from operations and distributions received from subsidiaries, 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, distributions received from subsidiaries, and availability under the DIP Credit Agreement are not sufficient to meet these 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 June 30, 2019, the Utility recorded total charges of $18 billion, which reflects the low end of the range of reasonably estimated 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 (other than potential punitive damages, fines and penalties or damages related to future claims), could exceed $30 billion; any punitive damages, fines and penalties or damages related to future claims could be material;

◦ whether, in light of the CPUC July 8, 2019 final decision in the Customer Harm Threshold OIR that excludes companies in Chapter 11 from accessing the Customer Harm Threshold, 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 fines or penalties that could result therefrom;

◦ 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 determined that the Utility had failed to comply with applicable laws and regulations;

◦ the amount of damages in respect of future claims, which could be material;

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◦ the applicability of the doctrine of inverse condemnation in the 2018 Camp fire and 2017 Northern California wildfires litigation, which the Utility intends to continue to challenge during the pendency of its Chapter 11 Case; 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, which potential financings are not addressed by AB 1054 as it only applies to future wildfires;

◦ the amount and recoverability of enhanced and accelerated inspection costs of the Utility’s electric transmission and distribution assets (the Utility incurred costs of $275 million and $485 million for enhanced and accelerated inspection and repair costs for the three and six months ended June 30, 2019, respectively); and

◦ the amount and recoverability of clean-up and repair costs (the Utility incurred costs of $989 million for clean-up and repair of the Utility’s facilities through June 30, 2019).

(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 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 loses 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.

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, PG&E Corporation and the Utility emerging from Chapter 11 by June 30, 2020 and making the 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 Outcome of Other Enforcement, Litigation, and Regulatory Matters. 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.)

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• The Timing and Outcome of Ratemaking Proceedings. The Utility’s financial results may be impacted by the timing and outcome of its 2019 GT&S rate case, 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, WPMA, and FRMMA that are incurred in connection with the Utility's 2019 Wildfire Safety 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.)

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.

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 six months ended June 30, 2019 and 2018:

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Consolidated Total	$	(2,553	)	$	(984	)	$	(2,420	)	$	(542	)
PG&E Corporation	1			(4		)	4			(11		)
Utility	$	(2,554	)	$	(980	)	$	(2,424	)	$	(531	)

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

Utility

The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three and six months ended June 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 June 30, 2019									Three Months Ended June 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	$	1,872		$	1,074		$	2,946		$	1,979		$	1,333		$	3,312
Natural gas operating revenues	792			205			997			752			170			922
Total operating revenues	2,664			1,279			3,943			2,731			1,503			4,234
Cost of electricity	—			837			837			—			963			963
Cost of natural gas	—			108			108			—			79			79
Operating and maintenance	1,562			378			1,940			1,244			542			1,786
Wildfire-related claims, net of insurance recoveries	3,900			—			3,900			2,125			—			2,125
Depreciation, amortization, and decommissioning	796			—			796			746			—			746
Total operating expenses	6,258			1,323			7,581			4,115			1,584			5,699
Operating loss	(3,594		)	(44		)	(3,638		)	(1,384		)	(81		)	(1,465		)
Interest income	22			—			22			11			—			11
Interest expense	(60		)	—			(60		)	(222		)	—			(222		)
Other income, net	20			44			64			27			81			108
Reorganization items	(57		)	—			(57		)	—			—			—
Loss before income taxes	$	(3,669	)	$	—		$	(3,669	)	$	(1,568	)	$	—		$	(1,568	)
Income tax benefit (1)							(1,119		)							(592		)
Net loss							(2,550		)							(976		)
Preferred stock dividend requirement							4									4
Loss Attributable to Common Stock							$	(2,554	)							$	(980	)

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

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	Six Months Ended June 30, 2019									Six Months Ended June 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	$	3,786		$	1,952		$	5,738		$	3,915		$	2,348		$	6,263
Natural gas operating revenues	1,586			630			2,216			1,490			537			2,027
Total operating revenues	5,372			2,582			7,954			5,405			2,885			8,290
Cost of electricity	—			1,436			1,436			—			1,782			1,782
Cost of natural gas	—			447			447			—			368			368
Operating and maintenance	3,256			788			4,044			2,494			896			3,390
Wildfire-related claims, net of insurance recoveries	3,900			—			3,900			2,118			—			2,118
Depreciation, amortization, and decommissioning	1,593			—			1,593			1,498			—			1,498
Total operating expenses	8,749			2,671			11,420			6,110			3,046			9,156
Operating loss	(3,377		)	(89		)	(3,466		)	(705		)	(161		)	(866		)
Interest income	43			—			43			20			—			20
Interest expense	(161		)	—			(161		)	(439		)	—			(439		)
Other income, net	41			89			130			56			161			217
Reorganization items	(168		)	—			(168		)	—			—			—
Loss before income taxes	$	(3,622	)	$	—		$	(3,622	)	$	(1,068	)	$	—		$	(1,068	)
Income tax benefit (1)							(1,205		)							(544		)
Net loss							(2,417		)							(524		)
Preferred stock dividend requirement							7									7
Loss Attributable to Common Stock							$	(2,424	)							$	(531	)

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

Utility Revenues and Costs that Impacted Earnings

The following discussion presents the Utility’s operating results for the three and six months ended June 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 decreased by $67 million, or 2%, and $33 million, or 1% in the three and six months ended June 30, 2019, respectively, compared to the same periods in 2018, primarily due to the regulatory treatment of interest on pre-petition debt and other impacts of the Chapter 11 Cases.

Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings increased by $318 million, or 26%, in the three months ended June 30, 2019, compared to the same period in 2018, primarily due to $275 million related to enhanced and accelerated inspections and repairs of transmission and distribution assets and $71 million for clean-up and repair costs relating to the 2018 Camp fire, with no similar charges in the same period in 2018.

The Utility’s operating and maintenance expenses that impacted earnings increased by $762 million, or 31%, in the six months ended June 30, 2019, compared to the same period in 2018, primarily due to $485 million related to enhanced and accelerated inspections and repairs of transmission and distribution assets and $250 million for clean-up and repair costs relating to the 2018 Camp fire, with no similar charges in the same period in 2018. Additionally, the Utility recorded $40 million in clean-up and repair costs relating to the 2017 Northern California wildfires in the six months ended June 30, 2018, with no similar charges in the same period in 2019.

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Wildfire-related claims, net of insurance recoveries

Costs related to wildfires that impacted earnings increased by $1,775 million, or 84%, and $1,782 million, or 84%, in the three and six months ended June 30, 2019, respectively, compared to the same periods in 2018. The Utility recognized pre-tax charges of $1.9 billion and $2.0 billion associated with the 2018 Camp fire and 2017 Northern California wildfires, respectively, for the three and six months ended June 30, 2019, as compared to pre-tax charges of $2.5 billion, offset by probable insurance recoveries of $375 million, associated with the 2017 Northern California wildfires during the same periods 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 $50 million, or 7%, and $95 million, or 6%, in the three and six months ended June 30, 2019, respectively, compared to the same periods in 2018, primarily due to capital additions.

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 $162 million, or 73%, and $278 million, or 63% in the three and six months ended June 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 $57 million and $168 million in the three and six months ended June 30, 2019, respectively, compared to the same periods in 2018, due to $75 million and $195 million, respectively, of expenses directly associated with the Utility’s Chapter 11 filing in the three and six months ended June 30, 2019, partially offset by interest income of $18 million and $27 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

Income tax benefits increased by $527 million and $661 million in the three and six months ended June 30, 2019, respectively, as compared to the same periods in 2018. The increases in income tax benefits were primarily the result of higher pretax losses in the three and six months ended June 30, 2019, compared to the same period 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 June 30,				Six Months Ended June 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)	7.4	%	8.6	%	7.7	%	11.5	%
Effect of regulatory treatment of fixed asset differences (2)	2.3	%	6.2	%	4.6	%	16.8	%
Tax credits	0.1	%	0.2	%	0.2	%	0.6	%
Other, net	(0.3	)%	1.9	%	(0.2	)%	1.1	%
Effective tax rate	30.5	%	37.9	%	33.3	%	51.0	%

⁽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 June 30,				Six Months Ended June 30,
(in millions)	2019		2018		2019		2018
Cost of purchased power, net (1)	$	796	$	919	$	1,295	$	1,672
Fuel used in generation facilities	41		44		141		110
Total cost of electricity	$	837	$	963	$	1,436	$	1,782

⁽¹⁾ Cost of purchased power, net decreased for the three and six months ended June 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 June 30,				Six Months Ended June 30,
(in millions)	2019		2018		2019		2018
Cost of natural gas sold	$	82	$	53	$	391	$	310
Transportation cost of natural gas sold	26		26		56		58
Total cost of natural gas	$	108	$	79	$	447	$	368

⁽¹⁾ One thousand cubic feet

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 full amount of the DIP Revolving Facility (including the full amount 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 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 August 7, 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 $537 million in face amount of letters of credit outstanding under the DIP Revolving Facility. As of August 7, 2019, there were undrawn commitments of $500 million and $3.0 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.”

Equity Financings

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

During the six months ended June 30, 2019, PG&E Corporation issued 8.3 million shares for cash proceeds of $85.2 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’s matching contributions under its 401(k) plan are deposited in cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PCG common stock fund on the open market rather than from PG&E Corporation.

PG&E Corporation does not expect to issue equity for the remaining duration of the Chapter 11 Cases.

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 2018 Camp fire and 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 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. (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:

	Six Months Ended June 30,
(in millions)	2019			2018
Net cash provided by operating activities	$	2,776		$	2,722
Net cash used in investing activities	(2,434		)	(2,895		)
Net cash provided by financing activities	1,399			210
Net change in cash, cash equivalents and restricted cash	$	1,741		$	37

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 six months ended June 30, 2019, net cash provided by operating activities increased by $54 million compared to the same period in 2018.  This increase was due to a reduction in interest paid of $368 million, offset by 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.

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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 2019 GT&S rate case, 2020 GRC, FERC TO18, TO19 and TO20 rate cases, 2018 CEMA filing, 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 Safety Plan (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.

Investing Activities

Net cash used in investing activities decreased by $461 million during the six months ended June 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 $7.1 billion in capital expenditures in 2019, and $7 billion in 2020.

Financing Activities

Net cash provided by financing activities increased by $1.2 billion during the six months ended June 30, 2019 as compared to the same period in 2018.  This increase was primarily due to $1.5 billion of borrowings under the DIP Initial Term Loan Facility 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.”

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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 July 15, 2019, the ALJ approved briefing dates in August and September of 2019.  No evidentiary hearings are scheduled.  The Utility is unable to predict the timing and outcome of its waiver application.

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 revenue requirement amounts currently authorized in the Utility’s 2015 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	%

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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 and 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 Utility also proposed to file a new cost of capital application with the CPUC on or about the time it emerges from its Chapter 11 proceeding.  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.

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 gas distribution operations, assuming 2017 authorized rate base amounts.  The revenues for the gas transmission and storage operations would increase by approximately $51 million, assuming 2018 authorized rate base amounts.  However, if the CPUC subsequently approves different electric and gas rate base amounts for the Utility in its 2019 GT&S Rate Case and its 2020 GRC, both 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 2015 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 2015 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	$	1,269	$	1,320

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 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. According to the current schedule, rebuttal testimony is due August 16, 2019, and additional rebuttal on testimony regarding the passage of AB 1054 is due August 21, 2019. A proposed decision would be issued on November 15, 2019. A final decision would be issued no sooner than 30 days after the proposed decision.  The Utility is unable to predict the timing and outcome of this proceeding.

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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.

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. The PFM, if adopted, would 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 July 12, 2019, a proposed decision on the PFM was issued requesting that the Utility make additional reductions to the revenue requirements.  There were two primary changes: first, to include the cost of removal component of book depreciation when calculating the amortization of protected excess deferred income taxes using the average rate assumption method (ARAM); and second, to amortize unprotected excess deferred taxes over a shorter period of time developed in collaboration with the Energy Division. The earliest the CPUC can consider this matter is on August 15, 2019. The Utility cannot predict the timing and outcome of this matter.

The Utility provided an update of the cost effectiveness study for the SmartMeter^TM Upgrade project to the CPUC on July 10, 2017. On July 11, 2019, the CPUC further extended the statutory deadline for the 2017 GRC to February 9, 2020, in order to allow for comments and CPUC action on a PD on the SmartMeter^TM upgrade cost effectiveness study.  The Utility cannot predict the timing and outcome of any CPUC action in connection with this study.

For more information, 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 has requested that the CPUC determine the annual amount of base revenues (or “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 has 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 (Decrease) 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
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	$	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, emergency response efforts, and 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 Safety Balancing Account to track and record actual incremental expenses and capital revenue requirements associated with the incremental costs of fire risk mitigation work that are not already addressed and recorded in another account; this would include the costs associated with overhead system hardening, enhanced vegetation management, and other incremental costs of wildfire mitigations.

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. The Utility also may seek or may be required to update the scope of work for the 2019 Wildfire Safety Plan that was approved by the CPUC on June 4, 2019.

In its application, the Utility requests that the CPUC issue a final decision by March 2020 and that the 2020 GRC rates 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 June 28, 2019, PAO submitted testimony recommending that the CPUC authorize a 2020 GRC revenue requirement of $503 million, or 5.91%, higher than the 2019 authorized level. PAO also recommended establishing a one-way balancing account for the Utility’s revenue requirement during the rate case term (2020 to 2022).

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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.

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 July 15, 2019, a proposed decision on the PFM was issued requesting that the Utility make additional reductions to the revenue requirements.  There were two primary changes: first, to include the cost of removal component of book depreciation when calculating the amortization of protected excess deferred income taxes using the average rate assumption method (ARAM); and second, to amortize unprotected excess deferred taxes over a shorter period of time developed in collaboration with the Energy Division. The earliest a final decision could be voted is on August 15, 2019. The Utility cannot predict the timing and outcome of this matter.

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

2019 Gas Transmission and Storage Rate Case

On November 17, 2017, the Utility filed its 2019 GT&S rate case application with the CPUC for the years 2019 through 2021. The Utility also provided a revenue requirement and rates for 2022, in the event the CPUC adopts an additional year. On October 1, 2018, the Utility entered into a stipulation with PAO that, if approved, would extend the rate case cycle through 2022 as recommended by PAO.

In its application, the Utility requested that the CPUC authorize a 2019 revenue requirement of $1.59 billion to recover anticipated costs of providing natural gas transmission and storage services beginning on January 1, 2019. This corresponds to an increase of $289 million over the Utility’s 2018 authorized revenue requirement of $1.30 billion. The Utility’s request also proposed revenue requirements of $1.73 billion for 2020, $1.91 billion for 2021, and $1.91 billion for 2022 if the CPUC orders a fourth year for the rate case period.

The Utility subsequently revised its forecast revenue requirement as a result of the Tax Act and other forecast updates, including significant reductions in the areas of gas storage facilities and gas system operations programs. The revised revenue requirements are as follows: $1.48 billion for 2019, $1.59 billion for 2020, $1.69 billion for 2021, and $1.68 billion for 2022. The revised 2019 requested revenue requirement corresponds to an increase of $184 million over the Utility’s 2018 authorized revenue requirement.

The requested rate base for 2019 is $4.75 billion, which corresponds to an increase of $1.04 billion over the 2018 adopted rate base of $3.71 billion. The Utility’s request is based on capital expenditure forecasts of $829 million for 2019, $872 million for 2020, and $830 million for 2021 (which exclude common capital allocations). The requested rate base amounts 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. 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 requested increase in revenue requirement is largely attributable to increased infrastructure investment and costs related to new natural gas storage safety and environmental regulations issued by DOGGR, the Pipeline and Hazardous Materials Safety Administration, and the CPUC.

In response to the Utility’s application, parties proposed various forecast reductions. For example, the PAO recommended a 2019 revenue requirement of $1.35 billion, an increase of $45 million over 2018 adopted amounts. TURN proposed widespread reductions in forecast costs and recommended capital and expense disallowances of more than $500 million.

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A second phase of the proceeding addressed the removal of officer compensation costs from the revenue requirement, which is required by SB 901. On March 1, 2019, the Utility, PAO and TURN submitted a joint stipulation to the CPUC proposing to reduce the Utility’s requested 2019 GT&S operating expenses by $1.428 million and capital expenditures by $455,000 for total operating expenses and capital expenditures of $617 million and $829 million, respectively.

In this case, the CPUC will authorize the revenue requirement that the Utility will collect through rates to recover its anticipated costs of providing natural gas transmission and storage services from 2019 through 2021, or 2022, in the event the CPUC adopts an additional year.

On July 16, 2019, the assigned ALJ issued a PD in the Utility’s 2019 GT&S rate case pending at the CPUC. The PD proposes a 2019 revenue requirement of $1.327 billion compared to the Utility’s (revised) request of $1.485 billion. This corresponds to an increase of $27 million over the Utility’s 2018 authorized revenue requirement of $1.301 billion, compared to the $184 million increase requested by the Utility. The PD also proposes revenue requirements of $1.427 billion for 2020, and $1.511 billion for 2021, compared to the Utility’s request of $1.595 billion for 2020, and $1.693 million for 2021. The PD also proposes a revenue requirement of $1.575 billion for 2022, compared to the Utility’s request of $1.679 billion for 2022. The proposed revenue requirement for 2022 allows for the possible combination of the Utility’s 2023 GRC and GT&S rate cases.

The revenue requirement amounts requested by the Utility and the revenue requirement amounts in the PD 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
PD	$	1,301	$	1,327	$	1,427	$	1,511	$	1,575

The PD proposes to remove from rate base of $304 million of pipeline replacement capital expenditures for the 2016-2018 period due to cost overruns. Incorporating this reduction, the PD proposes 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 PD proposes a rate base of $4.98 billion for 2020, $5.37 billion for 2021, and $5.71 billion for 2021. 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 PD proposes the adoption of 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 adopts a two-way balancing account for storage costs, which will be subject to a reasonableness review in the next GT&S rate case. The PD proposes to retain the one-way balancing account for transmission integrity management, and to adopt a number of new, one-way balancing accounts covering other operational areas.

If adopted, the PD also would resolve the second phase of the proceeding, which addressed the removal of officer compensation costs from the revenue requirement, which is required by SB 901. The PD proposes adoption of 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.

Opening comments on the PD were filed on August 5, 2019. The CPUC may vote on the PD, at the earliest, on August 15, 2019. The Utility is unable to predict the timing and outcome of this proceeding.

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

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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.

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 is seeking a return on equity of 10.9%, which includes an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO.  In the filing, the Utility forecasted that it 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 set 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.

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 2.83% 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 recommendations. 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 is $6.9 billion.  The Utility is seeking an ROE of 10.75%, which includes an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO.  In the filing, the Utility forecasted capital expenditures of approximately $1.4 billion.  On September 28, 2017, the FERC issued an order accepting the Utility’s July 2017 filing, subject to hearing and refund, and established March 1, 2018, as the effective date for rate changes.  FERC also ordered that the hearings 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.

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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, settlement judge procedures, and consolidation 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 unappealable TO18 decision. Additionally, if FERC determined 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.

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 revenues, including Construction Work in Progress, will be updated to the actual cost of service annually. Differences between amounts collected and determined under the formula rate will be either collected from or refunded to customers.

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 a settlement conference on March 14 to 15, 2019 and on June 13 to 14, 2019. The next settlement conference is scheduled for August 13 to 14, 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 this non-cash charge 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 (AFUDC) 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, and established hearing and settlement judge procedures.

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.

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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 a Diablo Canyon site-specific decommissioning cost estimate of $4.8 billion which represents a total cost estimate to decommission the Diablo Canyon facilities.

On February 14, 2019, the CPUC issued a scoping memo authorizing addressing the scope of the NDCTP Proceeding to include reasonableness reviews of the Diablo Canyon decommissioning cost estimates, ratemaking proposals, proposed Diablo Canyon milestone framework, plans to address host community needs, reasonableness of Humboldt Bay Power Plant decommissioning costs, and reasonableness of preforming Diablo Canyon planning activities pre-shutdown including the proposed rate of recovery of these pre-planning activities addressed in Application 18-07-013.

On March 7, 2019, the CPUC amended the scoping memo to combine A.18-07-013, 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 NDCTP A.18-12-008. 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 Proceeding. The CPUC will hold a public participation hearing for residents and organizations in and near San Luis Obispo to give their perspective and input to the CPUC about the Utility’s request to track costs of Diablo Canyon Decommissioning Planning Activities. The public participation hearing is scheduled for August 7 to 8, 2019.

On July 15, 2019, intervenors in this proceeding submitted their testimonies. Rebuttal Testimony is due August 15, 2019.

The Utility seeks to collect $383.7 million and $3.9 million for the funding of 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 3-year period 2020 to 2022 and a $44 million revenue requirements for the 2-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.

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 expense 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 June 30, 2019, the Condensed Consolidated Financial Statements include long-term regulatory assets of $127 million, consisting of insurance premium costs that are probable of recovery. 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 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 Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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, subject to true-up if actual costs were greater or less than the forecast, for additional tree mortality and fire risk mitigation work anticipated in 2018 and 2019. 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 November 2, 2018, the assigned ALJ denied the Utility’s July 25, 2018 motion requesting interim rate relief for $441 million, which represents 75% of the costs incurred in 2016 and 2017 related to storms, wildfires and tree mortality response work. Subsequently, on December 4, 2018, the Utility filed a renewed motion for interim rate relief, due to worsening financial conditions. The renewed motion for interim relief sought approximately $588 million, which represents 100% of the total costs incurred in 2016 and 2017 for the activities referenced above. The Utility requested that cost recovery occur over a one-year period, with the amounts collected to be subject to refund based on the authorized amount in the proceeding. On April 25, 2019, the CPUC authorized 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).  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 and 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 $90.318 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. During 2018, the Utility recorded $262 million of costs to the FHPMA, corresponding to vegetation management work performed to comply with CPUC December 2017 fire safety regulations. While the Utility believes such costs are recoverable, rate recovery requires CPUC reasonableness review and authorization in a separate proceeding or through a GRC.

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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 to capture mitigation costs incurred in advance of the CPUC’s approval of the Utility’s 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 Safety Plan recorded in the FRMMA, which the Utility expects will be substantial.

Wildfire Plan Memorandum Account

On June 5, 2019, the Utility submitted an advice letter to establish the WPMA effective May 30, 2019. The purpose of the WPMA is to track costs incurred to implement the Utility’s Wildfire Mitigation Plan, as required by SB 901. The WPMA is required to be established upon approval of a utility’s wildfire mitigation plan to track costs incurred to implement the plan. Upon approval of the memorandum account, the Utility will record any costs incurred in implementing an approved Wildfire Mitigation Pan.

The Utility anticipates that the recovery of the costs recorded to the WPMA 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 Safety Plan recorded in the WPMA, which the Utility expects will be substantial.

Other Regulatory Proceedings

2019 Wildfire Safety 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.

On February 6, 2019, the Utility filed its wildfire mitigation plan (the “2019 Wildfire Safety Plan”) with the CPUC. The 2019 Wildfire Safety 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 Safety Plan specifically addresses wildfire risk factors that occur most frequently and have potential to start or spread a fire. The 2019 Wildfire Safety 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;

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• 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 Public Safety Power Shutoff Program (PSPS) to include all transmission and distribution lines in Tier 2 and Tier 3 High Fire-Threat District (HFTD) 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 Public Safety Power Shutoff.

On February 12, February 14, and April 25, 2019, the Utility filed amendments to the 2019 Wildfire Safety Plan with the CPUC to correct inadvertent errors in the cost table attached to the 2019 Wildfire Safety Plan; refine language in the 2019 Wildfire Safety Plan; and modify certain 2019 Wildfire Safety 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 Safety 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 25^th 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 Safety 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 25^th amendment in Phase 2, as well as the process for independent evaluation of the Utility’s compliance with its 2019 plan. 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 Safety Plan recorded in the FRMMA and WPMA, which the Utility expects will be substantial.

OIR to Implement Public Utilities Code Section 451.2 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 customer harm threshold, 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 (the “Customer Harm Threshold”). 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 Customer Harm Threshold. 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 Customer Harm Threshold 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 Customer Harm Threshold 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 Customer Harm Threshold 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 Customer Harm Threshold 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 [Customer Harm Threshold], requires a utility to file a cost recovery application before the CHT [Customer Harm Threshold] will be determined, and erects ratepayer protection mechanisms as an extra-statutory hurdle for accessing the CHT [Customer Harm Threshold].” The Utility also argued that the CPUC should apply the Customer Harm Threshold methodology to costs related to the 2018 Camp fire.

The decision otherwise adopts a methodology to determine the Customer Harm Threshold 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 Customer Harm Threshold 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 Customer Harm Threshold. 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.

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.

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.

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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 needs assessment and distribution deferral opportunity reports will be filed and served on August 15, 2019.

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.  Phase one will focus on how to integrate climate change adaptation into the IOUs’ existing planning and operations to ensure utility safety and reliability.

The CPUC OIR will consider:

• how to define climate change adaptation for the IOUs;

• the climate-driven risks facing the IOUs;

• data, tools, resources, and guidance to instruct utilities on how to incorporate adaptation in their existing planning and operational processes; and

• strategies to address climate change in CPUC proceedings, including impacts on disadvantaged communities.

On October 10, 2018, the CPUC issued a scoping memo and established a procedural schedule. A final decision is expected in late 2019.

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;

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• 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 2 will take a more comprehensive look at de-energization practices, including mitigation, additional coordination across agencies, further refinements to findings in phase 1, re-energization practices, and other matters.

LEGISLATIVE AND REGULATORY INITIATIVES

Senate Bill 901

SB 901, signed into law on September 21, 2018, requires the CPUC to establish a Customer Harm Threshold (as defined herein), directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the Customer Harm Threshold. 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 Customer Harm Threshold. 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 Customer Harm Threshold 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 Customer Harm Threshold 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 Customer Harm Threshold in future applications under Section 451.2(a), but determines that a utility that has filed for relief under Chapter 11 cannot access the Customer Harm Threshold. 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 [Customer Harm Threshold], requires a utility to file a cost recovery application before the CHT [Customer Harm Threshold] will be determined, and erects ratepayer protection mechanisms as an extra-statutory hurdle for accessing the CHT [Customer Harm Threshold].” The Utility also argued that the CPUC should apply the Customer Harm Threshold 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.

AB 1054 provides that the Wildfire Fund will be established when Southern California Edison and San Diego Gas & Electric Company provide their initial contributions.

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;

• 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;

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• 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 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. The motion is expected to be heard on August 28, 2019, and objections and other responses are due August 21, 2019.

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 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. The Utility is currently developing a Chapter 11 plan of reorganization that would provide for the financing of such required contributions, but there can be no assurance that PG&E Corporation and the Utility will successfully develop, 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.

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.

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.  Comments on issues (e.g., the just and reasonableness of such a charge) are expected to be due in late August, 2019.  A final decision in the proceeding is expected in October 2019.

Power Charge Indifference Adjustment OIR

On October 11, 2018, the CPUC approved a decision to modify the PCIA methodology, which was developed after the 2001 California energy crisis, which adjusts how customers that leave the Utility’s bundled service for CCA or DA service pay for their share of the costs associated with long-term power purchase commitments made on their behalf. The decision better enables utilities to recover their above market costs from departing customers as compared to the previous methodology, by:

• adopting benchmark values used to set the PCIA rate that more closely resemble actual market prices for resource adequacy and renewable energy credits;

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• continuing to allow legacy utility-owned generation costs to be recovered from CCA customers;

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

• adding an annual true-up to the PCIA rate based on market sales.

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

On December 19, 2018, a prehearing conference was held to initiate phase two of the PCIA proceeding, to further develop proposals for future consideration by the CPUC. On February 1, 2019, the assigned commissioner issued a phase two scoping memo and ruling, which sets forth the category, issues, need for hearing, schedule, and other matters. As indicated in the scoping memo and ruling, Phase Two of this proceeding will primarily rely upon a stakeholder working group process to further develop a number of PCIA-related proposals for consideration by the CPUC. Working Group One, which is co-facilitated by the Utility and the California Community Choice Association, focuses on developing benchmarks and a true-up mechanism that reflect the current market value of brown power, resource adequacy, and renewable energy credits (Issues 1 to 7); and load forecasting, rate design mechanics, and customer bill presentation (Issues 8 to 12). Working Group Two focuses on CCA and DA prepayment options; and Working Group Three focuses on portfolio optimization and cost reduction, allocation and auctions, and whether the CPUC should consider new or modified shareholder responsibility for future portfolio mismanagement. The schedule included in the scoping memo and ruling indicates that the CPUC is expected to issue two decisions impactful to 2020 rates in late 2019 concerning benchmark true-ups and PCIA rate design mechanics. Proposed decisions addressing matters relevant to the prepayment working group and the portfolio optimization and cost reduction, and allocation and auction working group are anticipated in 2020.

On May 31, 2019, the Working Group One co-leads filed the Final Report on Issues 1 to 7. On July 1, 2019, the Working Group One co-leads filed the Final Report on Issues 8 to 12. On July 9, 2019, the assigned ALJ modified the procedural schedule allowing parties to file comments on the July 1 Final Report, and updated the date for parties to request evidentiary hearings on the Final Report of Working Group One on Issues 8 to 12.  Opening comments on issues 8 to 12 were filed on July 19, 2019, reply comments were filed on July 26, 2019, and motions for evidentiary hearings were due August 2, 2019. In accordance with the current schedule, a proposed decision on Working Group One issues 1 to 7 would be issued in September 2019, a proposed decision on Working Group One issues 8 to 12 would be issued in Fall 2019, and final decisions on each of those matters would be voted 30 days after those proposed decisions.

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.)

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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 six months ended June 30, 2019.

RECENT DEVELOPMENTS

New Chief Executive Officer and Board Members

On April 3, 2019, PG&E Corporation announced the appointment of 10 new directors to the Board of Directors of PG&E Corporation, with seven of the 10 then-incumbent directors stepping down, to be effective later that month. On April 22, 2019, Richard C. Kelly resigned from the Boards of PG&E Corporation and the Utility. Also, PG&E Corporation entered into a Settlement Agreement (the “Settlement Agreement”) with Blue Mountain Credit Alternatives Master Fund L.P. (together with its affiliates, “BlueMountain”), who had previously nominated candidates for election to PG&E Corporation’s Board of Directors. In connection with the execution and delivery of the Settlement Agreement, among other things, Frederick W. Buckman was appointed to the Boards of Directors of PG&E Corporation and the Utility and BlueMountain withdrew its nominations. The full text of the Settlement Agreement with BlueMountain is attached as an exhibit to PG&E Corporation’s Current Report on Form 8-K filed with the SEC on April 23, 2019. As of May 2, 2019, the Boards of Directors of PG&E Corporation and the Utility were each constituted with the following individuals: Richard R. Barrera, Jeffrey L. Bleich, Nora Mead Brownell, Frederick W. Buckman, Cheryl F. Campbell, Fred J. Fowler, William D. Johnson (Utility Board only), Michael J. Leffell, Kenneth Liang, Dominique Mielle, Meridee A. Moore, Eric D. Mullins, Kristine M. Schmidt and Alejandro D. Wolff.

In addition, William D. Johnson joined PG&E Corporation as its new Chief Executive Officer and President, effective May 2, 2019. In connection with the Settlement Agreement, PG&E Corporation agreed to engage Christopher A. Hart, a former chairman of the National Transportation Safety Board, to provide consulting services to Mr. Johnson regarding matters of safety.  

PG&E Corporation and the Utility expect that these leadership changes will have a significant impact on their operations and financial performance in the future.

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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 Chapter 11 Cases, the payment of pre-petition indebtedness is subject to compromise or other treatment under 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. ASC 852 requires pre-petition liabilities that are subject to compromise to be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts. The amounts currently classified as liabilities subject to compromise are preliminary and may be subject to future adjustments depending on the 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 if the Exclusive Filing Period or the Exclusive Solicitation Period is terminated; the ability to develop and 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 CPUC, and the FERC; increased costs related to the Chapter 11 Cases; the ability to obtain sufficient financing sources for ongoing and future operations; 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 Customer Harm Threshold OIR that excludes companies in Chapter 11 from accessing the Customer Harm Threshold, 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 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 future wildfires;

• 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 Safety Plan; and the cost of the program, 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;

• 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;

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• 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 items 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, and the Utility’s ongoing enhanced and accelerated inspection of its electric transmission and distribution assets;

• 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 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 timing and outcome of any CPUC action in connection with the Utility’s SmartMeter™ Upgrade cost-benefit analysis;

• 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.

Additionally, PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “News & Events: Events & Presentations” tab and links to certain documents and information related to the 2018 Camp fire, the 2017 Northern California wildfires, the 2015 Butte fire, and other updates which may be of interest to investors, at http://investor.pgecorp.com, under the “Wildfire Updates” tab, 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 this website is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC. PG&E Corporation and the Utility are providing the address to this website solely for the information of investors and do not intend the address to be an active link.

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 June 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 June 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 contingencies, see Notes 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 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 Safety 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. As of April 30, 2019, to the Utility’s knowledge, no parties have submitted comments to the court on the 2019 Wildfire Safety Plan.

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 5 years in light of the violation that has been adjudicated and whether the third-party 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’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’s Board of Directors assume responsibility for tracking progress of the 2019 Wildfire Safety 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.

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.

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.

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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 PG&E into gas and electric utilities (including, as one possibility, sale of the gas assets to a third party); establishing periodic review of PG&E’s certificate of convenience and necessity; modifying or eliminating PG&E Corporation’s holding company structure; and linking PG&E’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.”

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 Customer Harm Threshold 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 Customer Harm Threshold 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, PG&E Corporation and the Utility emerging from Chapter 11 by June 30, 2020 and making its initial contribution thereto) and 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. Failure to meet the eligibility conditions to access relief under the Wildfire Fund, including emerging from Chapter 11 by June 30, 2020 and making the 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.

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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. 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.

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. 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 or how it will be interpreted. 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.

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

During the quarter ended June 30, 2019, PG&E Corporation did not make any equity contributions to the Utility. Also during the quarter ended June 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 June 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 June 30, 2019, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

ITEM 6. EXHIBITS

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EXHIBIT INDEX

3.1	Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002, as amended by the Amendment dated June 21, 2019 [Conformed Copy]
10.1	Settlement Agreement, dated April 22, 2019, by and between PG&E Corporation and BlueMountain Capital Management, LLC (incorporated by reference to PG&E Corporation’s Form 8-K dated April 22, 2019 (File No. 1-12609), Exhibit 10.1)
10.2	Plan Support Agreement as to Plan Treatment of Public Entities’ Wildfire Claims dated as of June 18, 2019, by and among PG&E Corporation, Pacific Gas and Electric Company, the City of Clearlake, the City of Napa, the City of Santa Rosa, the County of Lake, the Lake County Sanitation District, the County of Mendocino, Napa County, the County of Nevada, the County of Sonoma, the Sonoma County Agricultural Preservation and Open Space District, the Sonoma County Community Development Commission, the Sonoma County Water Agency, the Sonoma Valley County Sanitation District and the County of Yuba (incorporated by reference to PG&E Corporation’s Form 8-K dated June 18, 2019 (File No. 1-12609), Exhibit 10.1)
10.3	Plan Support Agreement as to Plan Treatment of Public Entity’s Wildfire Claims dated as of June 18, 2019, by and among PG&E Corporation, Pacific Gas and Electric Company and the Town of Paradise (incorporated by reference to PG&E Corporation’s Form 8-K dated June 18, 2019 (File No. 1-12609), Exhibit 10.2)
10.4	Plan Support Agreement as to Plan Treatment of Public Entity’s Wildfire Claims dated as of June 18, 2019, by and among PG&E Corporation, Pacific Gas and Electric Company and the County of Butte (incorporated by reference to PG&E Corporation’s Form 8-K dated June 18, 2019 (File No. 1-12609), Exhibit 10.3)
10.5	Plan Support Agreement as to Plan Treatment of Public Entity’s Wildfire Claims dated as of June 18, 2019, by and among PG&E Corporation, Pacific Gas and Electric Company and the Paradise Recreation & Park District (incorporated by reference to PG&E Corporation’s Form 8-K dated June 18, 2019 (File No. 1-12609), Exhibit 10.4)
10.6	Plan Support Agreement as to Plan Treatment of Public Entity’s Wildfire Claims dated as of June 18, 2019, by and among PG&E Corporation, Pacific Gas and Electric Company and the County of Yuba (incorporated by reference to PG&E Corporation’s Form 8-K dated June 18, 2019 (File No. 1-12609), Exhibit 10.5)
10.7	Plan Support Agreement as to Plan Treatment of Public Entity’s Wildfire Claims dated as of June 18, 2019, by and among PG&E Corporation, Pacific Gas and Electric Company and the Calaveras County Water District (incorporated by reference to PG&E Corporation’s Form 8-K dated June 18, 2019 (File No. 1-12609), Exhibit 10.6)
*10.8	Form of Director and Officer Indemnification Agreement
*10.9	PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of June 3, 2019
*10.10	PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, as amended effective as of June 3, 2019
*10.11	Separation Agreement between Pacific Gas and Electric Company and Jesus Soto, Jr. dated June 3, 2019, revised as of June 5, 2019 and June 24, 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

116

101.DEF XBRL Taxonomy Extension Definition Linkbase Document

*Management contract or compensatory agreement.

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

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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: August 9, 2019

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EX-3.1

EXHIBIT 3.1

SUMMARY OF AMENDED AND RESTATED ARTICLES OF INCORPORATION

OF

PG&E CORPORATION

[EFFECTIVE AS OF JUNE 21, 2019]

FIRST: The name of the Corporation shall be

PG&E CORPORATION

SECOND: The purpose of the Corporation is to engage in any lawful act or activity for which a corporation may be organized under the General Corporation law of California other than the banking business, the trust company business or the practice of a profession permitted to be incorporated by the California Corporations Code.

THIRD:

I.     The Board of Directors of the Corporation shall consist of such number of directors, not less than eight (8) nor more than fifteen (15), as shall be prescribed in the Bylaws.

II.    The Board of Directors by a vote of two-thirds of the whole Board may appoint from the directors an Executive Committee, which Committee may exercise such powers as may lawfully be conferred upon it by the Bylaws of the Corporation. Such Committee may prescribe rules for its own government and its meetings may be held at such places within or without California as said Committee may determine or authorize.

FOURTH: No shareholder may cumulate votes in the election of directors. This Article FOURTH shall become effective only when the Corporation shall have become a “listed corporation” within the meaning of Section 301.5 of the California Corporations Code.

FIFTH: The liability of the directors of the Corporation for monetary damages shall be eliminated to the fullest extent permissible under California law.

SIXTH: The Corporation is authorized to provide indemnification of agents (as defined in Section 317 of the California Corporations Code) through bylaws, resolutions, agreements with agents, vote of shareholders or disinterested directors, or otherwise, in excess of the indemnification otherwise permitted by Section 317 of the California Corporations Code, subject only to the applicable limits set forth in Section 204 of the California Corporations Code

SEVENTH:

I.    The Corporation is authorized to issue two classes of shares, to be designated respectively Preferred Stock (“Preferred Stock”) and Common Stock (“Common “Stock”). The total number of shares of capital stock that the Corporation is authorized to issue is 885,000,000, of which 85,000,000 shall be Preferred Stock and 800,000,000 shall be Common Stock.

II.    The Preferred Stock may be issued from time to time in one or more series. The Board of Directors of the Corporation is expressly authorized to provide for the issue of all or any of the shares of the Preferred Stock in one or more series, and to fix the designation and number of shares and to determine or alter for each such series, such voting powers, full or limited, or no voting powers, and such designations, preferences and relative, participating, optional or other rights and such qualifications, limitations or restrictions thereof, as shall be stated and expressed in the resolution or resolutions adopted by the Board of Directors providing for the issue of such shares and as may be permitted by the General Corporation Law of California. The Board of Directors is also expressly authorized to increase or decrease (but not below the number of shares of such series then outstanding) the number of shares of any series subsequent to the issue of shares of that series. If the number of shares of any such series shall be so decreased, the shares constituting such decrease shall resume the status that they had prior to the adoption of the resolution originally fixing the number of shares of such series.

EIGHTH:

The directors of the Corporation, when evaluating any proposal or offer which would involve (i) a merger or consolidation of the Corporation or any of its subsidiaries with another person, (ii) a sale of all or substantially all of the assets of the Corporation or any of its subsidiaries, (iii) a tender offer or exchange offer for any capital stock of the Corporation or any of its subsidiaries, or (iv) any similar transactions, shall give due consideration to all factors they may consider relevant. Such factors may include, without limitation, (a) the adequacy, both in amount and form, of the consideration offered in relation not only to the current market price of the Corporation’s outstanding securities, but also the current value of the Corporation in a freely negotiated transaction with other potential acquirers and the Board’s estimate of the Corporation’s future value (including the unrealized value of its properties, assets and prospects) as an independent going concern, (b) the financial and managerial resources and future prospects of the acquirer, and (c) the legal, economic, environmental, regulatory and social effects of the proposed transaction on the Corporation’s and its subsidiaries’ employees, customers, suppliers and other affected persons and entities and on the communities and geographic areas in which the Corporation and its subsidiaries operate, provide utility service or are located, and in particular, the effect on the Corporation’s and its subsidiaries’ ability to safely and reliable meet any public utility obligations they may have at reasonable rates.

EX-10.8

EXHIBIT 10.08

INDEMNIFICATION AGREEMENT

This Indemnification Agreement is dated as of [] (this “Agreement”) and is between PG&E Corporation, a California corporation (the “Corporation”), Pacific Gas and Electric Company, a California Corporation (the “Utility” and, together with the Corporation, the “Company”), and [] (“Indemnitee”).

Background

The Company believes that in order to attract and retain highly competent persons to serve as directors or in other capacities, including as officers, it must provide such persons with adequate protection through indemnification against the risks of claims and actions against them arising out of their services to and activities on behalf of the Company.

The Company desires and has requested Indemnitee to serve, or to continue to serve, as a director or officer of the Company and, in order to induce Indemnitee to serve, or to continue to serve, as a director or officer of the Company, the Company is willing to grant Indemnitee the indemnification provided for herein. Indemnitee is willing to so serve, or to continue to serve, on the basis that such indemnification be provided. The indemnification provided herein is a supplement to and in furtherance of any rights granted under each of the Corporation’s and the Utility’s respective Restated Articles of Incorporation (the “Articles of Incorporation”) and Bylaws (the “Bylaws”) and shall not be deemed to be a substitute therefor nor to diminish or abrogate any rights of Indemnitee thereunder.

The parties by this Agreement desire to set forth their agreement regarding indemnification and the advancement of expenses.

In consideration of Indemnitee’s service to the Company and the covenants and agreements set forth below, and for other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the parties hereto, intending to be legally bound, hereby agree as follows:

Section 1.Indemnification. To the fullest extent permitted by the General Corporation Law of the State of California (the “CGCL”), subject to the limitations set forth in Section 204(a)(10)-(11) of the CGCL:

(a)The Company shall indemnify Indemnitee if Indemnitee was or is a party to, is threatened to be made a party to, or is otherwise involved in, as a witness or otherwise, any threatened, pending or completed action, suit or proceeding (brought in the right of the Company or otherwise), whether civil, criminal, administrative or investigative and whether formal or informal, including any and all appeals, by reason of the fact that Indemnitee is or was or has agreed to serve as a director or officer of the Company, or while serving as a director or officer of the Company, is or was serving or has agreed to serve at the request of the Company as a director, officer, employee or agent (which, for purposes hereof, shall include a trustee, fiduciary, partner or manager or similar capacity) of another corporation, limited liability company, partnership, joint venture, trust, employee benefit plan or other enterprise, or by reason of any action alleged to have been taken or omitted by Indemnitee in any such capacity.

(b)Subject to Section 6, the indemnification provided by this Section 1 shall be from and against all loss and liability suffered and expenses (including attorneys’ fees, costs and expenses), judgments, fines and amounts actually and reasonably incurred by or on behalf of Indemnitee in connection with such action, suit or proceeding, including any appeals (collectively, “Losses”).

Section 2.Advancement of Expenses. To the fullest extent permitted by the CGCL, but subject to the terms of this Agreement and following notice pursuant to Section 3(a) below, expenses (including attorneys’ fees, costs and expenses) incurred by Indemnitee in appearing at, participating in or defending, or otherwise arising out of or related to, any action, suit or proceeding described in Section 1(a) shall be paid by the Company in advance of the final disposition of such action, suit or proceeding, or in connection with any action, suit or proceeding brought to establish or enforce a right to indemnification or advancement of expenses pursuant to Section 3 (an “advancement of expenses”), within 20 days after receipt by the Company of a statement or statements from Indemnitee requesting such advancement of expenses from time to time. Indemnitee hereby undertakes to repay any amounts so advanced (without interest) to the extent that it is ultimately determined by final judicial decision from which there is no further right to appeal (a “final adjudication”) that such Indemnitee is not entitled to be indemnified or entitled to advancement of expenses under this Agreement. No other form of undertaking shall be required of Indemnitee other than the execution of this Agreement. This Section 2 shall be subject to Section 3(b) and shall not apply to any claim made by Indemnitee for which indemnity is excluded pursuant to Section 6.

Section 3.Procedure for Indemnification; Notification and Defense of Claim.

(a)Promptly after receipt by Indemnitee of notice of the commencement of any action, suit or proceeding, Indemnitee shall, if any indemnification, advancement or other claim in respect thereof is to be sought from or made against the Company hereunder, notify the Company in writing of the commencement thereof. The failure to promptly notify the Company of the commencement of any action, suit or proceeding, or of Indemnitee’s request for indemnification, advancement or other claims shall not relieve the Company from any liability that it may have to Indemnitee hereunder and shall not constitute a waiver or release by Indemnitee of any rights hereunder or otherwise, except to the extent the Company is actually and materially prejudiced in its defense of such action, suit or proceeding as a result of such failure. To submit a request for indemnification under this Agreement, Indemnitee shall submit to the Company a written request therefor; provided that any request for such indemnification may not be made until after a final adjudication of such action, suit or proceeding. Any notice by Indemnitee under this Section 3 should include such documentation and information as is reasonably available to Indemnitee and is reasonably necessary to enable the Company to determine whether and to what extent Indemnitee is entitled to indemnification.

(b)With respect to any action, suit or proceeding of which the Company is so notified as provided in this Agreement, the Company shall, subject to the last two sentences of this Section 3(b), be entitled to assume the defense of such action, suit or proceeding, with counsel reasonably acceptable to Indemnitee, upon the delivery to Indemnitee of written notice of its election to do so. After delivery of such notice, approval of such counsel by Indemnitee and the retention of such counsel by the Company, the Company will not be liable to Indemnitee under this Agreement for any subsequently incurred fees of separate counsel engaged by Indemnitee with respect to the same action, suit or proceeding unless the employment of separate counsel by Indemnitee has been previously authorized in writing by the Company, which authorization will not be unreasonably withheld or delayed. Notwithstanding the foregoing, if Indemnitee, based on the advice of his or her counsel, shall have reasonably concluded (with written notice being given to the Company setting forth the basis for such conclusion) that, in the conduct of any such defense, there is an actual or potential conflict of interest or position (other than such potential conflicts that are objectively immaterial or remote) between the Company and Indemnitee with respect to a significant issue, then the Company will not be entitled, without the written consent of Indemnitee, to assume such defense. In addition, the Company will not be entitled, without the written consent of Indemnitee, to assume the defense of any claim brought by or in the right of the Company.

(c)To the fullest extent permitted by the CGCL, the Company’s assumption of the defense of an action, suit or proceeding in accordance with paragraph 3(b) will constitute an irrevocable acknowledgement by the Company that any Losses suffered by Indemnitee paid in settlement by or for the account of Indemnitee incurred in connection therewith are indemnifiable by the Company under Section 1 of this Agreement.

(d)The determination whether to grant Indemnitee’s indemnification request shall be made promptly and in any event within 30 days following the Company’s receipt of a request for indemnification in accordance with Section 3(a). If the Company determines that Indemnitee is entitled to such indemnification or, as contemplated by Section 3(c) the Company has acknowledged such entitlement, the Company will make payment to Indemnitee of the indemnifiable amount within such 30 day period. If the Company is not deemed to have so acknowledged such entitlement or the Company’s determination of whether to grant Indemnitee’s indemnification request shall not have been made within such 30‑day period, the requisite determination of entitlement to indemnification shall, subject to Section 6, nonetheless be deemed to have been made and Indemnitee shall be entitled to such indemnification, absent (i) an intentional misstatement by Indemnitee of a material fact, or an intentional omission of a material fact necessary to make Indemnitee’s statement not misleading, in connection with the request for indemnification, or (ii) a prohibition of such indemnification under the CGCL.

(e)In the event that (i) the Company determines in accordance with this Section 3 that Indemnitee is not entitled to indemnification under this Agreement, (ii) the Company denies a request for indemnification, in whole or in part, or fails to respond or make a determination of entitlement to indemnification within 30 days following receipt of a request for indemnification as described above, (iii) payment of indemnification is not made within such 30‑day period, (iv) advancement of expenses is not timely made in accordance with Section 2 or (v) the Company or any other person takes or threatens to take any action to declare this Agreement void or unenforceable, or institutes any litigation or other action or proceeding designed to deny, or to recover from, Indemnitee the benefits provided or intended to be provided to Indemnitee hereunder, Indemnitee shall be entitled to an adjudication in any court of competent jurisdiction of his or her entitlement to such indemnification or advancement of expenses, as applicable. Indemnitee’s expenses (including attorneys’ fees, costs and expenses) incurred in connection with successfully establishing Indemnitee’s right to indemnification or advancement of expenses, in whole or in part, in any such proceeding or otherwise shall also be indemnified by the Company to the fullest extent permitted by the CGCL.

(f)Indemnitee shall be presumed to be entitled to indemnification and advancement of expenses under this Agreement upon submission of a request therefor in accordance with Section 2 or Section 3, as the case may be. The Company shall have the burden of proof in overcoming such presumption, and such presumption shall be used as a basis for a determination of entitlement to indemnification and advancement of expenses unless the Company overcomes such presumption by clear and convincing evidence. For purposes of this Agreement, to the fullest extent permitted by the CGCL, Indemnitee shall be deemed to have acted in good faith if Indemnitee’s action is based on the records or books of account of the Company, including financial statements, or on information supplied to Indemnitee by the officers, employees or committees of the Board of Directors of the Company (the “Board of Directors”), or on the advice of legal counsel or other advisors (including financial advisors and accountants) for the Company or on information or records given in reports made to the Company by an independent certified public accountant or by an appraiser or other expert or advisor selected by the Company, and the knowledge and/or actions, or failure to act, of any director, officer, agent or employee of the Company or relevant enterprises will not be imputed to Indemnitee in a manner that limits or otherwise adversely affects Indemnitee’s rights hereunder.

Section 4.Insurance and Subrogation.

(a)     The Company hereby covenants and agrees that, so long as Indemnitee shall be subject to any possible action, suit or proceeding by reason of the fact that Indemnitee is or was or has agreed to serve as a director or officer of the Company, or while serving as a director or officer of the Company, is or was serving or has agreed to serve at the request of the Company as a director, officer, employee or agent (which, for purposes hereof, shall include a trustee, fiduciary, partner or manager or similar capacity) of another corporation, limited liability company, partnership, joint venture, trust, employee benefit plan or other enterprise, the Company, subject to Section 4(b), shall promptly obtain and maintain in full force and effect directors’ and officers’ liability insurance (“D&O Insurance”) in reasonable amounts from established and reputable insurers, including without limitation, under any captive insurance or self-insurance program, as more fully described below.

(b)     Notwithstanding any other provisions of this Agreement to the contrary, the Company shall have no obligation to obtain or maintain D&O Insurance if the Company determines in good faith that: (i) such insurance is not reasonably available; (ii) the premium costs for such insurance are disproportionate to the amount of coverage provided; (iii) the coverage provided by such insurance is limited by terms, conditions and/or exclusions so as to provide an insufficient benefit; (iv) the Company is to be acquired or otherwise subject to a change in control and a tail policy of reasonable terms and duration is purchased for actual or alleged pre‑closing acts or omissions by Indemnitee; or (v) the Company is to be acquired or otherwise subject to a change in control and D&O Insurance will be maintained that covers actual or alleged pre‑closing acts and omissions by Indemnitee.

(c)     In all policies of D&O Insurance, Indemnitee shall qualify as an insured in such a manner as to provide Indemnitee the same rights and benefits as are accorded to the most favorably insured (i) of the Company’s independent directors (as defined by the insurer) if Indemnitee is such an independent director; (ii) of the Company’s non‑independent directors if Indemnitee is not an independent director; or (iii) of the Company’s officers if Indemnitee is an officer of the Company. If the Company has D&O Insurance in effect at the time the Company receives from Indemnitee any notice of the commencement of an action, suit or proceeding, the Company shall give prompt notice of the commencement of such action, suit or proceeding to the insurers in accordance with the procedures set forth in the policy. The Company shall thereafter take all necessary or desirable action to cause such insurers to pay, on behalf of Indemnitee, all amounts payable as a result of such proceeding in accordance with the terms of such policy.

(d)     In the event of any payment by the Company under this Agreement, the Company shall be subrogated to the extent of such payment to all of the rights of recovery of Indemnitee with respect to any insurance policy. Indemnitee shall execute all papers required and take all action necessary to secure such rights, including execution of such documents as are necessary to enable the Company to bring suit to enforce such rights in accordance with the terms of such insurance policy. The Company shall pay or reimburse all expenses actually and reasonably incurred by Indemnitee in connection with such subrogation.

(e)     The Company shall not be liable under this Agreement to make any payment of amounts otherwise indemnifiable hereunder (including, but not limited to, judgments, fines and amounts actually and reasonably incurred) if and to the extent that Indemnitee has otherwise actually received such payment under this Agreement or any insurance policy, contract, agreement or otherwise.

Section 5.Certain Definitions. For purposes of this Agreement, the following definitions shall apply:

(a)The term “action, suit or proceeding” shall be broadly construed and shall include, without limitation, the investigation, preparation, prosecution, defense, settlement, arbitration and appeal of, and the giving of testimony in, any threatened, pending or completed claim, counterclaim, cross claim, action, suit, arbitration, alternative dispute mechanism or any proceeding.

(b)The term “by reason of the fact that Indemnitee is or was or has agreed to serve as a director, officer, employee or agent of the Company, or while serving as a director or officer of the Company, is or was serving or has agreed to serve at the request of the Company as a director, officer, employee or agent (which, for purposes hereof, shall include a trustee, fiduciary, partner or manager or similar capacity) of another corporation, limited liability company, partnership, joint venture, trust, employee benefit plan or other enterprise” shall be broadly construed and shall include, without limitation, any actual or alleged act or omission to act.

(c)The term “expenses” shall be broadly construed and shall include, without limitation, all direct and indirect costs of any type or nature whatsoever (including, without limitation, all attorneys’ fees, costs and expenses and related disbursements, appeal bonds, other out‑of‑pocket costs, retainers, court costs, transcript costs, fees of experts and other professionals, witness fees, travel expenses, duplicating costs, printing and binding costs, telephone charges, postage, delivery service fees, any federal, state, local or foreign taxes imposed on Indemnitee as a result of the actual or deemed receipt of any payments under this Agreement, ERISA excise taxes and penalties and reasonable compensation for time spent by Indemnitee for which Indemnitee is not otherwise compensated by the Company or any third party), actually and reasonably incurred by Indemnitee in connection with either the investigation, defense or appeal of an action, suit or proceeding or establishing or enforcing a right to indemnification under this Agreement or otherwise incurred in connection with a claim that is indemnifiable hereunder.

(d)The term “judgments, fines and amounts actually and reasonably incurred” shall be broadly construed and shall include, without limitation, all direct and indirect payments of any type or nature whatsoever, as well as any penalties or excise taxes assessed on a person with respect to an employee benefit plan.

Section 6.Limitation on Indemnification. Notwithstanding any provision of this Agreement to the contrary, the Company shall not be obligated pursuant to this Agreement:

(a)Proceedings Initiated by Indemnitee. To indemnify or advance expenses to Indemnitee with respect to an action, suit or proceeding (or part thereof) initiated voluntarily by Indemnitee, except with respect to any compulsory counterclaim brought by Indemnitee, unless (i) such indemnification is expressly required to be made by law, (ii) such action, suit or proceeding (or part thereof) was authorized or consented to by the Board of Directors, (iii) such indemnification is provided by the Company, in its sole discretion, pursuant to the powers vested in the Company under the CGCL or (iv) such action, suit or proceeding is brought to establish or enforce a right to indemnification or advancement of expenses under this Agreement or any other statute or law or otherwise as required under Section 317 of the CGCL in advance of a final determination.

(b)Lack of Good Faith. To indemnify Indemnitee for any expenses incurred by Indemnitee with respect to any action, suit or proceeding instituted by Indemnitee to enforce or interpret this Agreement, if a court of competent jurisdiction determines that each of the material assertions made by Indemnitee in such action, suit or proceeding was not made in good faith or was frivolous.

(c)Section 16(b) and Clawback Matters. To indemnify Indemnitee for (i) an accounting of profits made from the purchase and sale (or sale and purchase) by Indemnitee of securities of the Company within the meaning of Section 16(b) of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), or similar provisions of state statutory law or common law, (ii) any reimbursement of the Company by the Indemnitee of any bonus or other incentive-based or equity-based compensation or of any profits realized by the Indemnitee from the sale of securities of the Company, as required in each case under the Exchange Act (including any such reimbursements that arise from an accounting restatement of the Company pursuant to Section 304 of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), or the payment to the Company of profits arising from the purchase and sale by Indemnitee of securities in violation of Section 306 of the Sarbanes-Oxley Act) or (iii) any reimbursement of the Company by Indemnitee of any compensation pursuant to any compensation recoupment or clawback policy adopted by the Board of Directors or the compensation committee of the Board of Directors, including but not limited to any such policy adopted to comply with stock exchange listing requirements implementing Section 10D of the Exchange Act.

(d)Prohibited by Law. To indemnify or advance expenses to Indemnitee in any circumstance where such indemnification has been determined to be prohibited by law by a final (not interlocutory) judgment or other adjudication

of a court or arbitration or administrative body of competent jurisdiction as to which there is no further right or option of appeal or the time within which an appeal must be filed has expired without such filing.

Section 7.Change in Control.

(a)The Company agrees that if there is a change in control of the Company, then with respect to all matters thereafter arising concerning the rights of Indemnitee to indemnification and advancement of expenses under this Agreement, any other agreement or the Company’s Articles of Incorporation or Bylaws now or hereafter in effect, the Company shall seek legal advice only from independent counsel selected by Indemnitee and approved by the Company (which approval shall not be unreasonably withheld). In addition, upon written request by Indemnitee for indemnification pursuant to Section 3(a), a determination, if required by the CGCL, with respect to Indemnitee’s entitlement thereto shall be made by such independent counsel in a written opinion to the Board of Directors, a copy of which shall be delivered to Indemnitee. The Company agrees to pay the reasonable fees of the independent counsel referred to above and to indemnify fully such counsel against any and all expenses (including attorneys’ fees, costs and expenses), claims, liabilities and damages arising out of or relating to this Agreement or its engagement pursuant hereto.

(b)For purposes of this Section 7, the following definitions shall apply:

(i)A “change in control” shall be deemed to occur upon the earliest to occur after the date of this Agreement of any of the following: (A) any person or group, within the meaning of Section 13(d)(3) of the Exchange Act, obtains ownership, directly or indirectly, of (x) more than 50% of the total voting power of the outstanding capital stock of the Company or applicable successor entity (including any securities convertible into, or exercisable or exchangeable for such capital stock) or (y) all or substantially all of the assets of the Company and its Subsidiaries on a consolidated basis; (B) during any period of two consecutive years (not including any period prior to the execution of this Agreement), individuals who at the beginning of such period constitute the Board of Directors, and any new director (other than a director designated by a person who has entered into an agreement with the Company to effect a transaction described in Sections 7(b)(i)(A), 7(b)(i)(C) or 7(b)(i)(D) or a director whose initial nomination for, or assumption of office as, a member of the Board of Directors occurs as a result of an actual or threatened solicitation of proxies or consents for election or removal of one or more directors by any person or group other than a solicitation for the election of one or more directors by or on behalf of the Board of Directors) whose election by the Board of the Directors or nomination for election by the Company’s stockholders was approved by a vote of at least two‑thirds of the directors then still in office who either were directors at the beginning of the period or whose election or nomination for election was previously so approved, cease for any reason to constitute at least a majority of the members of the Board of Directors; (C) the effective date of a merger or consolidation of the Company with any other entity, other than a merger or consolidation that would result in the voting securities of the Company outstanding immediately prior to such merger or consolidation continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity) at least 50% of the combined voting power of the voting securities of the surviving entity outstanding immediately after such merger or consolidation and with the power to elect at least a majority of the board of directors or other governing body of such surviving entity; and(D) the approval by the stockholders of the Company of a complete liquidation of the Company or an agreement for the sale or disposition by the Company of all or substantially all of the Company’s assets. For purposes of this Section 7(b)(i) only, “person” shall have the meaning as set forth in Sections 13(d) and 14(d) of the Exchange Act; provided, however, that “person” shall exclude (a) the Company, (b) any trustee or other fiduciary holding securities under an employee benefit plan of the Company and (c) any corporation owned, directly or indirectly, by the stockholders of the Company in substantially the same proportions as their ownership of stock of the Company.

(ii)The term “independent counsel” means a law firm, or a member of a law firm, that is experienced in matters of corporation law and neither presently is, nor in the past five years has been, retained to represent: (A) the Company or Indemnitee in any matter material to either such party or (B) any other party to the action, suit or proceeding giving rise to a claim for indemnification hereunder. Notwithstanding the foregoing, the term “independent counsel” shall not include any person who, under the applicable standards of professional conduct then prevailing, would have a conflict of interest in representing either the Company or Indemnitee in an action to determine Indemnitee’s rights under this Agreement.

(iii)The term “Subsidiary” means, with respect to the Company (or an applicable successor entity), any corporation, partnership, limited liability company, association or other business entity of which (i) if a corporation, a majority of the total voting power of shares of stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing persons or bodies thereof is at the time owned or controlled, directly or indirectly, by the Company or one or more of the other Subsidiaries of the Company or a combination thereof, or (ii) if a partnership, limited liability company, trust, association or other business entity, a majority of the partnership, limited liability company or

other similar ownership interest thereof is at the time owned or controlled, directly or indirectly, by the Company or one or more of the other Subsidiaries of the Company or a combination thereof. For purposes hereof, the Company or its applicable Subsidiary shall be deemed to have a majority ownership interest in a partnership, limited liability company, association or other business entity if the Company or such applicable Subsidiary shall be allocated a majority of partnership, limited liability company, association or other business entity gains or losses or shall be or control the managing director, managing member, manager or general partner of such partnership, limited liability company, association or other business entity.

Section 8.Certain Settlement Provisions. The Company shall have no obligation to indemnify Indemnitee under this Agreement for any amounts paid in settlement of any action, suit or proceeding without the Company’s prior written consent. The Company shall not, without Indemnitee’s prior written consent, settle any action, suit or proceeding in any manner that would attribute to Indemnitee any admission of liability or that would impose any fine or other obligation or restriction on Indemnitee. Neither the Company nor Indemnitee will unreasonably withhold his, her or its consent to any proposed settlement.

Section 9.Savings Clause. If any provision or provisions (or portion thereof) of this Agreement shall be invalidated on any ground by any court of competent jurisdiction, then the Company shall nevertheless indemnify Indemnitee if Indemnitee was or is a party to, is threatened to be made a party to, or is otherwise involved in, as a witness or otherwise, any threatened, pending or completed action, suit or proceeding (brought in the right of the Company or otherwise), whether civil, criminal, administrative or investigative and whether formal or informal, including any and all appeals, by reason of the fact that Indemnitee is or was or has agreed to serve as a director, officer, employee or agent of the Company, or while serving as a director or officer of the Company, is or was serving or has agreed to serve at the request of the Company as a director, officer, employee or agent (which, for purposes hereof, shall include a trustee, fiduciary, partner or manager or similar capacity) of another corporation, limited liability company, partnership, joint venture, trust, employee benefit plan or other enterprise, or by reason of any action alleged to have been taken or omitted by Indemnitee in any such capacity, from and against all Losses suffered by, or incurred by or on behalf of, Indemnitee in connection with such action, suit or proceeding, including any appeals, to the fullest extent permitted by any applicable portion of this Agreement that shall not have been invalidated.

Section 10.Contribution. In order to provide for just and equitable contribution in circumstances in which the indemnification provided for herein is held by a court of competent jurisdiction to be unavailable to Indemnitee in whole or in part, it is agreed that, in such event, the Company shall, to the fullest extent permitted by law, contribute to the payment of all Losses suffered by, or incurred by or on behalf of, Indemnitee in connection with any action, suit or proceeding, including any appeals, in an amount that is just and equitable in the circumstances in order to reflect (i) the relative benefits received by the Company and Indemnitee as a result of the event(s) and/or transaction(s) giving cause to such actions, suit or proceeding; and/or (ii) the relative fault of the Company (and its directors, officers, employees and agents) and Indemnitee in connection with such event(s) and/or transaction(s); provided that, without limiting the generality of the foregoing, such contribution shall not be required where such holding by the court is due to any limitation on indemnification set forth in Section 4(e), Section 6 or Section 8.

Section 11.Form and Delivery of Communications. All notices, requests, demands and other communications under this Agreement shall be in writing and shall be deemed to have been duly given if (a) delivered by hand, upon receipt by the party to whom said notice or other communication shall have been directed, (b) mailed by certified or registered mail with postage prepaid, on the third business day after the date on which it is so mailed, (c) mailed by reputable overnight courier, one day after deposit with such courier and with written verification of receipt, or (d) sent by email or facsimile transmission, with receipt of oral confirmation that such transmission has been received. Notice to the Company shall be directed to Janet Loduca, email: []@pge.com,facsimile: (415)‑ [], confirmation number: (415)‑ [] and Linda Cheng, email: []@pge.com, facsimile: (415)‑ [], confirmation number: (415)‑ []. Notice to Indemnitee shall be directed to the email address and telephone number set forth under the signature of the Indemnitee below.

Section 12.Nonexclusivity. The provisions for indemnification to or the advancement of expenses and costs to Indemnitee under this Agreement shall not limit or restrict in any way the power of the Company to indemnify or advance expenses to Indemnitee in any other way permitted by law or be deemed exclusive of, or invalidate, any right to which any indemnitee seeking indemnification or advancement of expenses may be entitled under any law, the Company’s Articles of Incorporation or Bylaws, other agreements or arrangements, vote of stockholders or disinterested directors or otherwise, both as to action in Indemnitee’s capacity as an officer, director, employee or agent of the Company and as to action in any other capacity. Indemnitee’s rights hereunder shall inure to the benefit of the heirs, executors and administrators of Indemnitee. No amendment or alteration of the Company’s Articles of Incorporation or Bylaws or any other agreement shall adversely affect the rights provided to Indemnitee under this Agreement.

Section 13.Defenses. In (i) any action, suit or proceeding brought by Indemnitee to enforce a right to indemnification hereunder (but not in an action, suit or proceeding brought by Indemnitee to enforce a right to an advancement

of expenses) it shall be a defense that, and (ii) any action, suit or proceeding brought by the Company to recover an advancement of expenses pursuant to the terms of an undertaking by Indemnitee pursuant to Section 2, the Company shall be entitled to recover such expenses upon a final adjudication that, Indemnitee has not met any applicable standard for indemnification set forth in the CGCL. Neither the failure of the Company (including its directors who are not parties to such action, a committee of such directors, independent legal counsel or the Company’s stockholders) to have made a determination prior to the commencement of such suit that indemnification of Indemnitee is proper in the circumstances because Indemnitee has met the applicable standard of conduct set forth in the CGCL, nor an actual determination by the Company (including its directors who are not parties to such action, a committee of such directors, independent legal counsel or the Company’s stockholders) that Indemnitee has not met such applicable standard of conduct, shall create a presumption that Indemnitee has not met the applicable standard of conduct or, in the case of such a suit brought by Indemnitee, be a defense to such suit.

Section 14.No Construction as Employment Agreement. Nothing contained herein shall be construed as giving Indemnitee any right to be retained as a director or officer of the Company or in the employ of the Company or any other entity. For the avoidance of doubt, the indemnification and advancement of expenses provided under this Agreement shall continue as to Indemnitee even though he or she may have ceased to be a director, officer, employee or agent of the Company.

Section 15.Interpretation of Agreement. It is understood that the parties hereto intend this Agreement to be interpreted and enforced so as to provide, in each instance, indemnification and advancement of expenses to Indemnitee to the fullest extent permitted by the CGCL, as the same exists or may hereafter be amended (but, in the case of any such amendment, only to the extent that such amendment permits the Company to provide broader indemnification rights than the CGCL permitted the Company to provide prior to such amendment). Whenever the words “include,” “includes,” or “including” are used in this Agreement, they shall be deemed to be followed by the words “without limitation,” whether or not they are in fact followed by those words or words of like import.

Section 16.Entire Agreement. This Agreement and the documents expressly referred to herein constitute the entire agreement between the parties hereto with respect to the matters covered hereby, and any other prior or contemporaneous oral or written understandings or agreements with respect to the matters covered hereby are expressly superseded by this Agreement.

Section 17.Modification and Waiver. No supplement, modification, waiver or amendment of this Agreement shall be binding unless executed in writing by the parties hereto. No waiver of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provision hereof (whether or not similar) nor shall such waiver constitute a continuing waiver. For the avoidance of doubt, (a) this Agreement may not be modified or terminated by the Company without Indemnitee’s prior written consent; (b) no amendment, alteration or interpretation of the Company’s Articles of Incorporation or Bylaws or any other agreement or arrangement shall limit or otherwise adversely affect the rights provided to Indemnitee under this Agreement and (c) a right to indemnification or to advancement of expenses arising under a provision of the Company’s Articles of Incorporation or Bylaws or this Agreement shall not be eliminated or impaired by an amendment to such provision after the occurrence of the act or omission that is the subject of the action, suit or proceeding for which indemnification or advancement of expenses is sought.

Section 18.Successor and Assigns. All of the terms and provisions of this Agreement shall be binding upon, shall inure to the benefit of and shall be enforceable by the parties hereto and their respective successors, assigns, heirs, executors, administrators and legal representatives. The Company shall require and cause any direct or indirect successor (whether by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets of the Company, by written agreement in form and substance reasonably satisfactory to Indemnitee, expressly to assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform if no such succession had taken place.

Section 19.Service of Process and Venue. The Company hereby irrevocably and unconditionally (a) agrees that any action or proceeding arising out of or in connection with this Agreement shall be brought in the courts of the State of California (the “California Courts”), (b) consents to submit to the exclusive jurisdiction of the California Courts for purposes of any action or proceeding arising out of or in connection with this Agreement, (c) waives any objection to the laying of venue of any such action or proceeding in the California Courts and (d) waives, and agrees not to plead or to make, any claim that any such action or proceeding brought in the California Courts has been brought in an improper or inconvenient forum.

Section 20.Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State of California. If, notwithstanding the foregoing, a court of competent jurisdiction shall make a final determination that the provisions of the law of any state other than California govern indemnification by the Company of Indemnitee, then the

indemnification provided under this Agreement shall in all instances be enforceable to the fullest extent permitted under such law, notwithstanding any provision of this Agreement to the contrary.

Section 21.Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed to be an original and all of which together shall be deemed to be one and the same instrument, notwithstanding that both parties are not signatories to the original or same counterpart.

Section 22.Headings and Section References. The section and subsection headings contained in this Agreement are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement. Section references are to this Agreement unless otherwise specified.

Section 23.Effectiveness of Agreement. This Agreement shall be effective as of the date set forth on the first page and shall apply to acts or omissions of Indemnitee which occurred prior to such date if Indemnitee was serving as a director, officer, trustee, general partner, managing member, fiduciary, board of directors’ committee member, employee or agent of the Company or of any Subsidiary or any other corporation, limited liability company, partnership, joint venture, trust, employee benefit plan or other enterprise of which Indemnitee is or was serving at the request of the Company as a director, officer, trustee, general partner, managing member, fiduciary, board of directors’ committee member, employee or agent.

[Signature Page Follows]

This Indemnification Agreement has been duly executed and delivered to be effective as of the date first written above.

PG&E CORPORATION
By:
	Name:
	Title:

PACIFIC GAS AND ELECTRIC COMPANY
By:
	Name:
	Title:

INDEMNITEE:

Name:

Email:

Phone:

EX-10.9

EXHIBIT 10.9

SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN

OF

PG&E CORPORATION

(As Amended Effective as of June 3, 2019)

______________________________________________

This is the controlling and definitive statement of the Supplemental Executive Retirement Plan (“PLAN”)    Words in all capitals are defined in Article I. for ELIGIBLE EMPLOYEES of PG&E Corporation (“CORPORATION”), Pacific Gas and Electric Company (“COMPANY”) and such other companies, affiliates, subsidiaries, or associations as the BOARD OF DIRECTORS may designate from time to time. The PLAN is the successor plan to the Supplemental Executive Retirement Plan of the COMPANY. The PLAN as contained herein was first adopted effective January 1, 2005.

No new participants can become eligible to accrue benefits under the PLAN on or after January 1, 2013, and existing participants in the PLAN as of January 1, 2013 shall cease to accrue further benefits under the Plan as of the date they become participants in Part III of the RETIREMENT PLAN. This Plan was further amended effective June 3, 2019 to reflect incentive structures adopted in connection with the CORPORATION’s and the COMPANY’s voluntary petition filed on January 29, 2019 pursuant to chapter 11 of title 11 of the U.S. Bankruptcy Code.

ARTICLE 1

DEFINITIONS

1.01    Basic SERP Benefit shall mean the benefit described in Section 2.01.

1.02    Board or Board of Directors shall mean the BOARD OF DIRECTORS of the CORPORATION or, when appropriate, any committee of the BOARD which has been delegated the authority to take action with respect to the PLAN.

1.03    Company shall mean the Pacific Gas and Electric Company, a California corporation.

1.04    Corporation shall mean PG&E Corporation, a California corporation.

1.05    Eligible Employee shall mean individuals who are, prior to January 1, 2013 (1) (a) employees of the COMPANY or, with respect to PG&E Corporation, PG&E Corporation Support Services, Inc., and PG&E Corporation Support Services II, Inc. only, (i) prior to April 1, 2007, were employees who transferred to PG&E Corporation, PG&E Corporation Support Services, Inc., or PG&E Corporation Support Services II, Inc. from Pacific Gas and Electric Company; or (ii) after March 31, 2007, all employees, and (b) officers in Officer Bands I-V, or (2) such other employees of the COMPANY, the CORPORATION, PG&E Corporation Support Services, Inc., PG&E Corporation Support Services II, Inc., or such other companies, affiliates, subsidiaries, or associations, as may be designated by the Chief Executive Officer of the CORPORATION. ELIGIBLE EMPLOYEES shall not include employees who retired prior to January 1, 2005, or whose employment relationship with any of the PARTICIPATING EMPLOYERS was otherwise terminated prior to January 1, 2005.

1.06    STIP Payment shall mean amounts received by an ELIGIBLE EMPLOYEE under the Short-Term Incentive Plan or other short-term or annual performance-based cash incentive plan (e.g., the 2019 Key Employee Incentive Plan) maintained by the CORPORATION prior to the date the ELIGIBLE EMPLOYEE becomes a participant in Part III of the RETIREMENT PLAN.

1.07    PART III of the RETIREMENT PLAN shall mean the cash balance benefit available under the RETIREMENT PLAN.

1.08    Participating Employer shall mean the COMPANY, the CORPORATION, PG&E Corporation Support Services, Inc., PG&E Corporation Support Services II, Inc., and any other companies, affiliates, subsidiaries or associations designated by the Chief Executive Officer of the CORPORATION.

1.09    Plan shall mean the Supplemental Executive Retirement Plan (“SERP”) as set forth herein and as may be amended from time to time.

1.10    Plan Administrator shall mean the Employee Benefit Committee or such individual or individuals as that Committee may appoint to handle the day-to-day affairs of the PLAN.

1.11    Retirement Plan shall mean the Pacific Gas and Electric Company Retirement Plan.

1.12    Salary shall mean the base salary received by an ELIGIBLE EMPLOYEE prior to the date the ELIGIBLE EMPLOYEE becomes a participant in Part III of the RETIREMENT PLAN. SALARY shall not include amounts received by an employee after such employee ceases to be an ELIGIBLE EMPLOYEE. For purposes of calculating benefits under the PLAN, SALARY shall not be reduced to reflect amounts that have been deferred under the PG&E Corporation Supplemental Retirement Savings Plan.

1.13    Service shall mean “credited service” as that term is defined in the RETIREMENT PLAN or, if the Nominating and Compensation Committee of the BOARD OF DIRECTORS has granted an adjusted service date for an ELIGIBLE EMPLOYEE, “credited service” as calculated from such adjusted service date. In no event, however, shall SERVICE include periods of time after which an officer has ceased to be an ELIGIBLE EMPLOYEE or after the date the ELIGIBLE EMPLOYEE becomes a participant in Part III of the RETIREMENT PLAN.

ARTICLE 2

SERP BENEFITS

2.01    The BASIC SERP BENEFIT payable from the PLAN shall be a monthly annuity with an annuity start date of the later of (a) the first of the month following the month in which the ELIGIBLE EMPLOYEE has a separation from service (as provided under Code Section 409A and related guidance), or (b) the first of the month following the ELIGIBLE EMPLOYEE’s 55th birthday; provided, however, that no payments under the PLAN shall be made until the seventh month following the annuity start date. The first payment shall consist of the monthly annuity payment for the seventh month, plus the first six monthly annuity payments, including interest calculated at a rate to reflect the CORPORATION’s marginal cost of funds. The monthly amount of the BASIC SERP BENEFIT shall be equal to the product of:

1.7% x the average of three highest calendar years’ combination of SALARY and STIP PAYMENT for the last ten years of SERVICE x SERVICE x 1/12.

In computing a year’s combination of SALARY and STIP PAYMENT, the year’s amount shall be the sum of the SALARY and STIP PAYMENT, if any, paid or payable in the same calendar year. If an ELIGIBLE EMPLOYEE has fewer than three years’ SALARY, the average shall be the combination of SALARY and STIP PAYMENT for such shorter time, divided by the number of years and partial years during which such employee was an ELIGIBLE EMPLOYEE.

The BASIC SERP BENEFIT is further reduced by any amounts paid or payable from the RETIREMENT PLAN (other than amounts paid or payable under Part III of the RETIREMENT PLAN), calculated before adjustments for marital or joint pension option elections.

The BASIC SERP BENEFIT is a benefit commencing at age 65. The amount of the benefit payable shall be reduced by the appropriate age and service factors contained in the RETIREMENT PLAN applicable to such employee. For such calculations, the service factor shall be SERVICE as defined in the PLAN.

In computing amounts payable from the RETIREMENT PLAN as an offset to the benefit payable from this PLAN, the RETIREMENT PLAN benefit shall be calculated as though the ELIGIBLE EMPLOYEE elected to receive a pension from the RETIREMENT PLAN commencing on the same date as benefits from this PLAN.

2.02    For ELIGIBLE EMPLOYEES of the PARTICIPATING EMPLOYERS, who transfer from any of said companies to another subsidiary or affiliate, the principles of Section 10 of the RETIREMENT PLAN shall govern the calculation of benefits under this PLAN.

2.03    An ELIGIBLE EMPLOYEE may elect to have his BASIC SERP BENEFIT paid in any one of the following forms that are actuarially equivalent within the meaning of Treasury Regulations Section 1.409A-2(b)(ii), with the first annuity payment commencing at the time set forth in Section 2.01:

(a)BASIC SERP BENEFIT, or a reduced BASIC SERP BENEFIT as calculated under Section 2.02, paid as a monthly annuity for the life of the ELIGIBLE EMPLOYEE with no survivor’s benefit.

(b)A monthly annuity payable for the life of the ELIGIBLE EMPLOYEE with a survivor’s option payable to the ELIGIBLE EMPLOYEE’s joint annuitant beginning on the first of the month following the ELIGIBLE EMPLOYEE’s death. Subject to the requirements of Treasury Regulations Section 1.409A-2(b)(ii), the factors to be applied to reduce the BASIC SERP BENEFIT to provide for a survivor’s benefit shall be the factors which are contained in the RETIREMENT PLAN and which are appropriate given the type of joint pension elected and the ages and marital status of the joint annuitants.

An ELIGIBLE EMPLOYEE may make this election by the latest date permitted by the PLAN ADMINISTRATOR and in compliance with the rules of Treasury Regulations Section 1.409A-2(b)(2)(ii).

2.04    Annuities payable to an ELIGIBLE EMPLOYEE who is receiving a (i) BASIC SERP BENEFIT, (ii) a BASIC SERP BENEFIT reduced to provide a survivor’s benefit to a joint annuitant, or (iii) a joint annuitant who is receiving a survivor’s benefit shall be decreased by any additional amounts which can be paid from the RETIREMENT PLAN where such additional amounts are due to increases in the limits placed on benefits payable from qualified pension plans under Section 4l5 of the Internal Revenue Code. The amount of any such decrease shall be adjusted to reflect the type of pension elected by an ELIGIBLE EMPLOYEE under the RETIREMENT PLAN and this PLAN.

ARTICLE 3

SURVIVOR BENEFITS

3.01    In the event that an ELIGIBLE EMPLOYEE who has accrued a benefit under this PLAN dies prior to the date that a BASIC SERP BENEFIT would otherwise commence, the PLAN ADMINISTRATOR shall pay a survivor’s benefit (“SURVIVOR’S BENEFIT”) to the ELIGIBLE EMPLOYEE’s surviving spouse or BENEFICIARY (“Beneficiary” shall have the same meaning as provided under the RETIREMENT PLAN):

(a)If the sum of the age and SERVICE of the ELIGIBLE EMPLOYEE at the time of death equaled 70 (69.5 or more is rounded to 70) or if the ELIGIBLE EMPLOYEE was age 55 or older at the time of death, the surviving spouse’s or BENEFICIARY’s benefit shall be a monthly annuity commencing at the time set forth in Section 2.01 and shall be payable for the life of the surviving spouse or BENEFICIARY. The amount of the monthly benefit shall be a monthly benefit that is actuarially equivalent to one-half of the monthly BASIC SERP BENEFIT that would have been paid to the ELIGIBLE EMPLOYEE calculated:

i.as if he had elected to receive a BASIC SERP BENEFIT, without survivor’s option; and

ii.the monthly annuity starting date was the first of the month following the month in which the ELIGIBLE EMPLOYEE died; and

iii.without the application of early retirement reduction factors. However, if the surviving spouse or BENEFICIARY is more than 10 years younger than the ELIGIBLE EMPLOYEE, the amount of the surviving spouse’s or BENEFICIARY’s benefit shall be reduced one-twentieth of 1 percent for each full month in excess of 120 months’ difference in their ages, except that such reduction shall not result in a SURVIVOR’S BENEFIT lower than would have been payable if the ELIGIBLE EMPLOYEE had retired as of the date of death and elected a 50 percent joint pension with a spouse of the same gender and age as the surviving spouse or BENEFICIARY.

(b)If the ELIGIBLE EMPLOYEE is less than 55 years of age or had fewer than 70 points (as calculated under Section 3.01(a)) at the time of death, the surviving spouse or BENEFICIARY will be entitled to receive a monthly annuity commencing at the time set forth in Section 2.01. The amount of the monthly annuity payable to the surviving spouse or BENEFICIARY shall be equal to the BASIC SERP BENEFIT converted to a marital joint annuity providing for a 50 percent survivor’s benefit, calculated as if: 1) the ELIGIBLE EMPLOYEE had terminated employment at the date of death, 2) had lived until age 55, 3) had begun to receive PENSION payments at age 55, and 4) had subsequently died.

(c)If a former ELIGIBLE EMPLOYEE was age 55 or older at the time of his death and not yet receiving a SERP BENEFIT under the PLAN, the surviving spouse or BENEFICIARY will be entitled to receive a monthly annuity at the time set forth in Section 2.01 in an amount equal to the BASIC SERP BENEFIT converted to a marital joint annuity providing for a 50 percent survivor’s benefit, calculated as if the former ELIGIBLE EMPLOYEE had begun receiving the converted SERP BENEFIT immediately prior to his death.

(d)If a former ELIGIBLE EMPLOYEE was younger than age 55 and had fewer than 70 points (as calculated under Section 3.01(a)) at the time of his death, the surviving spouse or BENEFICIARY will be entitled to receive a monthly annuity at the time set forth in Section 2.01 in an amount equal to the BASIC SERP BENEFIT converted to a marital joint annuity providing for a 50 percent survivor’s benefit, calculated as if: 1) the former ELIGIBLE EMPLOYEE had survived until age 55, 2) had begun receiving the converted SERP BENEFIT at age 55, and 3) had subsequently died.

3.02    A surviving spouse or BENEFICIARY who is entitled to receive a SURVIVOR’S BENEFIT under Section 3.01 shall not be entitled to receive any other benefit under the PLAN.

ARTICLE 4

ADMINISTRATIVE PROVISIONS

4.01    Administration. The PLAN shall be administered by the Senior Human Resources Officer of the CORPORATION (“PLAN ADMINISTRATOR”), who shall have the authority to interpret the PLAN and make and revise such rules as he or she deems appropriate. The PLAN ADMINISTRATOR shall have the duty and responsibility of maintaining records, making the requisite calculations, and disbursing payments hereunder. The PLAN ADMINISTRATOR’s interpretations, determinations, rules, and calculations shall be final and binding on all persons and parties concerned.

4.02    Amendment and Termination. The CORPORATION may amend or terminate the PLAN at any time, provided, however, that no such amendment or termination shall adversely affect an accrued benefit which an ELIGIBLE EMPLOYEE has earned prior to the date of such amendment or termination, nor shall any amendment or termination adversely affect a benefit which is being provided to an ELIGIBLE EMPLOYEE, surviving spouse, joint annuitant, or beneficiary under Article II or Article III on the date of such amendment or termination. Anything in this Section 4.02 to the contrary notwithstanding, the CORPORATION may (but is not obligated to) reduce or terminate any benefit to which an ELIGIBLE EMPLOYEE, surviving spouse or joint annuitant, is or may become entitled provided that such ELIGIBLE EMPLOYEE, surviving spouse or joint annuitant is or becomes entitled to an amount equal to such benefit under another plan, practice, or arrangement of the CORPORATION that preserves the time and form of payment rules under the PLAN and otherwise in a manner that complies with Code Section 409A, to the extent required to not violate Code Section 409A.

4.03    Nonassignability of Benefits. Except to the extent otherwise directed by a domestic relations order that the Plan Administrator determines is a Qualified Domestic Relations Order under Section 401(a)(12) of the Internal Revenue Code, the benefits payable under this PLAN or the right to receive future benefits under this PLAN may not be anticipated, alienated, pledged, encumbered, or subject to any charge or legal process, and if any attempt is made to do so, or a person eligible for any benefits becomes bankrupt, the interest under the PLAN of the person affected may be terminated by the PLAN ADMINISTRATOR which, in its sole discretion, may cause the same to be held if applied for the benefit of one or more of the dependents of such person or make any other disposition of such benefits that it deems appropriate.

4.04    Nonguarantee of Employment. Nothing contained in this PLAN shall be construed as a contract of employment between a PARTICPATING EMPLOYER and the ELIGIBLE EMPLOYEE, or as a right of the ELIGIBLE EMPLOYEE to be continued in the employ of a PARTICIPATING EMPLOYER, to remain as an officer of a PARTICIPATING EMPLOYER, or as a limitation on the right of a PARTICIPATING EMPLOYER to discharge any of its employees, with or without cause.

4.05    Apportionment of Costs. The costs of the PLAN may be equitably apportioned by the PLAN ADMINISTRATOR among the PARTICIPATING EMPLOYERS. Each PARTICIPATING EMPLOYER shall be responsible for making benefit payments pursuant to the PLAN on behalf of its ELIGIBLE EMPLOYEES or for reimbursing the CORPORATION for the cost of such payments, as determined by the CORPORATION in its sole discretion. In the event the respective PARTICIPATING EMPLOYER fails to make such payment or reimbursement, and the CORPORATION does not exercise its discretion to make the contribution on such PARTICIPATING EMPLOYER’s behalf, future benefit accruals of the ELIGIBLE EMPLOYEES of that PARTICIPATING EMPLOYER shall be suspended. If at some future date, the PARTICIPATING EMPLOYER makes all past-due contributions, plus interest at a rate determined by the PLAN

ADMINISTRATOR in his or her sole discretion, the benefit accrual of its ELIGIBLE EMPLOYEES will be recognized for the period of the suspension.

4.06    Benefits Unfunded and Unsecured. The benefits under this PLAN are unfunded, and the interest under this PLAN of any ELIGIBLE EMPLOYEE and such ELIGIBLE EMPLOYEE’s right to receive a distribution of benefits under this PLAN shall be an unsecured claim against the general assets of the CORPORATION.

4.07    Applicable Law. All questions pertaining to the construction, validity, and effect of the PLAN shall be determined in accordance with the laws of the United States, and to the extent not preempted by such laws, by the laws of the State of California. The PLAN is intended to comply with the provisions of Code Section 409A. However, the CORPORATION makes no representation that the benefits provided under this PLAN will comply with Code Section 409A and makes no undertaking to prevent Code Section 409A from applying to the benefits provided under this PLAN or to mitigate its effects on any deferrals or payments made under this PLAN.

4.08    Satisfaction of Claims. Notwithstanding Section 4.05 or any other provision of the PLAN, the CORPORATION may at any time satisfy its obligations (either on a before-tax or after-tax basis) for any benefits accrued under the PLAN by the purchase from an insurance company of an annuity contract on behalf of an ELIGIBLE EMPLOYEE. Such purchase shall be in the sole discretion of the CORPORATION and shall be subject to the ELIGIBLE EMPLOYEE’s acknowledgement that the CORPORATION’s obligations to provide benefits hereunder have been discharged, without regard to the payments ultimately made under the contract. In the event of a purchase pursuant to this Section 4.07, the CORPORATION may in its sole discretion make payments to or on behalf of an ELIGIBLE EMPLOYEE to defray the cost to such ELIGIBLE EMPLOYEE of any personal income tax in connection with the purchase.

EX-10.10

EXHIBIT 10.10

PG&E CORPORATION

DEFINED CONTRIBUTION EXECUTIVE SUPPLEMENTAL RETIREMENT PLAN

Effective as of January 1, 2013 (the “Effective Date”), PG&E Corporation adopted this Plan for the benefit of a select group of management or highly compensated employees of PG&E Corporation and its Participating Subsidiaries. This Plan was further amended effective September 17, 2013, with respect to certain vesting and deferral election provisions and effective June 3, 2019 to reflect incentive structures adopted in connection with PG&E Corporation’s and Pacific Gas and Electric Company’s voluntary petition filed on January 29, 2019 pursuant to chapter 11 of title 11 of the U.S. Bankruptcy Code. The Plan is an unfunded arrangement and is intended to be exempt from the participation, vesting, funding and fiduciary requirements set forth in Title I of ERISA.

Article 1 - Definitions

When used in this Plan, the following words, terms and phrases have the meanings given to them in this Article unless another meaning is expressly provided elsewhere in this document. When applying these definitions and any other word, term or phrase used in this Plan, the form of any word, term or phrase will include any and all of its other forms.

1.01    “Account” means the bookkeeping account established for each Eligible Employee as provided in Section 5.01 hereof.

1.02    “Aggregated Plan” means any arrangement that, along with this Plan, would be treated as a single nonqualified deferred compensation plan under Treasury Regulation Section 1.409A-

1(c)(2).

1.03    “Board” means the Board of Directors of Company.

1.04    “Code” means the Internal Revenue Code of 1986, as amended. Reference to a specific section of the Code shall include such section, any valid regulation promulgated thereunder, and any comparable provision of any future legislation amending, supplementing, or superseding such section.

1.05    “Committee” means the Compensation Committee of the Board, as it may be constituted from time to time.

1.06    “Company” means PG&E Corporation, a California corporation.

1.07    “Company Contribution” means a deemed contribution that is credited to an Eligible Employee’s Account in accordance with the terms of Article 2 hereof.

1.08    “Eligible Employee” means any individual who (i) was a participant in the SERP and elects to switch under the Pacific Gas and Electric Company Retirement Plan for Management Employees to a cash-balance formula pension benefit effective January 1, 2014, (ii) becomes an Officer in Bands I-V of Company or a Participating Subsidiary on or after the Effective Date; or (iii) is an employee of Company or a Participating Employer, and is designated as a Plan Participant by the Chief Executive Officer of Company. Notwithstanding the forgoing, any individual who is a participant in the Excess Plan shall not become an Eligible Employee until January 1 of the calendar year after satisfying any of the criteria in (ii)-(iii) above. If an individual ceases to be an Officer in Bands I-V or if his or her participation in this Plan is terminated by the Chief Executive Officer, then any accrued benefits will be handled in accordance with Article 6.

1.09    “Employer” means any entity that employs an Eligible Employee, whether that entity is the Company or any of the Participating Subsidiaries designated by the Plan Administrator.

1.10    “ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

1.11    “Excess Plan” means the Retirement Excess Plan of the Pacific Gas and Electric Company, as amended from time to time.

1.12    “Investment Fund” means each deemed investment vehicle which serves as a means to measure value, increases or decreases with respect to an Eligible Employee’s Account.

1.13    “Participating Subsidiary” means a United States-based subsidiary of Company, which has been designated by the Plan Administrator as a Participating Subsidiary under this Plan and which has agreed to make payments or reimbursements with respect to its Eligible Employees pursuant to Section 11.04. At such times and under such conditions as the Plan Administrator may direct, one or more other subsidiaries of Company may become Participating Subsidiaries or a Participating Subsidiary may be withdrawn from the Plan. An initial list of the Participating Subsidiaries is contained in Appendix A to this Plan.

1.14     “Plan” means the PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan.

1.15    “Plan Year” means each calendar year during which the Plan is in effect

1.16    “SERP” means the Supplemental Executive Retirement Plan of PG&E Corporation, as amended from time to time.

1.17    “Salary” means only the gross amount of an Eligible Employee’s base salary as reflected in the payroll records of the applicable Employer. Salary shall not include amounts received by an employee after such employee ceases to be an Eligible Employee or prior to becoming an Eligible Employee. Salary shall be calculated before reduction for compensation voluntarily deferred or contributed by the Eligible Employee pursuant to all qualified or nonqualified plans of the applicable Employer and shall be calculated to include amounts not otherwise included in the Eligible Employee’s gross income under Code Sections 125, 132, 402(e)(3), 402(h), or 403(b) pursuant to plans or arrangements established by the Employers; provided, however, that all such amounts will be included in compensation only to the extent that had there been no such plan, the amount would have been payable in cash to the Eligible Employee. Without limiting the foregoing, “Salary” shall not include any amount paid pursuant to a disability plan or pursuant to a disability insurance policy or distributions from nonqualified deferred compensation plans, incentive payments of any kind, commissions, overtime, fringe benefits, or any non-cash benefit.

1.18    “Separation from Service” means a “separation from service” with Company and its

Affiliates within the meaning of Code Section 409A(a)(2)(A)(i) and related Treasury Regulations and other guidance, as determined by the Plan Administrator in its discretion.

1.19    “STIP Payment” means the gross amount of an Eligible Employee’s bonus under the annual cash Short-Term Incentive Plan or other short-term or annual performance-based cash incentive plan (e.g., the 2019 Key Employee Incentive Plan) adopted and maintained each year by Company or its Participating Subsidiaries. STIP Payments shall not include amounts received by an employee after such employee ceases to be an Eligible Employee or prior to becoming an Eligible Employee. For purposes of calculating benefits under the Plan, STIP Payment shall be calculated before reduction for compensation voluntarily deferred or contributed by the Eligible Employee pursuant to all qualified or nonqualified plans of the applicable Employer, and shall be calculated to include amounts not otherwise included in the Eligible Employee’s gross income under Code Sections 125, 132, 402(e)(3), 402(h), or 403(b) pursuant to plans or arrangements established by the Employer; provided, however, that all such amounts will be included in compensation only to the extent that had there been no such plan, the amount would have been payable in cash to the Eligible Employee.

1.20    “Valuation Date” means:

(1) For purposes of valuing Plan assets and Eligible Employees’ Accounts for periodic reports and statements, the date as of which such reports or statements are made; and

(1) For purposes of determining the amount of assets actually distributed to the Eligible Employee, his or her beneficiary, or an Alternate Payee (or available for withdrawal), a date that shall not be more than thirty business days prior to the date the check is issued to the Eligible Employee.

In any other case, the Valuation Date shall be the date designated by the Plan Administrator (in its discretion) or the date otherwise set forth in this Plan. In all cases, the Plan Administrator (in its discretion) may change the Valuation Date, on a uniform and nondiscriminatory basis, as is necessary or appropriate. Notwithstanding the foregoing, the Valuation Date shall occur at least annually.

Article 2 - Company Contributions

2.01    Company Contributions. Company will make a deemed contribution to each Eligible Employee’s Account in a percentage amount designated by the Committee, in its sole discretion, of the Eligible Employee’s Salary and STIP Payment, at the time that such Salary or STIP Payment is paid.

2.02    Excess Plan Participants. Company will make an additional deemed contribution to the Account of each Eligible Employee who was a participant in the Excess Plan on or after January 1, 2013. The amount of such contribution will be approximately equal to the difference between the amounts that the Eligible Employee could have received under the Plan if contributions, if any, under Section 2.01 had commenced upon satisfying any of the eligibility criteria in Section 1.08(ii)-(iii), and the amount actually accrued under the Excess Plan, in each case through December 31 of such year. Such payments shall be made only for the portion of the calendar year prior to the individual becoming an Eligible Employee. Such calculation shall be done at the Company’s discretion, using such assumptions and methodologies as determined by the Company in its sole discretion. Amounts provided pursuant to this Section will distributed in a lump-sum, in accordance with Section 6.01(2).

Article 3 - Vesting

3.01    Vesting of Company Contributions. Except as otherwise determined by the Plan Administrator in its sole discretion, and provided that the Eligible Employee has not Separated from Service (other than due to death), an Eligible Employee shall become one hundred percent (100%) vested in the Eligible Employee’s Account after completing at least three (3) cumulative years of service with any Employer(s). For this purpose, years of service shall be calculated on an elapsed-time, anniversary date of hire basis. “Years of cumulative service” shall include, without limitation, all service while an active participant in the Plan or in the SERP, including active service prior to any break in service. An Employee’s service will be deemed to continue while on approved leave of absence. If an Eligible Employee dies prior to both Separating from Service and satisfying the three-year vesting period, the Eligible Employee’s Account shall vest in full and be paid out in accordance with Section 6.05, below.

3.02    Amounts Not Vested. Subject to the foregoing, any amounts credited to an Eligible Employee’s Account that are not vested at the time of the Eligible Employee’s Separation from Service shall be forfeited.

Article 4 - Investment Funds

Although no assets will be segregated or otherwise set aside with respect to an Eligible Employee’s Account, the amount that is ultimately payable to the Eligible Employee with respect to such Account shall be determined as if such Account had been invested in some or all of the Investment Funds. The Plan Administrator, in its sole discretion, shall adopt (and modify from time to time) such rules and procedures as it deems necessary or appropriate to implement the deemed investment of the Eligible Employees’ Accounts. Such procedures generally shall provide that an Eligible Employee’s Account shall be deemed to be invested among the available Investment Funds in the manner elected by the Eligible Employee in such percentages and manner as prescribed by the Plan Administrator. In the event no election has been made by the Eligible Employee, such Account will be deemed to be invested in the Investment Funds designated by the Plan Administrator. Eligible Employees shall be able to reallocate their Accounts between the Investment Funds and reallocate amounts newly credited to their Accounts at such time and in such manner as the Plan Administrator shall prescribe. Anything to the contrary herein notwithstanding, an Eligible Employee may not reallocate Account balances between Investment Funds if such reallocation would result in a non-exempt Discretionary Transaction as defined in Rule 16b-3 of the Securities Exchange Act of 1934, as amended, or any successor to Rule 16b-3, as in effect when the reallocation is requested. The available Investment Funds shall be designated by the Plan Administrator and may be changed from time to time by the Plan Administrator at its discretion.

Article 5 - Accountings

5.01    Eligible Employees’ Accounts. At the direction of the Plan Administrator, there shall be established and maintained on the books of the Employer, a separate account for each Eligible Employee in order to reflect his or her interest under the Plan.

5.02    Investment Earnings. Each Eligible Employee’s Account shall initially reflect the value of his or her Account’s interest in each of the Investment Funds, deemed acquired with the amounts credited thereto. Each Eligible Employee’s Account shall also be credited (or debited) with the net appreciation (or depreciation), earnings and gains (or losses) with respect to the investments deemed made by his or her Account. Any such net earnings or gains deemed realized with respect to any investment of any Eligible Employee’s Account shall be deemed reinvested in additional amounts of the same investment and credited to the Eligible Employee’s Account.

5.03    Accounting Methods. The accounting methods or formulae to be used under the Plan for the purpose of maintaining the Eligible Employees’ Accounts shall be determined by the Plan Administrator. The accounting methods or formulae selected by the Plan Administrator may be revised from time to time but shall conform to the extent practicable with the accounting methods used under the Plan.

5.04    Valuations and Reports. The fair market value of each Eligible Employee’s Account shall be determined as of each Valuation Date. In making such determinations and in crediting net deemed earnings and gains (or losses) in the Investment Funds to the Eligible Employees’ Accounts, the Plan Administrator (in its discretion) may employ such accounting methods as the Plan Administrator (in its discretion) may deem appropriate in order to fairly reflect the fair market values of the Investment Funds and each Eligible Employee’s Account. For this purpose, the Plan Administrator may rely upon information provided by the Plan Administrator or other persons believed by the Plan Administrator to be competent.

5.05    Statements of Eligible Employee’s Accounts. Each Eligible Employee shall be furnished with periodic statements of his or her interest in the Plan.

Article 6 - Distributions

6.01    Distribution of Account Balances.

(1) Participants in SERP. Distribution of the balance credited to the Account of any Eligible Employee who was a participant in the SERP will be made according to the time and form provisions applicable to that Eligible Employee’s benefits under the SERP. Sections 6.01(2), 6.02, 6.03, 6.04 and 6.05 shall not apply to the Eligible Employees described above in this Section 6.01(1).

(2) Other Eligible Employees. Except to the extent the Eligible Employee has elected otherwise under this Section 6 at the time of deferral, distribution of the balance credited to an Eligible Employee’s Account shall be made in a single lump sum as soon as reasonably practicable (but in any event within 90 days) following the date that is seven (7) months following Separation from Service.

(3) DROs. In the case of an Alternate Payee (as defined in Section 7.01(1)), to the extent allowable under Code Section 409A, distribution shall be made as directed in a domestic relations order approved by the Plan Administrator, but only as to the portion of the Eligible Employee’s Account which the domestic relations order states is payable to the Alternate Payee.

6.02    Election of Installment Payments. In lieu of the single sum payment under Section 6.01, an Eligible Employee may elect in writing, on such form or in such other manner as it may prescribe, and file with the Plan Administrator an election that payment of amounts credited to the Eligible Employee’s Account be made in from 2 to 10 equal annual installments. Installment payments elected before September 17, 2013 will be considered separate payments for purposes of Code Section 409A. Installment payments will commence as soon as reasonably practicable (but in any event within 90 days) following the date that is seven (7) months following Separation from Service (“Benefit Commencement Date”), and subsequent installments will be paid on each anniversary of the Benefit Commencement Date thereof until all installments are paid. However, if during the installment payment period after the Benefit Commencement Date the Account balance plus the Eligible Employee’s interest in all other Aggregated Plans is less than the dollar limit set forth in Code Section 402(g)(1)(B) in the aggregate, the value of the remaining installments and such other interest(s) may be accelerated by written election of the Plan Administrator and subsequently paid as a lump sum at the sole discretion of the Plan Administrator, except to the extent that would result in a violation of Code Section 409A. Notwithstanding anything in this Section 6.02 to the contrary, if the Eligible Employee’s vested Account balance on the Benefit Commencement Date is less than $50,000, and prior to September 17, 2013 the Eligible Employee elected pursuant to this Section 6.02 to receive payment in installments, then the distribution election described in this Section 6.02 shall be disregarded and the Eligible Employee’s entire vested Account balance shall be paid in a lump sum distribution as described in Section 6.01(2) above.

6.03    Timing of Elections.

(1) General Rule. The election described in Section 6.02 shall be made no later than December 31 of the calendar year immediately preceding the calendar year in which the Salary or STIP Payment commences to be earned that is the basis of the Company Contribution for which an election is being made, in accordance with such procedures established by the Company in its sole discretion.

(2) Initial Eligibility. Notwithstanding Section 6.03(1), an Eligible Employee that is newly eligible to participate in the Plan (or in any Aggregated Plan) must make an election regarding whether distributions shall be made in a lump-sum or installments, as provided in Section 6.02. Such election must be made within thirty (30) days after he or she first becomes an Eligible Employee (or within such other earlier deadline as may be established by the Company, in its sole discretion) but only with respect to Company Contributions attributable to Salary and STIP Payments that are paid with respect to services performed after such election is made; provided, however, that for this purpose only such thirty (30) day period shall begin to run on the date that the Eligible Employee first becomes eligible to participate in this Plan (or, if earlier, any Aggregated Plan). In the event an Eligible Employee fails to timely make such election, Section 6.01(2) shall apply. Notwithstanding anything to the contrary herein, no Company Contributions shall be earned or made to a newly Eligible Employee’s Account with respect to service performed prior to the earlier of (1) the day after the Eligible Employee returns an initial election pursuant to Section 6.03(2) or (2) 31 days after the individual first qualifies as an Eligible Employee.

(3) Performance-Based Compensation. Notwithstanding Section 6.03(1), with respect to STIP Payments that qualify as “Performance-Based Compensation,” the Company may, in its sole discretion, permit an election pertaining to Company Contributions attributable to     such Performance-Based Compensation to be made no later than six (6) months before the end of the performance service period and in accordance with Code Section 409A. For this purpose, “Performance-Based Compensation” shall be compensation, the payment or amount of which is contingent on pre-established organizational or individual performance criteria, which satisfies the requirements of Code Section 409A

6.04    Change in Distribution Election. An Eligible Employee may change a distribution election previously made pursuant to Section 6.02 only in accordance with the rules under Code Section 409A. Generally, a subsequent election pursuant to this Section 6.04: (1) cannot take effect for twelve (12) months, (2) must occur at least twelve (12) months before the first scheduled payment, and (3) must defer a previously elected distribution at least five (5) additional years. The Plan Administrator may establish additional rules or restrictions on changes in distribution elections.

6.05    Death Distributions. If an Eligible Employee dies before the balance of his or her Account has been distributed (whether or not the Eligible Employee had previously had a Separation from Service), the Eligible Employee’s Account shall be distributed in a single lump sum to the beneficiary designated or otherwise determined in accordance with Section 6.07, as soon as practicable the date of death (but in any event within 90 days after the date of death).

6.06    Effect of Change in Eligible Employee Status. If an Eligible Employee ceases to be an Eligible Employee but does not experience a Separation from Service, the balance credited to his or her Account shall continue to be credited (or debited) with appreciation, depreciation, earnings, gains or losses under the terms of the Plan and shall be distributed to him or her at the time and in the manner set forth in this Section 6.

6.07    Payments to Incompetents. If any individual to whom a benefit is payable under the Plan is a minor or if the Plan Administrator determines that any individual to whom a benefit is payable under the Plan is incompetent to receive such payment or to give a valid release therefor, payment shall be made to the guardian, committee, or other representative of the estate of such individual which has been duly appointed by a court of competent jurisdiction. If no guardian, committee, or other representative has been appointed, payment may be made to any person as custodian for such individual under the California Uniform Transfers to Minors Act (or similar law of another state) or may be made to or applied to or for the benefit of the minor or incompetent, the incompetent’s spouse, children or other dependents, the institution or persons maintaining the minor or incompetent, or any of them, in such proportions as the Plan Administrator from time to time shall determine; and the release of the person or institution receiving the payment shall be a valid and complete discharge of any liability of Company with respect to any benefit so paid.

6.08    Beneficiary Designations. Each Eligible Employee may designate, in a signed writing delivered to the Plan Administrator, on such form or in such other manner as it may prescribe, one or more beneficiaries to receive any distribution which may become payable under the Plan as the result of the Eligible Employee’s death. Such an Eligible Employee may designate different beneficiaries at any time by delivering a new designation in like manner. Any designation shall become effective only upon its receipt by the Plan Administrator, and the last effective designation received by the Plan Administrator shall supersede all prior designations. If such an Eligible Employee dies without having designated a beneficiary or if no beneficiary survives that Eligible Employee, that Eligible Employee’s Account shall be payable to the beneficiary or beneficiaries designated or otherwise determined under the PG&E Corporation Retirement Savings Plan or any predecessor qualified retirement plan sponsored by Company or any of its subsidiary companies.

6.09    Undistributable Accounts. Each Eligible Employee and (in the event of death) his or her beneficiary shall keep the

Plan Administrator advised of his or her current address. If the Plan Administrator is unable to locate the Eligible Employee or beneficiary to whom an Eligible Employee’s Account is payable under this Section 6, the Eligible Employee’s Account shall be frozen as of the date on which distribution would have been completed in accordance with this Section 6, and no further appreciation, depreciation, earnings, gains or losses shall be credited (or debited) thereto. Company shall have the right to assign or transfer the liability for payment of any undistributable Account to the Eligible Employee’s former Employer (or any successor thereto).

6.10    Plan Administrator Discretion. Within the specific time periods described in this Section 6, the Plan Administrator shall have sole discretion to determine the specific timing of the payment of any Account balance under the Plan.

Article 7 - Domestic Relations Orders

7.01    Domestic Relations Orders. The Plan Administrator shall establish written procedures for determining whether a domestic relations order purporting to dispose of any portion of an Eligible Employee’s Account is a domestic relations order within the meaning of Section 414(p) of the Code that is acceptable to the Plan (a “DRO”).

(1) No Payment Unless a DRO. No payment shall be made to any person designated in a domestic relations order (an “Alternate Payee”) until the Plan Administrator (or a court of competent jurisdiction reversing an initial adverse determination by the Plan Administrator) determines that the order is a DRO. Payment shall be made to each Alternate Payee as specified in the DRO.

(2) Time of Payment. Payment may be made to an Alternate Payee in the form of a lump sum, at the time specified in the DRO, but no earlier than the date the DRO determination is made by the Plan.

(3) Hold Procedures. Notwithstanding any contrary Plan provision, prior to the receipt of a domestic relations order, the Plan Administrator may, in its sole discretion, place a hold upon all or a portion of an Eligible Employee’s Account for a reasonable period of time (as determined by the Plan Administrator in accordance with Code Section 409A) if the Plan Administrator receives notice that (a) a domestic relations order is being sought by the Eligible Employee, his or her spouse, former spouse, child or other dependent, and (b) the Eligible Employee’s Account is a source of the payment under such domestic relations order. For purposes of this Section 7.01, a “hold” means that no withdrawals, distributions, or investment transfers may be made with respect to an Eligible Employee’s Account. If the Plan Administrator places a hold upon an Eligible Employee’s Account pursuant to this Section 7.01, it shall inform the Eligible Employee of such fact.

Article 8 - Tax Withholding

Each Eligible Employee shall be responsible for FICA taxes on amounts credited to his or her Account under Section 2. Without limiting the foregoing, the applicable Employer shall have the right to withhold such amounts from other payments due to the Eligible Employee. Company Contributions will not be reduced to cover Eligible Employees’ FICA tax liabilities.

The applicable Employer, as applicable, will withhold from other amounts owed to an Eligible Employee or require the Eligible Employee to remit to Employer, as applicable, an amount sufficient to satisfy federal, state and local tax withholding requirements with respect to any Plan benefit or the vesting, payment or cancellation of any Plan benefit.

Article 9 - Administration of the Plan

9.01    Plan Administrator. The Employee Benefit Committee of Company is hereby designated as the administrator of the Plan (within the meaning of Section 3(16)(A) of ERISA). The Plan Administrator delegates to the most senior human resource officer for Company, or his or her designee, the authority to carry out all duties and responsibilities of the Plan Administrator under the Plan. The Plan Administrator shall have the authority to control and manage the operation and administration of the Plan.

9.02    Powers of Plan Administrator. The Plan Administrator shall have all discretion and powers necessary to supervise the administration of the Plan and to control its operation in accordance with its terms, including, but not by way of limitation, the power to interpret the provisions of the Plan and to determine, in its sole discretion, any question arising under, or in connection with the administration or operation of, the Plan.

9.03    Decisions of Plan Administrator. All decisions of the Plan Administrator and any action taken by it in respect of the Plan and within the powers granted to it under the Plan shall be conclusive and binding on all persons and shall be given the maximum deference permitted by law.

Article 10 - Modification or Termination of Plan

10.01 Employers’ Obligations Limited. The Plan is voluntary on the part of the Employers, and the Employers do not guarantee to continue the Plan. Company at any time may, by appropriate amendment of the Plan, or suspend Company Contributions , with or without cause.

10.02    Right to Amend or Terminate. The Board of Directors, acting through the Committee, reserves the right to alter, amend, or terminate the Plan, or any part thereof, in such manner as it may determine, for any reason whatsoever.

(1) Limitations. Any alteration, amendment, or termination shall take effect upon the date indicated in the document embodying such alteration, amendment, or termination, provided that no such alteration or amendment shall divest any portion of an Account that is then vested under the Plan.

(2) Appendices. Notwithstanding the above, the Plan Administrator may amend the Appendices in its discretion.

10.03    Effect of Termination. If the Plan is terminated, the balances credited to the Accounts of the Eligible Employees affected by such termination shall be distributed to them at the time and in the manner set forth in Section 6; provided, however, that the Plan Administrator, in its sole discretion, may authorize accelerated distribution of Eligible Employees’ Accounts to the extent provided in Treasury Regulation Sections 1-409A-3(j)(4)(ix) (A) (relating to terminations in connection with certain corporate dissolutions), (B) (relating to terminations in connection with certain change of control events), and (C) (relating to general terminations).

Article 11 - General Provisions

11.01    Inalienability. Except to the extent otherwise directed by a domestic relations order which the Plan Administrator determines is a DRO (as defined in Section 7.01) or mandated by applicable law, in no event may either an Eligible Employee, a former Eligible Employee or his or her spouse, beneficiary or estate sell, transfer, anticipate, assign, hypothecate, or otherwise dispose of any right or interest under the Plan; and such rights and interests shall not at any time be subject to the claims of creditors nor be liable to attachment, execution, or other legal process.

11.02    Rights and Duties. Neither the Employers nor the Plan Administrator shall be subject to any liability or duty under the Plan except as expressly provided in the Plan, or for any action taken, omitted, or suffered in good faith.

11.03    No Enlargement of Employment Rights. Neither the establishment or maintenance of the Plan nor any action of any Employer or Plan Administrator, shall be held or construed to confer upon any individual any right to be continued as an Employee nor, upon dismissal, any right or interest in any specific assets of the Employers other than as provided in the Plan. Each Employer expressly reserves the right to discharge any Employee at any time, with or without cause or advance notice.

11.04.    Apportionment of Costs and Duties. All acts required of the Employers under the Plan may be performed by Company for itself and its Participating Subsidiaries, and the costs of the Plan may be equitably apportioned by the Plan Administrator among Company and the other Employers. Whenever an Employer is permitted or required under the terms of the Plan to do or perform any act, matter or thing, it shall be done and performed by any officer or employee of the Employer who is thereunto duly authorized by the board of directors of the Employer. Each Participating Subsidiary shall be responsible for making benefit payments pursuant to the Plan on behalf of its Eligible Employees or for reimbursing Company for the cost of such payments, as determined by Company in its sole discretion. In the event the respective Participating Subsidiary fails to make such payment or reimbursement, and Company does not exercise its discretion to make the payment on such Participating Subsidiary’s behalf, participation in the Plan by the Eligible Employees of that Participating Subsidiary shall be suspended in a manner consistent with Code Section 409A. If at some future date, the Participating Subsidiary makes all past-due payments and reimbursements, plus interest at a rate determined by Company in its sole discretion, the suspended participation of its Eligible Employees eligible to participate in the Plan will be recognized in a manner consistent with Code Section 409A. In the event the respective Participating Subsidiary fails to make such payment or reimbursement, an Eligible Employee’s (or other payee’s) sole recourse shall be against the respective Participating Subsidiary, and not against Company. An Eligible Employee’s participation in the Plan shall constitute agreement with this provision.

11.05    Applicable Law. The provisions of the Plan shall be construed, administered, and enforced in accordance with the laws of the State of California and, to the extent applicable, ERISA. The Plan is intended to comply with the provisions of Code Section 409A. However, Company makes no representation that the benefits provided under the Plan will comply with Code Section 409A and makes no undertaking to prevent Code Section 409A from applying to the benefits provided under the Plan or to mitigate its effects on any deferrals or payments made under the Plan.

11.06    Severability. If any provision of the Plan is held invalid or unenforceable, its invalidity or unenforceability shall not affect any other provisions of the Plan, and the Plan shall be construed and enforced as if such provision had not been included.

11.07    Captions. The captions contained in and the table of contents prefixed to the Plan are inserted only as a matter of convenience and for reference and in no way define, limit, enlarge, or describe the scope or intent of the Plan nor in any way shall affect the construction of any provision of the Plan.

APPENDIX A

PARTICIPATING SUBSIDIARIES

(As of January 1, 2013)

- Pacific Gas and Electric Company

- All U.S. subsidiaries of PG&E Corporation or the above-named corporation(s)

EX-10.11

EXHIBIT 10.11

SEPARATION AGREEMENT

June 3, 2019

Revised June 5, 2019

Revised June 24, 2019

This Separation Agreement (“Agreement”) is made and entered into by and between Jesus Soto and Pacific Gas and Electric Company (the “Company” or “PG&E”) (collectively the “Parties”) and sets forth the terms and conditions of Mr. Soto’s separation from employment with the Company. The “Effective Date” of this Agreement is defined in paragraph 18(a).

1.Resignation. Mr. Soto shall resign from his position as Senior Vice President, Gas Operations effective June 8, 2019. His final day on the payroll shall be July 3, 2019 (for purposes of this Agreement, the “Date of Resignation”). Mr. Soto shall have until July 8, 2019 to accept this Agreement. Regardless of whether Mr. Soto accepts this Agreement, on July 3, 2019, he will be paid all salary or wages and vacation accrued, unpaid and owed to him as of that date, he will remain entitled to any other benefits to which he is otherwise entitled under the provisions of the Company’s plans and programs, and he will receive notice of the right to continue his existing health-insurance coverage pursuant to COBRA.

The benefits set forth in paragraph 2 below are conditioned upon Mr. Soto’s acceptance of this Agreement.

2.Separation benefits. In consideration of his acceptance of this Agreement, the Company will provide to Mr. Soto the following separation benefits:

a.Severance payment. Under the terms of the PG&E Corporation 2012 Officer Severance Policy, Mr. Soto’s severance payment amount is $920,000. (Nine Hundred Twenty Thousand Dollars). Following his execution of this Agreement as set forth in paragraph 18(a) below, provided Mr. Soto files a claim in the Company’s case under chapter 11 of the United States Bankruptcy Code pending in the U.S. Bankruptcy Court, Northern District of California (the “Bankruptcy Court”), In re PG&E Corporation and Pacific Gas and Electric Company (Case No. 19-30088)and such claim is allowed, the Company will treat such claim as provided in a plan of reorganization that is confirmed and becomes effective in such chapter 11 case (the “Plan”).

b.    Stock. Subject to the provisions of the Bankruptcy Code and any orders entered in the Company’s chapter 11 case, upon the date of resignation but conditioned on the occurrence of the Effective Date of this Agreement as set forth in paragraph 18(a) below, all unvested restricted stock unit grants and performance share grants provided to Mr. Soto under PG&E’s 2014 Long-Term Incentive Plan (“LTIP”), shall continue to vest, terminate, or be canceled as provided in the LTIP agreements.    

c.    Career transition services. Subject to the provisions of the Bankruptcy Code and any orders entered in the Company’s chapter 11 case, for a maximum period of one year following July 3, 2019, the Company will provide Mr. Soto with executive career transition services from Lee Hecht Harrison, with total payments to the firm not to exceed $19,000 (Nineteen Thousand Dollars). Lee Hecht Harrison shall bill the Company directly for their services to Mr. Soto. Mr. Soto’s entitlement to services under this Agreement will terminate when he becomes employed, either by another employer or through self-employment other than consulting with the Company.

d.    Payment of COBRA premium. In addition to the severance payment described in paragraph 2(a), provided Mr. Soto files a claim in the Bankruptcy Court in the amount of $48,939 and such claim is allowed, the Company will treat such claim as provided in the Plan. The amount of such claim is the estimated value of his monthly COBRA premiums for the eighteen-month period commencing the first full month after the Date of Resignation.

3.Defense and indemnification in third-party claim. Subject to any restrictions resulting from the Company’s pending chapter 11 case, the Company and/or its affiliate, or subsidiary will provide Mr. Soto with legal representation and indemnification protection in any legal proceeding in which he is a party or is threatened to be made a party by reason of the fact that he is or was an employee or officer of the Company and/or its affiliate or subsidiary, in accordance with the terms of the resolution of the Board of Directors of PG&E dated July 19, 1995, any subsequent PG&E policy or plan providing greater protection to Mr. Soto, or as otherwise required by law.

4.Cooperation with legal proceedings. Mr. Soto will, upon reasonable notice, furnish information and reasonable assistance to the Company and/or its affiliate or subsidiary (including truthful testimony and document production) as may reasonably be required by them or any of them in connection with any legal, administrative or regulatory proceeding in which they or any of them is, or may become, a party, or in connection with any filing or similar obligation imposed by any taxing, administrative or regulatory authority having jurisdiction, provided, however, that the Company and/or its affiliate or subsidiary will pay all reasonable expenses incurred by Mr. Soto in complying with this paragraph.

5.Release of claims and covenant not to sue.

a.In consideration of the benefits the Company is providing under this Agreement, Mr. Soto, on behalf of himself and his representatives, agents, heirs and assigns, waives, releases, discharges and promises never to assert any and all claims, liabilities or obligations of every kind and nature, whether known or unknown, suspected or unsuspected that he ever had, now has or might have as of the Effective Date against the Company or its predecessors, affiliates, subsidiaries, shareholders, owners, directors, officers, employees, agents, attorneys, successors, or assigns. These released claims include, without limitation, any claims arising from or related to Mr. Soto’s employment with the Company, or any of its affiliates and subsidiaries, and the termination of that employment. These released claims also specifically include, but are not limited to, any claims arising under any federal, state and local statutory or common law, such as (as amended and as applicable) Title VII of the Civil Rights Act, the Age Discrimination in Employment Act, the Americans With Disabilities Act, the Employee Retirement Income Security Act, the California Fair Employment and Housing Act, the California Labor Code, any other federal, state or local law governing the terms and conditions of employment or the termination of employment, and the law of contract and tort; and any claim for attorneys’ fees.

b.Mr. Soto acknowledges that there may exist facts or claims in addition to or different from those which are now known or believed by him to exist. Nonetheless, this Agreement extends to all claims of every nature and kind whatsoever, whether known or unknown, suspected or unsuspected, past or present, and Mr. Soto specifically waives all rights under Section 1542 of the California Civil Code which provides that:

A GENERAL RELEASE DOES NOT EXTEND TO CLAIMS THAT THE CREDITOR OR RELEASING PARTY DOES NOT KNOW OR SUSPECT TO EXIST IN HIS OR HER FAVOR AT THE TIME OF EXECUTING THE RELEASE, AND THAT IF KNOWN BY HIM OR HER, WOULD HAVE MATERIALLY AFFECTED HIS OR HIS SETTLEMENT WITH THE DEBTOR OR RELEASED PARTY.

c.With respect to the claims released in the preceding paragraphs, Mr. Soto will not initiate or maintain any legal or administrative action or proceeding of any kind against the Company or its predecessors, affiliates, subsidiaries, shareholders, owners, directors, officers, employees, agents, attorneys, successors, or assigns, for the purpose of obtaining any personal relief, nor (except as otherwise required or permitted by law) assist or participate in any such proceedings, including any proceedings brought by any third parties.

6.Re-employment. Mr. Soto will not seek any future re-employment with the Company, or any of its subsidiaries or affiliates. This paragraph will not, however, preclude Mr. Soto from accepting an offer of future employment from the Company, or any of its subsidiaries or affiliates.

7.Non-disclosure.

a.    Mr. Soto will not disclose, publicize, or circulate to anyone in whole or in part, any information concerning the existence, terms, and/or conditions of this Agreement without the express written consent of the PG&E Corporation’s Chief Executive Officer or, as reasonably necessary to enforce the terms of this Agreement, unless otherwise required or permitted by law or if this Agreement is publicly filed with the Securities and Exchange Commission. Notwithstanding the preceding sentence, Mr. Soto may disclose the terms and conditions of this Agreement to his family members, and any attorneys or tax advisors, if any, to whom there is a bona fide need for disclosure in order for them to render professional services to him, provided that the person first agrees to keep the information confidential and not to make any disclosure of the terms and conditions of this Agreement unless otherwise required or permitted by law or if this Agreement is publicly filed with the Securities and Exchange Commission.

b.    Mr. Soto will not use, disclose, publicize, or circulate any confidential or proprietary

information concerning the Company or its subsidiaries or affiliates, which has come to his attention during his employment with the Company, unless doing so is expressly authorized in writing by PG&E Corporation’s Chief Executive Officer, or is otherwise required or permitted by law. Nothing in this Agreement prohibits Mr. Soto from reporting possible violations of federal law or regulation to any governmental agency or regulatory authority, including but not limited to the U.S. Securities and Exchange Commission, or from making other disclosures that are protected under the whistleblower provisions of federal or state law or regulation.

8.Non-Disparagement. The Parties agree to refrain from performing any act, engaging in any conduct or course of action or making or publishing any statements, claims, allegations or assertions, which have or may reasonably have the effect of demeaning the name or business reputation of the other Party, or in the case of the Company, any of its subsidiaries or affiliates, or any of their respective employees, officers, directors, agents or advisors in their capacities as such or which adversely affects (or may reasonably be expected adversely to affect) the best interests (economic or otherwise) of any of them. Nothing in this paragraph 8 shall preclude either Party from fulfilling any legal duty it may have, including responding to any subpoena or official inquiry from any court or government agency, or from reporting possible violations of federal law or regulation to any governmental agency or regulatory authority, including but not limited to the U.S. Securities and Exchange Commission, or from making other disclosures that are protected under the whistleblower provisions of federal or state law or regulation.

9.No unfair competition.

a.For a period of 12 months after the Effective Date of this Agreement, Mr. Soto will not engage in any unfair competition against the Company, or any of its subsidiaries or affiliates.

b.For a period of 12 months after the Effective Date of this Agreement, Mr. Soto will not, directly or indirectly, solicit or contact for the purpose of diverting or taking away or attempt to solicit or contact for the purpose of diverting or taking away:

(1) any existing customer of the Company or its affiliates or subsidiaries;

(2) any prospective customer of the Company or its affiliates or subsidiaries about whom Mr. Soto acquired information as a result of any solicitation efforts by the Company or its affiliates or subsidiaries, or by the prospective customer, during Mr. Soto’s employment with the Company;

(3) any existing vendor of the Company or its affiliates or subsidiaries;

(4) any prospective vendor of the Company or its affiliates or subsidiaries, about whom Mr. Soto acquired information as a result of any solicitation efforts by the Company or its affiliates or subsidiaries, or by the prospective vendor, during Mr. Soto’s employment with the Company;

(5) any existing employee, agent or consultant of the Company or its affiliates or subsidiaries, to terminate or otherwise alter the person’s or entity’s employment, agency or consultant relationship with the Company or its affiliates or subsidiaries; or

(6) any existing employee, agent or consultant of the Company or its affiliates or subsidiaries, to work in any capacity for or on behalf of any person, Company or other business enterprise that is in competition with the Company or its affiliates or subsidiaries.

10.Material breach by Employee. In the event that Mr. Soto breaches any material provision of this Agreement, including but not necessarily limited to paragraphs 4, 5, 6, 7, 8 and/or 9 and fails to cure said breach upon reasonable notice, the Company will be entitled to recover any actual damages and to recalculate any future pension benefit entitlement without the additional credited age he received or would have received under this Agreement. Despite any breach by Mr. Soto, his other duties and obligations under this Agreement, including his waivers and releases, will remain in full force and effect. In the event of a breach or threatened breach by Mr. Soto of any of the provisions in paragraphs 4, 5, 6, 7, 8, and/or 9, the Company will, in addition to any other remedies provided in this Agreement, be entitled to equitable and/or injunctive relief and because the damages for such a breach or threatened

breach will be difficult to determine and will not provide a full and adequate remedy, the Company will also be entitled to specific performance by Mr. Soto of his obligations under paragraphs 4, 5, 6, 7, 8, and/or 9.

11.Material breach by the Company. Mr. Soto will be entitled to recover actual damages in the event of any material breach of this Agreement by the Company, including any unexcused late or non-payment of any amounts owed under this Agreement, or any unexcused failure to provide any other benefits specified in this Agreement. In the event of a breach or threatened breach by the Company of any of its material obligations to him under this Agreement, Mr. Soto will be entitled to seek, in addition to any other remedies provided in this Agreement, specific performance of the Company’s obligations and any other applicable equitable or injunctive relief.

12.No admission of liability. This Agreement is not, and will not be considered, an admission of liability or of a violation of any applicable contract, law, rule, regulation, or order of any kind.

13.Complete agreement. This Agreement sets forth the entire agreement between the Parties pertaining to the subject matter of this Agreement and fully supersedes any prior or contemporaneous negotiations, representations, agreements, or understandings between the Parties with respect to any such matters, whether written or oral (including any that would have provided Mr. Soto with any different severance arrangements). The Parties acknowledge that they have not relied on any promise, representation or warranty, express or implied, not contained in this Agreement. Parole evidence will be inadmissible to show agreement by and among the Parties to any term or condition contrary to or in addition to the terms and conditions contained in this Agreement.

14.Severability. If any provision of this Agreement is determined to be invalid, void, or unenforceable, the remaining provisions will remain in full force and effect.

15.Arbitration. With the exception of any request for specific performance, injunctive or other equitable relief, any dispute or controversy of any kind arising out of or related to this Agreement, Mr. Soto’s employment with the Company (or with the employing subsidiary), the separation of Mr. Soto from that employment and from his positions as an officer and/or director of the Company or any subsidiary or affiliate, or any claims for benefits, rights under, or interpretation of this Agreement, will be resolved exclusively by final and binding arbitration using one arbitrator in accordance with the Commercial Arbitration Rules of the American Arbitration Association currently in effect, provided, however, that in rendering their award, the arbitrators will be limited to those legal rights and remedies provided for by law. The only claims not covered by this paragraph are any non-waivable claims for benefits under workers’ compensation or unemployment insurance laws, which will be resolved under those laws. Any arbitration pursuant to this paragraph will take place in San Francisco, California. The Parties may be represented by legal counsel at the arbitration but must bear their own fees for such representation in the first instance. The prevailing party in any dispute or controversy covered by this paragraph, or with respect to any request for specific performance, injunctive or other equitable relief in any forum, will be entitled to recover, in addition to any other available remedies specified in this Agreement, all litigation expenses and costs, including any arbitrator, administrative or filing fees and reasonable attorneys’ fees, except as prohibited or limited by law. The Parties specifically waive any right to a jury trial on any dispute or controversy covered by this paragraph. Judgment may be entered on the arbitrators’ award in any court of competent jurisdiction. Subject to the arbitration provisions of this paragraph, the sole jurisdiction and venue for any action related to the subject matter of this Agreement will be the California state and federal courts having within their jurisdiction the location of the Company’s principal place of business in California at the time of such action, and both Parties thereby consent to the jurisdiction of such courts for any such action.

16.Governing law. This Agreement will be governed by and construed under the laws of the United States and, to the extent not preempted by such laws, by the laws of the State of California, without regard to their conflicts of laws provisions.

17.No waiver. The failure of either Party to exercise or enforce, at any time, or for any period of time, any of the provisions of this Agreement will not be construed as a waiver of that provision, or any portion of that provision, and will in no way affect that party’s right to exercise or enforce such provisions. No waiver or default of any provision of this Agreement will be deemed to be a waiver of any succeeding breach of the same or any other provisions of this Agreement.

18.Acceptance of Agreement.

a.Mr. Soto was provided up to 21 days to consider and accept the terms of this Agreement but was advised he may execute this Agreement at his discretion prior to his Date of Resignation. He was also advised to

consult with an attorney about the Agreement before signing it. The provisions of the Agreement are, however, not subject to negotiation. After signing the Agreement, Mr. Soto will have an additional seven (7) days in which to revoke in writing acceptance of this Agreement. To revoke, Mr. Soto will submit a signed statement to that effect to PG&E Corporation’s Chief Executive Officer before the close of business on the seventh day. If Mr. Soto does not submit a timely revocation, the Effective Date of this Agreement will be the eighth day after he has signed it.

b.Mr. Soto acknowledges reading and understanding the contents of this Agreement, being afforded the opportunity to review carefully this Agreement with an attorney of his choice, not relying on any oral or written representation not contained in this Agreement, signing this Agreement knowingly and voluntarily, and, after the Effective Date of this Agreement, being bound by its’ provisions.

Dated:	8/5/2019	PACIFIC GAS AND ELECTRIC COMPANY
		By:	/s/ DINYAR B. MISTRY
Dated:	7/8/2019		JESUS SOTO
			/s/JESUS SOTO

EX-31.1

EXHIBIT 31.01

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, William D. Johnson, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended June 30, 2019 of PG&E Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 9, 2019	/s/ WILLIAM D. JOHNSON
	William D. Johnson
	Chief Executive Officer and President

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Jason P. Wells, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended June 30, 2019 of PG&E Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 9, 2019	/s/ JASON P. WELLS
	Jason P. Wells
	Executive Vice President and Chief Financial Officer

EX-31.2

EXHIBIT 31.02

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Michael A. Lewis, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended June 30, 2019 of Pacific Gas and Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 9, 2019	/s/ MICHAEL A. LEWIS
	Michael A. Lewis
	Senior Vice President, Electric Operations

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, Melvin J. Christopher, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended June 30, 2019 of Pacific Gas and Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 9, 2019	/s/ MELVIN J. CHRISTOPHER
	Melvin J. Christopher
	Vice President, Gas Operations

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, James M. Welsch, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended June 30, 2019 of Pacific Gas and Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 9, 2019	/s/ JAMES M. WELSCH
	James M. Welsch
	Senior Vice President and Chief Nuclear Officer

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO SECURITIES AND EXCHANGE COMMISSION RULE 13a-14(a)

I, David S. Thomason, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the quarter ended June 30, 2019 of Pacific Gas and Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 9, 2019	/s/ DAVID S. THOMASON
	David S. Thomason
	Vice President, Chief Financial Officer and Controller

EX-32.1

EXHIBIT 32.01

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended June 30, 2019 (“Form 10-Q”), I, William D. Johnson, Chief Executive Officer and President of PG&E Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1) the Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of PG&E Corporation.

/s/ WILLIAM D. JOHNSON

William D. Johnson

Chief Executive Officer and President

August 9, 2019

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of PG&E Corporation for the quarter ended June 30, 2019 (“Form 10-Q”), I, Jason P. Wells, Executive Vice President and Chief Financial Officer of PG&E Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1) the Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of PG&E Corporation.

/s/ JASON P. WELLS

Jason P. Wells

Executive Vice President and

Chief Financial Officer

August 9, 2019

EX-32.2

EXHIBIT 32.02

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended June 30, 2019 (“Form 10-Q”), I, Michael A. Lewis, Senior Vice President, Electric Operations of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1) the Form 10-Q fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company.

/s/ MICHAEL A. LEWIS

Michael A. Lewis

Senior Vice President, Electric Operations

August 9, 2019

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended June 30, 2019 (“Form 10-Q”), I, Melvin J. Christopher, Vice President, Gas Operations of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1) the Form 10-Q fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company.

/s/ MELVIN J. CHRISTOPHER

Melvin J. Christopher

Vice President, Gas Operations

August 9, 2019

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended June 30, 2019 (“Form 10-Q”), I, James M. Welsch, Senior Vice President and Chief Nuclear Officer of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1) the Form 10-Q fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company.

/s/ JAMES M. WELSCH

James M. Welsch

Senior Vice President and Chief Nuclear Officer

August 9, 2019

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the accompanying Quarterly Report on Form 10-Q of Pacific Gas and Electric Company for the quarter ended June 30, 2019 (“Form 10-Q”), I, David S. Thomason, Vice President, Chief Financial Officer and Controller of Pacific Gas and Electric Company, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge and belief, that:

(1) the Form 10-Q fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pacific Gas and Electric Company.

/s/ DAVID S. THOMASON

David S. Thomason

Vice President, Chief Financial Officer and Controller

August 9, 2019

XML

Cover Page - shares	6 Months Ended
	Jun. 30, 2019	Aug. 02, 2019
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2019
Document Transition Report	false
Entity File Number	1-12609
Entity Registrant Name	PG&E CORP
Entity Incorporation, State or Country Code	CA
Entity Tax Identification Number	94-3234914
Entity Address, Address Line One	77 Beale Street
Entity Address, Address Line Two	P.O. Box 770000
Entity Address, City or Town	San Francisco,
Entity Address, State or Province	CA
Entity Address, Postal Zip Code	94177
City Area Code	415
Local Phone Number	973-1000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)		529,223,793
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Entity Central Index Key	0001004980
Pacific Gas & Electric Co
Entity Information [Line Items]
Entity File Number	1-2348
Entity Registrant Name	PACIFIC GAS & ELECTRIC CO
Entity Incorporation, State or Country Code	CA
Entity Tax Identification Number	94-0742640
Entity Address, Address Line One	77 Beale Street
Entity Address, Address Line Two	P.O. Box 770000
Entity Address, City or Town	San Francisco,
Entity Address, State or Province	CA
Entity Address, Postal Zip Code	94177
City Area Code	415
Local Phone Number	973-7000
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)		264,374,809
Entity Central Index Key	0000075488
The New York Stock Exchange | Common stock, no par value
Entity Information [Line Items]
Title of 12(b) Security	Common stock, no par value
Trading Symbol	PCG
Security Exchange Name	NYSE
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% series A redeemable
Entity Information [Line Items]
Title of 12(b) Security	First preferred stock, cumulative, par value $25 per share, 5% series A redeemable
Trading Symbol	PCG-PE
Security Exchange Name	NYSEAMER
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% redeemable
Entity Information [Line Items]
Title of 12(b) Security	First preferred stock, cumulative, par value $25 per share, 5% redeemable
Trading Symbol	PCG-PD
Security Exchange Name	NYSEAMER
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 4.80% redeemable
Entity Information [Line Items]
Title of 12(b) Security	First preferred stock, cumulative, par value $25 per share, 4.80% redeemable
Trading Symbol	PCG-PG
Security Exchange Name	NYSEAMER
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 4.50% redeemable
Entity Information [Line Items]
Title of 12(b) Security	First preferred stock, cumulative, par value $25 per share, 4.50% redeemable
Trading Symbol	PCG-PH
Security Exchange Name	NYSEAMER
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable
Entity Information [Line Items]
Title of 12(b) Security	First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable
Trading Symbol	PCG-PI
Security Exchange Name	NYSEAMER
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 6% nonredeemable
Entity Information [Line Items]
Title of 12(b) Security	First preferred stock, cumulative, par value $25 per share, 6% nonredeemable
Trading Symbol	PCG-PA
Security Exchange Name	NYSEAMER
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable
Entity Information [Line Items]
Title of 12(b) Security	First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable
Trading Symbol	PCG-PB
Security Exchange Name	NYSEAMER
NYSE American LLC | First preferred stock, cumulative, par value $25 per share, 5% nonredeemable
Entity Information [Line Items]
Title of 12(b) Security	First preferred stock, cumulative, par value $25 per share, 5% nonredeemable
Trading Symbol	PCG-PC
Security Exchange Name	NYSEAMER

XML

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Operating Revenues
Total operating revenues	$ 3,943	$ 4,234	$ 7,954	$ 8,290
Operating Expenses
Operating and maintenance	1,942	1,786	4,029	3,390
Wildfire-related claims, net of insurance recoveries	3,900	2,125	3,900	2,118
Depreciation, amortization, and decommissioning	796	746	1,593	1,498
Total operating expenses	7,583	5,699	11,405	9,156
Operating Loss	(3,640)	(1,465)	(3,451)	(866)
Interest income	22	12	44	21
Interest expense	(60)	(226)	(163)	(446)
Other income, net	66	106	137	214
Reorganization items, net	(56)	0	(183)	0
Loss Before Income Taxes	(3,668)	(1,573)	(3,616)	(1,077)
Income tax benefit	(1,119)	(593)	(1,203)	(542)
Net Loss	(2,549)	(980)	(2,413)	(535)
Preferred stock dividend requirement of subsidiary	4	4	7	7
Loss Attributable to Common Shareholders	$ (2,553)	$ (984)	$ (2,420)	$ (542)
Weighted Average Common Shares Outstanding, Basic (in shares)	529	516	528	516
Weighted Average Common Shares Outstanding, Diluted (in shares)	529	516	528	517
Net Loss Per Common Share, Basic (in dollars per share)	$ (4.83)	$ (1.91)	$ (4.58)	$ (1.05)
Net Loss Per Common Share, Diluted (in dollars per share)	$ (4.83)	$ (1.91)	$ (4.58)	$ (1.05)
Pacific Gas & Electric Co
Operating Revenues
Total operating revenues	$ 3,943	$ 4,234	$ 7,954	$ 8,290
Operating Expenses
Operating and maintenance	1,940	1,786	4,044	3,390
Wildfire-related claims, net of insurance recoveries	3,900	2,125	3,900	2,118
Depreciation, amortization, and decommissioning	796	746	1,593	1,498
Total operating expenses	7,581	5,699	11,420	9,156
Operating Loss	(3,638)	(1,465)	(3,466)	(866)
Interest income	22	11	43	20
Interest expense	(60)	(222)	(161)	(439)
Other income, net	64	108	130	217
Reorganization items, net	(57)	0	(168)	0
Loss Before Income Taxes	(3,669)	(1,568)	(3,622)	(1,068)
Income tax benefit	(1,119)	(592)	(1,205)	(544)
Net Loss	(2,550)	(976)	(2,417)	(524)
Preferred stock dividend requirement of subsidiary	4	4	7	7
Loss Attributable to Common Shareholders	(2,554)	(980)	(2,424)	(531)
Electric
Operating Revenues
Total operating revenues	2,946	3,312	5,738	6,263
Operating Expenses
Cost of goods	837	963	1,436	1,782
Electric | Pacific Gas & Electric Co
Operating Revenues
Total operating revenues	2,946	3,312	5,738	6,263
Operating Expenses
Cost of goods	837	963	1,436	1,782
Natural gas
Operating Revenues
Total operating revenues	997	922	2,216	2,027
Operating Expenses
Cost of goods	108	79	447	368
Natural gas | Pacific Gas & Electric Co
Operating Revenues
Total operating revenues	997	922	2,216	2,027
Operating Expenses
Cost of goods	$ 108	$ 79	$ 447	$ 368

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Net Loss	$ (2,549)	$ (980)	$ (2,413)	$ (535)
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes)	0	0	0	0
Total other comprehensive income	0	0	0	0
Comprehensive Loss	(2,549)	(980)	(2,413)	(535)
Preferred stock dividend requirement of subsidiary	4	4	7	7
Comprehensive Loss Attributable to Common Shareholders	(2,553)	(984)	(2,420)	(542)
Pacific Gas & Electric Co
Net Loss	(2,550)	(976)	(2,417)	(524)
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes)	0	1	0	1
Total other comprehensive income	0	1	0	1
Comprehensive Loss	$ (2,550)	$ (975)	$ (2,417)	$ (523)

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Pension and other postretirement benefit plans obligations tax	$ 0	$ 0	$ 0	$ 0
Pacific Gas & Electric Co
Pension and other postretirement benefit plans obligations tax	$ 0	$ 0	$ 0	$ 0

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CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Current Assets
Cash and cash equivalents	$ 3,459	$ 1,668
Accounts receivable:
Customers (net of allowance for doubtful accounts of $39 and $56 at respective dates)	1,260	1,148
Accrued unbilled revenue	991	1,000
Regulatory balancing accounts	1,884	1,435
Other	2,610	2,686
Regulatory assets	212	233
Inventories:
Gas stored underground and fuel oil	99	111
Materials and supplies	509	443
Income taxes receivable	18	23
Other	535	448
Total current assets	11,577	9,195
Property, Plant, and Equipment
Electric	60,967	59,150
Gas	22,428	21,556
Construction work in progress	2,563	2,564
Other	20	2
Total property, plant, and equipment	85,978	83,272
Accumulated depreciation	(25,727)	(24,715)
Net property, plant, and equipment	60,251	58,557
Other Noncurrent Assets
Regulatory assets	5,349	4,964
Nuclear decommissioning trusts	3,016	2,730
Operating lease right of use asset	2,662
Income taxes receivable	67	69
Other	1,465	1,480
Total other noncurrent assets	12,559	9,243
TOTAL ASSETS	84,387	76,995
Current Liabilities
Short-term borrowings	0	3,435
Long-term debt, classified as current	0	18,559
Accounts payable:
Trade creditors	1,679	1,975
Regulatory balancing accounts	1,370	1,076
Other	593	464
Operating lease liabilities	546
Disputed claims and customer refunds	0	220
Interest payable	5	228
Wildfire-related claims	100	14,226
Other	1,418	1,512
Total current liabilities	5,711	41,695
Noncurrent Liabilities
Debtor-in-possession financing	1,500	0
Regulatory liabilities	9,038	8,539
Pension and other post-retirement benefits	1,996	2,119
Asset retirement obligations	6,111	5,994
Deferred income taxes	2,354	3,281
Operating lease liabilities	2,116
Other	2,357	2,464
Total noncurrent liabilities	25,472	22,397
Liabilities Subject to Compromise	42,610	0
Shareholders’ Equity
Common stock	13,014	12,910
Reinvested earnings	(2,663)	(250)
Accumulated other comprehensive loss	(9)	(9)
Total shareholders’ equity	10,342	12,651
Noncontrolling Interest - Preferred Stock of Subsidiary	252	252
Total equity	10,594	12,903
TOTAL LIABILITIES AND EQUITY	84,387	76,995
Pacific Gas & Electric Co
Current Assets
Cash and cash equivalents	3,036	1,295
Accounts receivable:
Customers (net of allowance for doubtful accounts of $39 and $56 at respective dates)	1,260	1,148
Accrued unbilled revenue	991	1,000
Regulatory balancing accounts	1,884	1,435
Other	2,621	2,688
Regulatory assets	212	233
Inventories:
Gas stored underground and fuel oil	99	111
Materials and supplies	509	443
Income taxes receivable	1	5
Other	535	448
Total current assets	11,148	8,806
Property, Plant, and Equipment
Electric	60,967	59,150
Gas	22,428	21,556
Construction work in progress	2,563	2,564
Other	18	0
Total property, plant, and equipment	85,976	83,270
Accumulated depreciation	(25,725)	(24,713)
Net property, plant, and equipment	60,251	58,557
Other Noncurrent Assets
Regulatory assets	5,349	4,964
Nuclear decommissioning trusts	3,016	2,730
Operating lease right of use asset	2,653
Income taxes receivable	66	66
Other	1,325	1,348
Total other noncurrent assets	12,409	9,108
TOTAL ASSETS	83,808	76,471
Current Liabilities
Short-term borrowings	0	3,135
Long-term debt, classified as current	0	18,209
Accounts payable:
Trade creditors	1,678	1,972
Regulatory balancing accounts	1,370	1,076
Other	688	498
Operating lease liabilities	543
Disputed claims and customer refunds	0	220
Interest payable	5	227
Wildfire-related claims	100	14,226
Other	1,420	1,497
Total current liabilities	5,804	41,060
Noncurrent Liabilities
Debtor-in-possession financing	1,500	0
Regulatory liabilities	9,038	8,539
Pension and other post-retirement benefits	1,996	2,026
Asset retirement obligations	6,111	5,994
Deferred income taxes	2,474	3,405
Operating lease liabilities	2,110
Other	2,408	2,492
Total noncurrent liabilities	25,637	22,456
Liabilities Subject to Compromise	41,829	0
Shareholders’ Equity
Preferred stock	258	258
Common stock	1,322	1,322
Additional paid-in capital	8,550	8,550
Reinvested earnings	409	2,826
Accumulated other comprehensive loss	(1)	(1)
Total shareholders’ equity	10,538	12,955
TOTAL LIABILITIES AND EQUITY	$ 83,808	$ 76,471

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CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Allowance for doubtful accounts	$ 39	$ 56
Common stock, shares authorized (in shares)	800,000,000	800,000,000
Common stock, shares outstanding (in shares)	529,223,793	520,338,710
Pacific Gas & Electric Co
Allowance for doubtful accounts	$ 39	$ 56
Common stock, par value (in dollars per share)	$ 5	$ 5
Common stock, shares authorized (in shares)	800,000,000	800,000,000
Common stock, shares outstanding (in shares)	264,374,809	264,374,809

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Cash Flows from Operating Activities
Net Loss	$ (2,413)	$ (535)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	1,593	1,498
Allowance for equity funds used during construction	(45)	(63)
Deferred income taxes and tax credits, net	(915)	(145)
Reorganization items, net (Note 2)	90	0
Other	53	104
Effect of changes in operating assets and liabilities:
Accounts receivable	(54)	(11)
Wildfire-related insurance receivable	35	(144)
Inventories	(41)	(6)
Accounts payable	159	39
Wildfire-related claims	(14)	2,299
Income taxes receivable/payable	5	0
Other current assets and liabilities	(15)	(103)
Regulatory assets, liabilities, and balancing accounts, net	(34)	(12)
Liabilities subject to compromise	4,221	0
Other noncurrent assets and liabilities	132	(168)
Net cash provided by operating activities	2,757	2,753
Cash Flows from Investing Activities
Capital expenditures	(2,410)	(2,897)
Proceeds from sales and maturities of nuclear decommissioning trust investments	517	802
Purchases of nuclear decommissioning trust investments	(547)	(815)
Other	6	15
Net cash used in investing activities	(2,434)	(2,895)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	1,850	0
Repayments of debtor-in-possession credit facility	(350)	0
Debtor-in-possession credit facility debt issuance costs	(111)	0
Borrowings under revolving credit facilities	0	700
Net repayments of commercial paper, net of discount	0	(182)
Short-term debt financing	0	250
Short-term debt matured	0	(250)
Proceeds from issuance of long-term debt, net of discount and issuance costs	0	350
Long-term debt matured or repurchased	0	(750)
Common stock issued	85	82
Other	(6)	10
Net cash provided by financing activities	1,468	210
Net change in cash, cash equivalents, and restricted cash	1,791	68
Cash, cash equivalents, and restricted cash at January 1	1,675	456
Cash, cash equivalents, and restricted cash at June 30	3,466	524
Less: Restricted cash and restricted cash equivalents included in other current assets	(7)	(7)
Cash and cash equivalents at June 30	3,459	517
Supplemental disclosures of cash flow information
Interest, net of amounts capitalized	(21)	(394)
Supplemental disclosures of noncash operating activities
Operating lease liabilities arising from obtaining ROU assets	2,816	0
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	836	317
Pacific Gas & Electric Co
Cash Flows from Operating Activities
Net Loss	(2,417)	(524)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	1,593	1,498
Allowance for equity funds used during construction	(45)	(63)
Deferred income taxes and tax credits, net	(920)	(149)
Reorganization items, net (Note 2)	91	0
Other	34	57
Effect of changes in operating assets and liabilities:
Accounts receivable	(64)	(11)
Wildfire-related insurance receivable	35	(144)
Inventories	(41)	(6)
Accounts payable	206	40
Wildfire-related claims	(14)	2,299
Income taxes receivable/payable	4	0
Other current assets and liabilities	(8)	(95)
Regulatory assets, liabilities, and balancing accounts, net	(34)	(12)
Liabilities subject to compromise	4,215	0
Other noncurrent assets and liabilities	141	(168)
Net cash provided by operating activities	2,776	2,722
Cash Flows from Investing Activities
Capital expenditures	(2,410)	(2,897)
Proceeds from sales and maturities of nuclear decommissioning trust investments	517	802
Purchases of nuclear decommissioning trust investments	(547)	(815)
Other	6	15
Net cash used in investing activities	(2,434)	(2,895)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	1,850	0
Repayments of debtor-in-possession credit facility	(350)	0
Debtor-in-possession credit facility debt issuance costs	(95)	0
Borrowings under revolving credit facilities	0	650
Net repayments of commercial paper, net of discount	0	(50)
Short-term debt financing	0	250
Short-term debt matured	0	(250)
Long-term debt matured or repurchased	0	(400)
Other	(6)	10
Net cash provided by financing activities	1,399	210
Net change in cash, cash equivalents, and restricted cash	1,741	37
Cash, cash equivalents, and restricted cash at January 1	1,302	454
Cash, cash equivalents, and restricted cash at June 30	3,043	491
Less: Restricted cash and restricted cash equivalents included in other current assets	(7)	(7)
Cash and cash equivalents at June 30	3,036	484
Supplemental disclosures of cash flow information
Interest, net of amounts capitalized	(19)	(387)
Supplemental disclosures of noncash operating activities
Operating lease liabilities arising from obtaining ROU assets	2,807	0
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$ 836	$ 317

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Parenthetical) $ in Millions	6 Months Ended
	Jun. 30, 2018 USD ($)
Statement of Cash Flows [Abstract]
Discount on net issuances of commercial paper	$ 1

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CONDENSED CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Millions	Total	Common Stock	Reinvested Earnings	Accumulated Other Comprehensive Income (Loss)	Total Shareholders’ Equity	Non controlling Interest - Preferred Stock of Subsidiary	Pacific Gas & Electric Co	Pacific Gas & Electric Co Preferred Stock	Pacific Gas & Electric Co Common Stock	Pacific Gas & Electric Co Additional Paid-in Capital	Pacific Gas & Electric Co Reinvested Earnings	Pacific Gas & Electric Co Accumulated Other Comprehensive Income (Loss)	Pacific Gas & Electric Co Total Shareholders’ Equity
Beginning balance (in shares) at Dec. 31, 2017		514,755,845
Beginning balance at Dec. 31, 2017	$ 19,472	$ 12,632	$ 6,596	$ (8)	$ 19,220	$ 252		$ 258	$ 1,322	$ 8,505	$ 9,656	$ 6	$ 19,747
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss											452		452
Other comprehensive income (loss)											2	(2)
Preferred stock dividend											(3)		(3)
Ending balance at Mar. 31, 2018								258	1,322	8,505	10,107	4	20,196
Beginning balance (in shares) at Dec. 31, 2017		514,755,845
Beginning balance at Dec. 31, 2017	19,472	$ 12,632	6,596	(8)	19,220	252		258	1,322	8,505	9,656	6	19,747
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss	(535)						$ (524)
Ending balance (in shares) at Jun. 30, 2018		517,102,983
Ending balance at Jun. 30, 2018	19,061	$ 12,763	6,059	(13)	18,809	252		258	1,322	8,505	9,127	5	19,217
Beginning balance at Mar. 31, 2018								258	1,322	8,505	10,107	4	20,196
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss	(980)		(980)		(980)		$ (976)				(976)		(976)
Other comprehensive income (loss)	0			0	0							1	1
Common stock issued, net (in shares)		1,099,026
Common stock issued, net	47	$ 47			47
Stock-based compensation amortization	15	$ 15			15
Preferred stock dividend requirement of subsidiary	(4)		(4)		(4)
Preferred stock dividend											(4)		(4)
Ending balance (in shares) at Jun. 30, 2018		517,102,983
Ending balance at Jun. 30, 2018	$ 19,061	$ 12,763	6,059	(13)	18,809	252		258	1,322	8,505	9,127	5	19,217
Beginning balance (in shares) at Dec. 31, 2018	520,338,710	520,338,710					264,374,809
Beginning balance at Dec. 31, 2018	$ 12,903	$ 12,910	(250)	(9)	12,651	252		258	1,322	8,550	2,826	(1)	12,955
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss	136		136		136						133		133
Common stock issued, net (in shares)		8,871,568
Common stock issued, net	85	$ 85			85
Stock-based compensation amortization	5	$ 5			5
Ending balance (in shares) at Mar. 31, 2019		529,210,278
Ending balance at Mar. 31, 2019	$ 13,129	$ 13,000	(114)	(9)	12,877	252		258	1,322	8,550	2,959	(1)	13,088
Beginning balance (in shares) at Dec. 31, 2018	520,338,710	520,338,710					264,374,809
Beginning balance at Dec. 31, 2018	$ 12,903	$ 12,910	(250)	(9)	12,651	252		258	1,322	8,550	2,826	(1)	12,955
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss	$ (2,413)						$ (2,417)
Ending balance (in shares) at Jun. 30, 2019	529,223,793	529,223,793					264,374,809
Ending balance at Jun. 30, 2019	$ 10,594	$ 13,014	(2,663)	(9)	10,342	252		258	1,322	8,550	409	(1)	10,538
Beginning balance (in shares) at Mar. 31, 2019		529,210,278
Beginning balance at Mar. 31, 2019	13,129	$ 13,000	(114)	(9)	12,877	252		258	1,322	8,550	2,959	(1)	13,088
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss	(2,549)		(2,549)		(2,549)		$ (2,550)				(2,550)		(2,550)
Common stock issued, net (in shares)		13,515
Stock-based compensation amortization	$ 14	$ 14			14
Ending balance (in shares) at Jun. 30, 2019	529,223,793	529,223,793					264,374,809
Ending balance at Jun. 30, 2019	$ 10,594	$ 13,014	$ (2,663)	$ (9)	$ 10,342	$ 252		$ 258	$ 1,322	$ 8,550	$ 409	$ (1)	$ 10,538

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ORGANIZATION AND BASIS OF PRESENTATION

6 Months Ended

Jun. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

ORGANIZATION AND BASIS OF PRESENTATION

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 (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented.  The information at December 31, 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 pre-petition liabilities. 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 Chapter 11, 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.)

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BANKRUPTCY FILING

6 Months Ended

Jun. 30, 2019

Reorganizations [Abstract]

BANKRUPTCY FILING

BANKRUPTCY FILING

Chapter 11 Proceedings

On January 29, 2019, PG&E Corporation and the Utility filed 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 administered under a Chapter 11 plan of reorganization to be voted upon by creditors and other stakeholders, and approved by the Bankruptcy Court. However, under the Bankruptcy Code, regulatory or criminal proceedings are generally not subject to an automatic stay, and PG&E Corporation and the Utility expect these proceedings to continue 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

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.

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”). Pursuant to the Exclusivity Order, PG&E Corporation’s and the Utility’s Exclusive Filing Period is extended to, and including, September 26, 2019, and PG&E Corporation’s and the Utility’s Exclusive Solicitation Period is 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 Filing Period and the Exclusive Solicitation Period.  The Ad Hoc Noteholder Committee annexed to its motion a “Term Sheet for Plan of Reorganization.”  On July 17, 2019, the Ad Hoc Noteholder Committee filed with the Bankruptcy Court an amended version of the term sheet, along with a commitment letter with respect to certain financings described therein.  Certain third parties have filed joinders and statements in support with the Bankruptcy Court with respect to the Ad Hoc Noteholder Committee’s motion, but such parties have not taken any position on the plan construct described by the term sheet.  These third parties include TURN, two collective bargaining units representing the Utility’s employees, and the UCC. 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.  Also on July 18, 2019, the Ad Hoc Group of Subrogation Claim Holders (the “Ad Hoc Subrogation Group”), the TCC, and certain owners of common stock of PG&E Corporation (the “Shareholder Group”) filed objections to the Ad Hoc Noteholder Committee’s motion with the Bankruptcy Court. At a hearing on July 24, 2019, the Bankruptcy Court granted an oral motion of the CPUC and the Governor’s office to adjourn the hearing on the Ad Hoc Noteholder Committee’s motion from July 24, 2019 to August 13, 2019, to allow PG&E Corporation and the Utility, the CPUC, the Governor’s office, and other parties in interest time to engage in discussions regarding the formulation of a potential protocol for the efficient submission and consideration of Chapter 11 plan proposals. The parties are due to provide a status update on these discussions to the Bankruptcy Court on August 9, 2019. On August 7, 2019, the Ad Hoc Noteholder Committee submitted a statement with the Bankruptcy Court, criticizing the protocol proposed by the CPUC and including as an exhibit its own proposed “Alternative Protocol” to govern a competitive plan process. In addition, the Ad Hoc Noteholder Committee annexed to its statement a second amended version of the term sheet and a revised version of the commitment letter.

On July 23, 2019, the Ad Hoc Subrogation Group submitted its own motion, pursuant to section 1121(d)(1) of the Bankruptcy Code, to terminate the Exclusive Filing Period and the Exclusive Solicitation Period, which included as an exhibit a “Restructuring Term Sheet.” The hearing before the Bankruptcy Court on the Ad Hoc Subrogation Group’s motion is scheduled for August 13, 2019. 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. Also on August 6, 2019, the UCC filed a statement in opposition with respect to the Ad Hoc Subrogation Group’s motion, and the Shareholder Group filed an objection to the Ad Hoc Subrogation Group’s motion, both requesting that the motion be denied.

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.

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.

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 June 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 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 June 30, 2019:

(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Financing debt (2)	$	21,811	$	650	$	22,461
Wildfire-related claims (3)	18,012		—		18,012
Trade creditors	1,325		4		1,329
Non-qualified benefit plan	18		125		143
2001 bankruptcy disputed claims	221		—		221
Customer deposits & advances	278		—		278
Other	164		2		166
Total Liabilities Subject to Compromise	$	41,829	$	781	$	42,610

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

⁽²⁾ At June 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 $285 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. As described in Note 10 under the heading “Plan Support Agreements with Public Entities,” on June 18, 2019, PG&E Corporation and the Utility entered into agreements with certain local public entities to potentially resolve their wildfire-related claims through the Chapter 11 process.

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. 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. 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.

Numerous claims have been filed with the Bankruptcy Court against PG&E Corporation and the Utility relating to the period prior to the Petition Date and it is expected that new and amended claims will continue to be filed until the Bar Date, including claims amended to assign value to claims originally filed with no designated value. Through the claims resolution process, differences in amounts scheduled by PG&E Corporation and the Utility and claims filed by creditors will be investigated and resolved, including through the filing of objections with the Bankruptcy Court where appropriate. In light of the substantial number and amount of claims filed, the claims resolution process may take considerable time to complete and will likely continue after PG&E Corporation and the Utility emerge from bankruptcy. The ultimate number and amount of allowed claims is not determinable at this time.

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 $15 million and $78 million for PG&E Corporation and the Utility, respectively, during the six months ended June 30, 2019. Reorganization items, net for the three months ended June 30, 2019 and from the Petition Date through June 30, 2019 include the following:

	Three Months Ended June 30, 2019
(in millions)	Utility			PG&E Corporation (1)			PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	—		$	—		$	—
Legal and other	75			1			76
Interest income	(18		)	(3		)	(21		)
Adjustments to LSTC	—			—			—
Trustee fees (2)	—			1			1
Total reorganization items, net	$	57		$	(1	)	$	56

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

⁽²⁾ PG&E Corporation and the Utility incurred $416,667 and $250,000, respectively, in fees to the U.S. Trustee in the three months ended June 30, 2019.

	Petition Date Through June 30, 2019
(in millions)	Utility			PG&E Corporation (1)			PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	97		$	17		$	114
Legal and other	98			2			100
Interest income	(27		)	(5		)	(32		)
Adjustments to LSTC	—			—			—
Trustee fees (2)	—			1			1
Total reorganization items, net	$	168		$	15		$	183

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

⁽²⁾ PG&E Corporation and the Utility incurred $416,667 and $250,000, respectively, in fees to the U.S. Trustee through June 30, 2019.

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 June 30, 2019, contractual interest expense of $405 million related to LSTC has not been recorded in the financial statements. The portion of authorized revenues from the Petition Date through June 30, 2019 related to interest expense on pre-petition debt has been deferred as a non-current 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 & 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.

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. In addition, on June 26, 2019, the Utility filed a petition for review of those earlier FERC orders also in the Ninth Circuit.

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.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

6 Months Ended

Jun. 30, 2019

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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.

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 June 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 June 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 six months ended June 30, 2019 and 2018 were as follows:

	Pension Benefits						Other Benefits
	Three Months Ended June 30,
(in millions)	2019			2018			2019			2018
Service cost for benefits earned (1)	$	111		$	129		$	14		$	17
Interest cost	190			172			19			18
Expected return on plan assets	(226		)	(256		)	(30		)	(32		)
Amortization of prior service cost	(2		)	(2		)	3			3
Amortization of net actuarial loss	—			2			(1		)	(2		)
Net periodic benefit cost	73			45			5			4
Regulatory account transfer (2)	10			39			—			—
Total	$	83		$	84		$	5		$	4

⁽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.

	Pension Benefits						Other Benefits
	Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Service cost for benefits earned (1)	$	222		$	257		$	28		$	33
Interest cost	379			344			38			35
Expected return on plan assets	(453		)	(511		)	(61		)	(65		)
Amortization of prior service cost	(3		)	(3		)	7			7
Amortization of net actuarial loss	1			3			(2		)	(3		)
Net periodic benefit cost	146			90			10			7
Regulatory account transfer (2)	21			77			—			—
Total	$	167		$	167		$	10		$	7

⁽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 June 30, 2019
Beginning balance	$	(21	)	$	17		$	(4	)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $1 and $1, respectively) (1)	(1		)	2			1
Amortization of net actuarial loss (net of taxes of $0 and $1, respectively) (1)	—			—			—
Regulatory account transfer (net of taxes of $1 and $0, respectively) (1)	1			(2		)	(1		)
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)	Three Months Ended June 30, 2018
Beginning balance	$	(30	)	$	17		$	(13	)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1 and $1, respectively)	(1		)	2			1
Amortization of net actuarial loss (net of taxes of $1 and $1, respectively)	1			(1		)	—
Regulatory account transfer (net of taxes of $0 and $0, respectively)	—			(1		)	(1		)
Net current period other comprehensive gain (loss)	—			—			—
Ending balance	$	(30	)	$	17		$	(13	)

⁽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)	Six Months Ended June 30, 2019
Beginning balance	$	(21	)	$	17		$	(4	)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $1 and $2, respectively) (1)	(2		)	5			3
Amortization of net actuarial loss (net of taxes of $0 and $1, respectively) (1)	1			(1		)	—
Regulatory account transfer (net of taxes of $1 and $1, respectively) (1)	1			(4		)	(3		)
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)	Six Months Ended June 30, 2018
Beginning balance	$	(25	)	$	17		$	(8	)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $1 and $2, respectively) (1)	(2		)	5			3
Amortization of net actuarial loss (net of taxes of $1 and $1, respectively) (1)	2			(2		)	—
Regulatory account transfer (net of taxes of $0 and $1, respectively) (1)	—			(3		)	(3		)
Reclassification of stranded income tax to retained earnings	(5		)	—			(5		)
Net current period other comprehensive gain (loss)	(5		)	—			(5		)
Ending balance	$	(30	)	$	17		$	(13	)

⁽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.

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.

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

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Electric
Revenue from contracts with customers
Residential	$	994		$	1,039		$	2,282		$	2,375
Commercial	1,135			1,234			2,088			2,307
Industrial	326			354			619			678
Agricultural	261			318			347			443
Public street and highway lighting	16			18			33			38
Other (1)	—			84			(309		)	(118		)
Total revenue from contracts with customers - electric	2,732			3,047			5,060			5,723
Regulatory balancing accounts (2)	214			265			678			540
Total electric operating revenue	$	2,946		$	3,312		$	5,738		$	6,263
Natural gas
Revenue from contracts with customers
Residential	$	343		$	452		$	1,515		$	1,410
Commercial	129			119			369			315
Transportation service only	304			264			686			560
Other (1)	(129		)	(128		)	(205		)	(179		)
Total revenue from contracts with customers - gas	647			707			2,365			2,106
Regulatory balancing accounts (2)	350			215			(149		)	(79		)
Total natural gas operating revenue	997			922			2,216			2,027
Total operating revenues	$	3,943		$	4,234		$	7,954		$	8,290

⁽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 amends the guidance relating to the definition of a lease, the recognition of lease assets and lease liabilities on the balance sheet, and the disclosure of key information about leasing arrangements.  Under the new standard, all lessees must recognize a ROU asset, reflecting the right to use the underlying asset for the lease term, and a lease liability, reflecting the obligation to make lease payments, on the balance sheet. Operating leases were previously not recognized on the balance sheet.  PG&E Corporation and the Utility adopted the ASU 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, the Corporation and Utility elected to not separate lease and non-lease components. Additionally, PG&E Corporation and the Utility have elected not to restate comparative periods upon adoption.

PG&E Corporation and the Utility determine if an arrangement is a lease at inception. As most of the leases do not provide implicit discount rates, the Utility uses an estimate of its incremental secured borrowing rates based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities include only fixed lease payments. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Lease terms will only include options to extend or terminate the lease when it is reasonably certain that the Utility will exercise such options. The Utility recognizes lease expense in conformity with ratemaking.

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 six months ended June 30, 2019.

Cash payments arising from operating leases were $848 million for the six months ended June 30, 2019 and are presented within operating activities on the Condensed Consolidated Statement of Cash Flows. Cash payments for the principal portion of the financing lease liability will continue to be presented within financing activities. Variable lease payments not included in the financing lease liability, if any, are presented within operating activities. 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 fixed lease payments and excluding any variable lease payments. This amount is presented within the supplemental disclosures of noncash activities for the six months ended, June 30, 2019.

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, for terms between 5 years and 20 years. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land leases.

At June 30, 2019, the Utility’s operating 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 June 30, 2019		Six Months Ended June 30, 2019
Operating lease fixed cost	$	114	$	236
Operating lease variable cost	490		799
Total operating lease costs	$	604	$	1,035

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

(in millions)	June 30, 2019
2019 (1)	$	450
2020	679
2021	623
2022	548
2023	255
Thereafter	692
Total lease payments	3,247
Less imputed interest	(594		)
Total	$	2,653

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

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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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

6 Months Ended

Jun. 30, 2019

Regulated Operations [Abstract]

REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

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)	June 30, 2019		December 31, 2018
Pension benefits (1)	$	1,928	$	1,947
Environmental compliance costs	997		1,013
Utility retained generation (2)	251		274
Price risk management	67		90
Unamortized loss, net of gain, on reacquired debt (3)	230		76
Catastrophic event memorandum account (4)	918		790
Wildfire expense memorandum account (5)	127		94
Fire hazard prevention memorandum account (6)	291		263
Fire risk mitigation memorandum account (7)	154		—
Other	386		417
Total long-term regulatory assets	$	5,349	$	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 the accelerated amortization of premiums and debt issuance costs on pre-petition debt.

⁽⁴⁾ 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.

⁽⁵⁾ Includes specific incremental wildfire liability costs the CPUC approved for tracking in June 2018. Recovery of WEMA costs are subject to CPUC review and approval.

⁽⁶⁾ 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.

⁽⁷⁾ Includes costs associated with the 2019 Wildfire Safety Plan. Recovery of FHPMA costs are subject to CPUC review and approval.

Current Regulatory Liabilities

Current regulatory liabilities are primarily comprised of the current portion of the tax reform adjustment recorded as a result of the Tax Act.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Liability Balance at
(in millions)	June 30, 2019		December 31, 2018
Cost of removal obligations (1)	$	6,233	$	5,981
Deferred income taxes (2)	4		283
Recoveries in excess of AROs (3)	472		356
Public purpose programs (4)	785		674
Employee benefit plans (5)	423		421
Other	1,121		824
Total long-term regulatory liabilities	$	9,038	$	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 net of amounts owed to customers for deferred taxes collected at higher rates before the Tax Act and amounts owed to the Utility for reversal of deferred taxes subject to flow-through treatment.

⁽³⁾ 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.)

⁽⁴⁾ 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.

⁽⁵⁾ 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)	June 30, 2019		December 31, 2018
Electric distribution	$	465	$	160
Electric transmission	91		128
Utility generation	92		79
Gas distribution and transmission	173		462
Energy procurement	654		168
Public purpose programs	97		111
Other	312		327
Total regulatory balancing accounts receivable	$	1,884	$	1,435

	Payable Balance at
(in millions)	June 30, 2019		December 31, 2018
Electric transmission	135		134
Gas distribution and transmission	6		9
Energy procurement	308		59
Public purpose programs	610		587
Other	311		287
Total regulatory balancing accounts payable	$	1,370	$	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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DEBT

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

DEBT

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 June 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	$	—	$	521	$	3,479

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

As of June 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	June 30, 2019		December 31, 2018
Debt Subject to Compromise (1)
PG&E Corporation
Borrowings under Pre-Petition Credit Facilities
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)	2,965		2,965
Other borrowings:
Term Loan - Stated Maturity: 2019	variable rate(10)	250		250
Total Borrowings under Pre-Petition Credit Facility Subject to Compromise		3,215		3,215
Total Utility Debt Subject to Compromise		21,603		21,425
Total PG&E Corporation Consolidated Debt Subject to Compromise		$	22,253	$	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 $285 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 June 30, 2019, the contractual LIBOR-based interest rate on loans was 3.87%.

⁽³⁾ At June 30, 2019, the contractual LIBOR-based interest rate on the term loan was 3.60%.

⁽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 June 30, 2019, the contractual interest rate on the letter of credit facility supporting these bonds was 7.70%.

⁽⁷⁾ At June 30, 2019, the contractual interest rate on the letter of credit facility supporting these bonds ranged from 7.70% to 7.83%.

⁽⁸⁾ Also includes $79 million in letters of credit.

⁽⁹⁾ At June 30, 2019, the contractual LIBOR-based interest rate on the loans was 3.67%.

⁽¹⁰⁾ At June 30, 2019, the contractual LIBOR-based interest rate on the term loan was 3.00%.

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EQUITY

6 Months Ended

Jun. 30, 2019

Stockholders' Equity Note [Abstract]

EQUITY

EQUITY

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

PG&E Corporation issued common stock under the PG&E Corporation 401(k) plan and share-based compensation plans.  During the six months ended June 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.

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EARNINGS PER SHARE

6 Months Ended

Jun. 30, 2019

Earnings Per Share [Abstract]

EARNINGS PER SHARE

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 June 30,						Six Months Ended June 30,
(in millions, except per share amounts)	2019			2018			2019			2018
Loss attributable to common shareholders	$	(2,553	)	$	(984	)	$	(2,420	)	$	(542	)
Weighted average common shares outstanding, basic	529			516			528			516
Add incremental shares from assumed conversions:
Employee share-based compensation	—			—			—			1
Weighted average common shares outstanding, diluted	529			516			528			517
Total loss per common share, diluted	$	(4.83	)	$	(1.91	)	$	(4.58	)	$	(1.05	)

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.

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DERIVATIVES

6 Months Ended

Jun. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVES

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.

Volume of Derivative Activity

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

		Contract Volume at
Underlying Product	Instruments	June 30, 2019	December 31, 2018
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	174,575,917	177,750,349
	Options	16,455,000	13,735,405
Electricity (Megawatt-hours)	Forwards, Futures and Swaps	2,999,616	3,833,490
	Options	912,033	—
	Congestion Revenue Rights (3)	329,571,344	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 June 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	$	47		$	(4	)	$	48	$	91
Other noncurrent assets – other	161			—			—		161
Current liabilities – other	(25		)	4			3		(18		)
Noncurrent liabilities – other	(67		)	—			—		(67		)
Total commodity risk	$	116		$	—		$	51	$	167

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 June 30, 2019, the Utility satisfied its obligations related to the credit-risk related contingency features.

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FAIR VALUE MEASUREMENTS

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

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
	June 30, 2019
(in millions)	Level 1		Level 2		Level 3		Netting (1)			Total
Assets:
Short-term investments	$	3,402	$	—	$	—	$	—		$	3,402
Nuclear decommissioning trusts
Short-term investments	16		—		—		—			16
Global equity securities	1,959		—		—		—			1,959
Fixed-income securities	815		698		—		—			1,513
Assets measured at NAV	—		—		—		—			19
Total nuclear decommissioning trusts (2)	2,790		698		—		—			3,507
Price risk management instruments (Note 8)
Electricity	—		13		192		20			225
Gas	—		3		—		24			27
Total price risk management instruments	—		16		192		44			252
Rabbi trusts
Fixed-income securities	—		98		—		—			98
Life insurance contracts	—		71		—		—			71
Total rabbi trusts	—		169		—		—			169
Long-term disability trust
Short-term investments	5		—		—		—			5
Assets measured at NAV	—		—		—		—			142
Total long-term disability trust	5		—		—		—			147
TOTAL ASSETS	$	6,197	$	883	$	192	$	44		$	7,477
Liabilities:
Price risk management instruments (Note 8)
Electricity	$	—	$	4	$	83	$	(4	)	$	83
Gas	2		3		—		(3		)	2
TOTAL LIABILITIES	$	2	$	7	$	83	$	(7	)	$	85

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

⁽²⁾ Represents amount before deducting $491 million, primarily related to deferred taxes on appreciation of investment value.

	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 six months ended June 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.

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)	June 30, 2019
Fair Value Measurement	Assets		Liabilities		Valuation Technique	Unobservable Input	Range (1)
Congestion revenue rights	$	191	$	64	Market approach	CRR auction prices	$(13.11) - 22.76
Power purchase agreements	$	1	$	19	Discounted cash flow	Forward prices	$ 19.68 - 38.80

 ⁽¹⁾ Represents price per megawatt-hour.

	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 six months ended June 30, 2019 and 2018:

	Price Risk Management Instruments
(in millions)	2019			2018
Asset (liability) balance as of April 1	$	129		$	40
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)	(20		)	(6		)
Asset (liability) balance as of June 30	$	109		$	34

⁽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 (liability) balance as of January 1	$	95	$	42
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)	14		(8		)
Asset (liability) balance as of June 30	$	109	$	34

⁽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 to approximate their carrying values at June 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 June 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		1,500		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 4.

⁽²⁾ The Utility drew $350 million from the DIP Revolving Facility on February 1, 2019 which was subsequently repaid on April 3, 2019 using certain of the proceeds of the DIP Initial Term Loan Facility.

Nuclear Decommissioning Trust Investments

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

(in millions)
As of June 30, 2019	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Total Fair Value
Nuclear decommissioning trusts
Short-term investments	$	16	$	—	$	—		$	16
Global equity securities	496		1,486		(4		)	1,978
Fixed-income securities	1,431		84		(2		)	1,513
Total (1)	$	1,943	$	1,570	$	(6	)	$	3,507
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 $491 million and $408 million for the periods ended June 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)	June 30, 2019
Less than 1 year	$	26
1–5 years	541
5–10 years	340
More than 10 years	606
Total maturities of fixed-income securities	$	1,513

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

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	171		$	308		$	517		$	802
Gross realized gains on securities	56			11			22			48
Gross realized losses on securities	(26		)	(5		)	(7		)	(9		)

XML

WILDFIRE-RELATED CONTINGENCIES

6 Months Ended

Jun. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

WILDFIRE-RELATED CONTINGENCIES

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.

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 June 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)	June 30, 2019		December 31, 2018
2015 Butte fire	$	212	$	226
2017 Northern California wildfires	5,500		3,500
2018 Camp fire	12,400		10,500
Total wildfire-related claims (1)	$	18,112	$	14,226

⁽¹⁾ On the Petition Date, all wildfire-related claims were classified as LSTC and all pending litigation was stayed. As of June 30, 2019, $100 million was reclassified from LSTC to current liabilities - wildfire-related claims to reflect Bankruptcy Court approval of contributions to the Wildfire Assistance Fund.

In addition, during the three and six months ended June 30, 2019, the Utility incurred legal and other costs of $19 million and $32 million, respectively, related to the 2018 Camp fire, with no corresponding costs in the same periods in 2018. During the three and six months ended June 30, 2019, the Utility incurred legal and other costs of $7 million and $41 million, respectively, related to the 2017 Northern California wildfires, as compared to $46 million and $68 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 July 9, 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. (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations of the 2018 Camp fire.) As of the date of this filing, this 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.

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 issued 19 investigation reports and two supplementary investigation reports that include its determination of the causes of 21 of the 2017 Northern California wildfires, and alleged that all of these fires, with the exception of the Tubbs fire, involved the Utility’s equipment.

During the second quarter of 2018, Cal Fire issued news releases announcing its determination on the causes of 16 of the 2017 Northern California wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket and Atlas fires, located in Mendocino, Lake, Butte, Sonoma, Humboldt, Nevada and Napa counties). According to the Cal Fire news releases:

• the La Porte, McCourtney, Lobo and Honey fires “were caused by trees coming into contact with power lines,” and

• the Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket and Atlas fires “were caused by electric power and distribution lines, conductors and the failure of power poles.”

Cal Fire stated in its news releases that the McCourtney, Lobo, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fire investigations, and the investigation related to the Honey fire, have been referred to the appropriate county District Attorney’s offices for review “due to evidence of alleged violations of state law.” (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations by the District Attorneys’ offices related to these fires.)

Also during the second quarter of 2018, Cal Fire released its investigation reports related to the Redwood, Cherokee, 37, Nuns and La Porte fires. Cal Fire did not refer these fires to District Attorney offices for investigation.

On October 9, 2018, Cal Fire issued a news release announcing the results of its investigation into the Cascade fire, located in Yuba County, concluding that the Cascade fire “was started by sagging power lines coming into contact during heavy winds” and that “the power line in question was owned by Pacific Gas and Electric Company.” On October 10, 2018, Cal Fire released its investigation report related to the Cascade fire. (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations of the Cascade fire by the Office of the District Attorney of Yuba County.)

On January 24, 2019, Cal Fire issued a news release and its investigation report into the cause of the Tubbs fire. Cal Fire has determined that the Tubbs fire was caused by a private electrical system adjacent to a residential structure.

During the second quarter of 2019, Cal Fire released its investigation reports related to the Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires. The Cal Fire investigation report for the Adobe fire included as Attachment 42.1 a “Supplementary Investigation Report” concerning the Pressley fire. The Cal Fire investigator concludes in the Supplementary Investigation Report that the Pressley fire was started by an ember cast from the Adobe fire.

On July 24, 2019, the CPUC released copies of Cal Fire’s investigation report related to the Point fire and supplementary investigation reports related to the Youngs fire, which Cal Fire had not previously released publicly, as attachments to the SED’s own investigative reports for those fires. (The Youngs fire is the fire that the Utility has previously referred to as the Maacama fire.) The Cal Fire investigation report for the Point fire alleges that the fire was caused by a tree limb that broke off in high winds and fell into a power line, causing the power line to contact the ground. The Cal Fire investigators in the Youngs supplementary reports conclude that the fire was caused by a tree that fell into a power line, severing the line.

Cal Fire has not yet released its investigation reports related to the McCourtney and Lobo 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.

As described in Note 11, on June 27, 2019, the CPUC issued an OII disclosing 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. 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, relating to matters such as the Utility’s vegetation management procedures and practices, its use of recloser devices in high fire risk areas, its pro-active de-energization of powerlines during times of high fire danger and its recordkeeping and other practices.

Further, the SED is conducting investigations into certain of the other 2017 Northern California wildfires, including the McCourtney and Lobo fires. Various other entities may also be investigating certain of the fires. It is uncertain when the investigations will be complete and whether the SED will release any preliminary findings before its investigations are 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.

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 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, the TCC has submitted a motion to the Bankruptcy Court seeking relief from the automatic stay to enable certain plaintiffs to pursue their claims outside of the Chapter 11 process, as further described under the heading “Motions to Lift the Automatic Stay for Certain Tubbs Fire-Related Claims” below. PG&E Corporation and the Utility have opposed such motions.

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 were 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. 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, certain holders of subrogation claims have submitted motions to the Bankruptcy Court seeking relief from the automatic stay in order to pursue their claims outside of the Chapter 11 process, as further described under the heading “Motions to Lift the Automatic Stay for Certain Tubbs Fire-Related Claims” below. PG&E Corporation and the Utility have opposed such motions.

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 were 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.

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. 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. It is expected that numerous wildfire-related claims will be filed against PG&E Corporation and the Utility in connection with the 2018 Camp fire and the 2017 Northern California wildfires through the Bar Date. 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 and the 2017 Northern California wildfires, as further described under the heading “Motion for the Establishment of Wildfire Claims Estimation Procedures” below.

PG&E Corporation and the Utility are continuing to review the evidence concerning the 2018 Camp fire and 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 or to the McCourtney and Lobo investigation reports prepared by Cal Fire. PG&E Corporation and the Utility and 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, regulatory proceedings and any potential enforcement proceedings, all of which could take a number of years to resolve. The timing and outcome of these and other potential proceedings are uncertain.

PG&E Corporation and the Utility, as part of their efforts to emerge from bankruptcy, are engaged in discussions with holders of claims related to the 2017 Northern California wildfires and the 2018 Camp fire in an attempt to reach a global settlement of such claims. As discussed under the heading “Plan Support Agreements with Public Entities,” PG&E Corporation and the Utility have entered into agreements with certain government entity claimholders to potentially resolve their wildfire-related claims. The most recent settlement offers made by PG&E Corporation and the Utility to subrogated insurance claimholders and individual claimholders as of the date of this filing are discussed in further detail below under the heading “2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge.” PG&E Corporation and the Utility cannot predict the outcome or timing of discussions with other claimholders.  Even if discussions with claimholders were successful, the consummation of such a global settlement would likely be contingent on numerous uncertain conditions, including Bankruptcy Court approval and governmental action.

On March 16, 2018, PG&E Corporation and the Utility filed a demurrer to the inverse condemnation cause of action in the 2017 Northern California wildfires litigation. On May 21, 2018, the court overruled the motion. On July 20, 2018, PG&E Corporation and the Utility filed a writ in the Court of Appeal requesting appellate review of the trial court’s decision, which was denied on September 17, 2018. On September 27, 2018, PG&E Corporation and the Utility filed a petition for review to the California Supreme Court. On November 14, 2018, the California Supreme Court denied PG&E Corporation’s and the Utility’s petition for review.

Motions to Lift the Automatic Stay for Certain Tubbs Fire-Related Claims

On July 2, 2019, the TCC submitted a motion, pursuant to section 362(d)(1) of the Bankruptcy Code, for entry of an order terminating the automatic stay to permit certain individual plaintiffs (the “Tubbs Preference 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 the Tubbs Preference 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.

On July 19, 2019, PG&E Corporation and the Utility filed an objection to the motions of the TCC and the Ad Hoc Subrogation Group, requesting that the motions be denied. Also on July 19, 2019, the UCC and the Shareholder Group filed objections to the motions of the TCC and the Ad Hoc Subrogation Group with the Bankruptcy Court, requesting that the motions be denied. The Shareholder Group also joined in PG&E Corporation’s and the Utility’s objection to the motions of the TCC and the Ad Hoc Subrogation Group.

On July 22, 2019, the Bankruptcy Court issued an order continuing the hearings on the TCC’s and the Ad Hoc Subrogation Group’s motions for relief from the automatic stay to August 14, 2019.

Motion for the Establishment of Wildfire Claims Estimation Procedures

On July 18, 2019, PG&E Corporation and the Utility submitted a motion, pursuant to sections 105(a) and 502(c) of the Bankruptcy Code, for entry of an order establishing procedures and schedules for the estimation of PG&E Corporation’s and the Utility’s aggregate liability for contingent and/or unliquidated claims arising out of the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (which are collectively referred to in this paragraph as “wildfire claims”). In the motion, PG&E Corporation and the Utility proposed, among other things, the following general parameters of the estimation process:

• First, the Bankruptcy Court would address the legal issue of whether, pursuant to the state law doctrine of inverse condemnation, PG&E Corporation and the Utility may be held strictly liable for wildfire claims asserting property damages even where PG&E Corporation or the Utility were not negligent.

• Second, the Bankruptcy Court would schedule a hearing on the limited issue of causation of the Tubbs fire on October 7, 2019, or as soon as possible thereafter.

• Third, following the Bar Date, the Bankruptcy Court would determine the aggregate value of the wildfire claims in a hearing proposed to be scheduled for early December 2019. This phase of the estimation process would involve the resolution of questions around the likelihood of success of the wildfire claims on issues such as negligence, the recoverability of certain categories of damages and the aggregate estimate of overall damages based upon sampling of claims and expert testimony. In the motion, PG&E Corporation and the Utility indicated that they are prepared to agree that, as part of the proposed estimation process, they will not contest causation with respect to any wildfire for which Cal Fire has concluded that PG&E Corporation and the Utility are responsible, including the 2018 Camp fire and the 2017 Northern California wildfires identified above, except the Tubbs fire.

The motion is expected to be heard by the Bankruptcy Court on August 14, 2019. On August 7, 2019, certain third parties filed joinders and statements in support with the Bankruptcy Court with respect to PG&E Corporation’s and the Utility’s motion, including the Ad Hoc Noteholder Committee, the UCC and the Shareholder Group. Also on August 7, 2019, certain third parties filed objections to PG&E Corporation’s and the Utility’s motion with the Bankruptcy Court, including the City and County of San Francisco, the Ad Hoc Subrogation Group and the TCC. The objection of the City and County of San Francisco is limited to PG&E Corporation’s and the Utility’s proposal for the Bankruptcy Court to address the legal issue of whether, under the doctrine of inverse condemnation, PG&E Corporation and the Utility may be held strictly liable for wildfire claims asserting property damages even where it was not negligent.

Plan Support Agreements with Public Entities

On June 18, 2019, PG&E Corporation and the Utility entered into PSAs with certain local 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”). PG&E Corporation and the Utility’s Chapter 11 plan of reorganization currently is under development and has not yet been filed with the Bankruptcy Court.  PG&E Corporation and the Utility have entered into a PSA with each of the following public entities or group of public entities, as applicable: 

• the City of Clearlake, the City of Napa, the City of Santa Rosa, the County of Lake, the Lake County Sanitation District, the County of Mendocino, Napa County, the County of Nevada, the County of Sonoma, the Sonoma County Agricultural Preservation and Open Space District, the Sonoma County Community Development Commission, the Sonoma County Water Agency, the Sonoma Valley County Sanitation District and the County of Yuba (collectively, the “2017 Northern California Wildfire Public Entities”);

• the Town of Paradise;

• the County of Butte;

• the Paradise Recreation & Park District;

• the County of Yuba; and

• the Calaveras County Water District. 

For purposes of each PSA, the local public entities that are party to such PSA are referred to herein as “Supporting Public Entities.”

Each PSA provides that PG&E Corporation and the Utility’s Chapter 11 plan of reorganization will include, among other things, the following elements: 

• following the effective date of PG&E Corporation and the Utility’s Chapter 11 plan of reorganization, PG&E Corporation and the Utility will remit a Settlement Amount (as defined below) in the amount set forth below to the applicable Supporting Public Entities in full and final satisfaction and discharge of their Public Entity Wildfire Claims, and

• subject to the Supporting Public Entities voting affirmatively to accept PG&E Corporation and the Utility’s Chapter 11 plan of reorganization, following the effective date of PG&E Corporation and the Utility’s Chapter 11 plan of reorganization, PG&E Corporation and the Utility will create and promptly fund $10.0 million to a segregated fund to be used by the Supporting Public Entities collectively in connection with the defense or resolution of claims against the Supporting Public Entities by third parties relating to the wildfires noted above (“Third Party Claims”). 

The “Settlement Amount” set forth in each PSA is as follows: 

• for the 2017 Northern California Wildfire Public Entities, $415.0 million (which amount will be allocated among such entities),

• for the Town of Paradise, $270.0 million,

• for the County of Butte, $252.0 million,

• for the Paradise Recreation & Park District, $47.5 million,

• for the County of Yuba, $12.5 million, and

• for the Calaveras County Water District, $3.0 million.

Each PSA provides that, subject to certain terms and conditions, the Supporting Public Entities will support PG&E Corporation and the Utility’s Chapter 11 plan of reorganization with respect to its treatment of their respective Public Entity Wildfire Claims, including by voting to accept PG&E Corporation and the Utility’s Chapter 11 plan of reorganization in the Chapter 11 Cases.

Each PSA may be terminated by the applicable Supporting Public Entities under certain circumstances, including:

• if the Federal Emergency Management Agency or the OES fails to agree that no reimbursement is required from the Supporting Public Entities on account of assistance rendered by either agency in connection with the wildfires noted above, and

• by any individual Supporting Public Entity, if a material amount of Third Party Claims is filed against such Supporting Public Entity and such Third Party Claims are not released pursuant to PG&E Corporation and the Utility’s Chapter 11 plan of reorganization. 

Each PSA may be terminated by PG&E Corporation and the Utility under certain circumstances, including if:

• PG&E Corporation and the Utility do not obtain the consent, or the waiver of the lack of consent as a defense, of their insurance carriers for the policy years 2017 and 2018,

• the Board of Directors of either PG&E Corporation or the Utility determines in good faith that continued performance under the PSA would be inconsistent with the exercise of its fiduciary duties, and

• any Supporting Public Entity terminates a PSA, in which case PG&E Corporation and the Utility may terminate any other PSA.

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. These claims reflect insured property losses only. 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.

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, 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 wildfire-related claims that will be filed in the Chapter 11 Cases, 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 treated and whether such claims will be allowed, and 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. 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, which amount does not include potential punitive damages, fines and penalties or damages related to claims that have not manifested yet. 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, and 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. 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.

2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge

Following accounting rules, PG&E Corporation and the Utility record a liability when a loss is probable and reasonably estimable. In accordance with U.S. generally accepted accounting principles, 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 is the amount within the range that is a better estimate than any other amount 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.

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. Based on additional facts and circumstances available to the Utility as of the date of this filing, including the entry into the PSAs and the status of PG&E Corporation’s and the Utility’s efforts to reach a resolution with other holders of wildfire-related claims, PG&E Corporation and the Utility recorded an additional charge for claims in connection with the 2018 Camp fire in the amount of $1.9 billion for the three months ended June 30, 2019.

The aggregate liability of $12.4 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 total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. 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 2018 Camp fire may change, which could result in material increases to the loss accrued.

The $12.4 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.

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. Based on additional facts and circumstances available to the Utility as of the date of this filing, including additional information from Cal Fire, the entry into the PSAs and the status of PG&E Corporation’s and the Utility’s efforts to reach a resolution with other holders of wildfire-related claims, 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 June 30, 2019.

The aggregate liability of $5.5 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.

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. However, as a result of PG&E Corporation’s and the Utility’s most recent settlement offer to holders of claims related to the Tubbs and 37 fires as of the date of this filing, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with such fires. With respect to 17 of the other 19 of the 2017 Northern California wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, Blue, Pocket, Atlas, Cascade, Point and Sonoma/Napa merged fires (which include the Nuns, Norrbom, Adobe, Partrick and Pythian 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. With respect to 2 of the other 19 of the 2017 Northern California wildfires (the Youngs and Pressley fires), PG&E Corporation and the Utility have 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 based on information that became available to PG&E Corporation and the Utility after the filing of their last Quarterly Report on Form 10-Q.

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 total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. 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 $5.5 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 Accounting Charge

The aggregate liability of $17.9 billion for claims in connection with the 2018 Camp fire and the 2017 Northern California wildfires is comprised of (i) $8.5 billion for subrogated insurance claimholders, (ii) $7.5 billion for individual claimholders (including those with uninsured and underinsured property losses, among other claims), (iii) $1.0 billion for the Supporting Public Entities with respect to their Public Entity Wildfire Claims pursuant to the PSAs and (iv) $900 million for clean-up and fire suppression costs. The aggregate liabilities of $8.5 billion for subrogated insurance claimholders and $7.5 billion for individual claimholders are based on PG&E Corporation’s and the Utility’s estimates of probable loss developed from data and other information available to PG&E Corporation and the Utility and PG&E Corporation’s and the Utility’s most recent settlement offers to representatives of such claimholders as of the date of this filing. PG&E Corporation and the Utility cannot predict the outcome or timing of discussions with such claimholders. With respect to the $1.0 billion liability for claims held by the Supporting Public Entities, while PG&E Corporation and the Utility previously disclosed the existence of claims asserted by such entities, PG&E Corporation and the Utility had not previously taken a charge related to these claims as the amount of the liability could not be reasonably estimated. As described above, the aggregate liability of $17.9 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.)

As of the date of this filing, PG&E Corporation and the Utility believe that the settlement discussions with representatives of subrogated insurance claimholders are in a particularly critical period of the negotiation. PG&E Corporation and the Utility believe that the potential exists for material developments in the negotiation in the near term. Accordingly, if PG&E Corporation, the Utility and such claimholders reach agreement, PG&E Corporation’s and the Utility’s probable loss contingency for the subrogated insurance claims may increase by a material amount, which would result in an additional accrual above the $8.5 billion reflected in this filing. Any such increase could be substantial and could be taken in the third quarter of 2019. In their motion submitted to the Bankruptcy Court on July 23, 2019, the Ad Hoc Subrogation Group stated that holders of subrogated insurance claims hold in excess of $20 billion of wildfire-related claims against PG&E Corporation and the Utility. In the “Restructuring Term Sheet” attached to such motion, the Ad Hoc Subrogation Group proposed terms for a plan of reorganization that would settle all such subrogated insurance claims for consideration valued at $15.8 billion. PG&E Corporation and the Utility cannot predict the outcome or timing of discussions with such claimholders.

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 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.

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 June 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.

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 following table presents changes in the insurance receivable for the six months ended June 30, 2019. The balance for insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:

(in millions)	Insurance Receivable
2018 Camp fire
Balance at December 31, 2018	$	1,380
Accrued insurance recoveries	—
Reimbursements	—
Balance at June 30, 2019	$	1,380
2017 Northern California wildfires
Balance at December 31, 2018	$	829
Accrued insurance recoveries	—
Reimbursements	—
Balance at June 30, 2019	$	829

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 customer harm threshold, 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 (the “Customer Harm Threshold”). 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 Customer Harm Threshold. 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 Customer Harm Threshold 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 Customer Harm Threshold 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 Customer Harm Threshold 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 Customer Harm Threshold 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 [Customer Harm Threshold], requires a utility to file a cost recovery application before the CHT [Customer Harm Threshold] will be determined, and erects ratepayer protection mechanisms as an extra-statutory hurdle for accessing the CHT [Customer Harm Threshold].” The Utility also argued that the CPUC should apply the Customer Harm Threshold methodology to costs related to the 2018 Camp fire.

The decision otherwise adopts a methodology to determine the Customer Harm Threshold 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 Customer Harm Threshold 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 Customer Harm Threshold. 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. 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.

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. 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. 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.

Wildfire-Related Securities Class Action Litigation

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 federal 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.

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, and PG&E Corporation and the Utility are currently seeking an order from the Bankruptcy Court to extend the stay to the officer, director, and underwriter defendants.

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.”

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 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.

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 $655 million for clean-up and repair of the Utility’s facilities (including $236 million in capital expenditures) through June 30, 2019, in connection with the 2018 Camp fire. The Utility also incurred costs of $334 million for clean-up and repair of the Utility’s facilities (including $161 million in capital expenditures) through June 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 June 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 June 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 will consist of $105 million deposited into a segregated account to be controlled by an independent third-party administrator appointed by the Bankruptcy Court, who will disburse and administer the funds. The administrator will be responsible for developing the specific eligibility requirements and application procedures for the distribution of the Wildfire Assistance Fund to eligible claimants. 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.

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.

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.

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. 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. It is expected that numerous wildfire-related claims will be filed against PG&E Corporation and the Utility in connection with the 2015 Butte fire through the Bar Date. 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 2015 Butte fire, as further described under the heading “Motion for the Establishment of Wildfire Claims Estimation Procedures” above.

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.

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 $226 million and $212 million as of December 31, 2018 and June 30, 2019, respectively, reflecting payments of $14 million in January 2019, prior to the Petition Date. As of June 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 June 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 $85 million and $50 million as of December 31, 2018 and June 30, 2019, respectively, reflecting reimbursements of $35 million during the six months ended June 30, 2019.

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.

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 Safety 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. As of April 30, 2019, to the Utility’s knowledge, no parties have submitted comments to the court on the 2019 Wildfire Safety Plan.

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’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’s Board of Directors assume responsibility for tracking progress of the 2019 Wildfire Safety 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.

CPUC and FERC Matters

Order Instituting an Investigation 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 requires 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 is 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 must 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.

The OII also indicates that the assigned commissioner shall set a prehearing conference for 45 to 60 days after the initiation of the proceeding or as soon as practicable after the CPUC makes the assignment. The assigned commissioner will also issue a scoping memo setting forth the scope of the proceeding and establishing a procedural schedule.

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.

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.

Order Instituting an Investigation 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.

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 reach a partial stipulation in order to streamline the proceeding.  On April 24, 2019, the Utility provided notice of a settlement conference and the parties have continued 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 the Utility’s 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. The parties continue settlement discussions. In accordance with the current procedural schedule issued by the ALJ on June 27, 2019, intervenor testimony is due August 16, 2019, and the Utility’s reply testimony is due September 18, 2019.  The SED’s rebuttal testimony is due October 4, 2019.  Evidentiary hearings are scheduled for October 21 to 25, 2019.

Based on the information available to PG&E Corporation and the Utility as of the date of this filing, PG&E Corporation and the Utility believe it is probable that the Utility will incur penalties, including fines or other remedies. Accordingly, PG&E Corporation and the Utility recorded a charge during the quarter ended June 30, 2019 for an amount that is not material, which corresponds to the lower end of the range of PG&E Corporation's and the Utility's reasonably estimated losses and is subject to change based on additional information.  PG&E Corporation and the Utility are unable to determine a better estimate within such range 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.

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.

Order Instituting an Investigation 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 (formerly known as the Office of Ratepayer Advocates or ORA), the SED, and TURN.

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 June 30, 2019, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets include an $16 million accrual 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 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 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.

At June 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. 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.

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)	June 30, 2019		December 31, 2018
Topock natural gas compressor station	$	346	$	369
Hinkley natural gas compressor station	142		146
Former manufactured gas plant sites owned by the Utility or third parties (1)	580		520
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	112		111
Fossil fuel-fired generation facilities and sites (3)	125		137
Total environmental remediation liability	$	1,305	$	1,283

⁽¹⁾ Primarily driven by the following sites: Vallejo, San Francisco East Harbor, Napa, Beach Street, San Francisco North Beach, and San Rafael MGP-Bio Marin MGP.

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

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

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 June 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 June 30, 2019, the Utility expected to recover $960 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 $302 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 2019 and finalized in 2020. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $139 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.

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 $528 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 $98 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 $86 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. For the period from August 1, 2019 through July 31, 2020, PG&E Corporation and the Utility have secured approximately $430 million for general wildfire liability (subject to an initial self-insured retention of $10 million per occurrence). PG&E Corporation and the Utility continue to pursue additional insurance coverage for the period from August 1, 2019 through July 30, 2020. 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 July 31, 2020 (consisting of the $430 million general wildfire liability coverage described above and $520 million for non-wildfire general liability) is approximately $190 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 June 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.

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 $5 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 June 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 six months ended June 30, 2019.

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OTHER CONTINGENCIES AND COMMITMENTS

6 Months Ended

Jun. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

OTHER CONTINGENCIES AND COMMITMENTS

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.

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 June 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)	June 30, 2019		December 31, 2018
2015 Butte fire	$	212	$	226
2017 Northern California wildfires	5,500		3,500
2018 Camp fire	12,400		10,500
Total wildfire-related claims (1)	$	18,112	$	14,226

⁽¹⁾ On the Petition Date, all wildfire-related claims were classified as LSTC and all pending litigation was stayed. As of June 30, 2019, $100 million was reclassified from LSTC to current liabilities - wildfire-related claims to reflect Bankruptcy Court approval of contributions to the Wildfire Assistance Fund.

In addition, during the three and six months ended June 30, 2019, the Utility incurred legal and other costs of $19 million and $32 million, respectively, related to the 2018 Camp fire, with no corresponding costs in the same periods in 2018. During the three and six months ended June 30, 2019, the Utility incurred legal and other costs of $7 million and $41 million, respectively, related to the 2017 Northern California wildfires, as compared to $46 million and $68 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 July 9, 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. (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations of the 2018 Camp fire.) As of the date of this filing, this 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.

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 issued 19 investigation reports and two supplementary investigation reports that include its determination of the causes of 21 of the 2017 Northern California wildfires, and alleged that all of these fires, with the exception of the Tubbs fire, involved the Utility’s equipment.

During the second quarter of 2018, Cal Fire issued news releases announcing its determination on the causes of 16 of the 2017 Northern California wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket and Atlas fires, located in Mendocino, Lake, Butte, Sonoma, Humboldt, Nevada and Napa counties). According to the Cal Fire news releases:

• the La Porte, McCourtney, Lobo and Honey fires “were caused by trees coming into contact with power lines,” and

• the Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket and Atlas fires “were caused by electric power and distribution lines, conductors and the failure of power poles.”

Cal Fire stated in its news releases that the McCourtney, Lobo, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fire investigations, and the investigation related to the Honey fire, have been referred to the appropriate county District Attorney’s offices for review “due to evidence of alleged violations of state law.” (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations by the District Attorneys’ offices related to these fires.)

Also during the second quarter of 2018, Cal Fire released its investigation reports related to the Redwood, Cherokee, 37, Nuns and La Porte fires. Cal Fire did not refer these fires to District Attorney offices for investigation.

On October 9, 2018, Cal Fire issued a news release announcing the results of its investigation into the Cascade fire, located in Yuba County, concluding that the Cascade fire “was started by sagging power lines coming into contact during heavy winds” and that “the power line in question was owned by Pacific Gas and Electric Company.” On October 10, 2018, Cal Fire released its investigation report related to the Cascade fire. (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations of the Cascade fire by the Office of the District Attorney of Yuba County.)

On January 24, 2019, Cal Fire issued a news release and its investigation report into the cause of the Tubbs fire. Cal Fire has determined that the Tubbs fire was caused by a private electrical system adjacent to a residential structure.

During the second quarter of 2019, Cal Fire released its investigation reports related to the Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires. The Cal Fire investigation report for the Adobe fire included as Attachment 42.1 a “Supplementary Investigation Report” concerning the Pressley fire. The Cal Fire investigator concludes in the Supplementary Investigation Report that the Pressley fire was started by an ember cast from the Adobe fire.

On July 24, 2019, the CPUC released copies of Cal Fire’s investigation report related to the Point fire and supplementary investigation reports related to the Youngs fire, which Cal Fire had not previously released publicly, as attachments to the SED’s own investigative reports for those fires. (The Youngs fire is the fire that the Utility has previously referred to as the Maacama fire.) The Cal Fire investigation report for the Point fire alleges that the fire was caused by a tree limb that broke off in high winds and fell into a power line, causing the power line to contact the ground. The Cal Fire investigators in the Youngs supplementary reports conclude that the fire was caused by a tree that fell into a power line, severing the line.

Cal Fire has not yet released its investigation reports related to the McCourtney and Lobo 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.

As described in Note 11, on June 27, 2019, the CPUC issued an OII disclosing 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. 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, relating to matters such as the Utility’s vegetation management procedures and practices, its use of recloser devices in high fire risk areas, its pro-active de-energization of powerlines during times of high fire danger and its recordkeeping and other practices.

Further, the SED is conducting investigations into certain of the other 2017 Northern California wildfires, including the McCourtney and Lobo fires. Various other entities may also be investigating certain of the fires. It is uncertain when the investigations will be complete and whether the SED will release any preliminary findings before its investigations are 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.

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 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, the TCC has submitted a motion to the Bankruptcy Court seeking relief from the automatic stay to enable certain plaintiffs to pursue their claims outside of the Chapter 11 process, as further described under the heading “Motions to Lift the Automatic Stay for Certain Tubbs Fire-Related Claims” below. PG&E Corporation and the Utility have opposed such motions.

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 were 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. 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, certain holders of subrogation claims have submitted motions to the Bankruptcy Court seeking relief from the automatic stay in order to pursue their claims outside of the Chapter 11 process, as further described under the heading “Motions to Lift the Automatic Stay for Certain Tubbs Fire-Related Claims” below. PG&E Corporation and the Utility have opposed such motions.

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 were 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.

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. 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. It is expected that numerous wildfire-related claims will be filed against PG&E Corporation and the Utility in connection with the 2018 Camp fire and the 2017 Northern California wildfires through the Bar Date. 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 and the 2017 Northern California wildfires, as further described under the heading “Motion for the Establishment of Wildfire Claims Estimation Procedures” below.

PG&E Corporation and the Utility are continuing to review the evidence concerning the 2018 Camp fire and 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 or to the McCourtney and Lobo investigation reports prepared by Cal Fire. PG&E Corporation and the Utility and 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, regulatory proceedings and any potential enforcement proceedings, all of which could take a number of years to resolve. The timing and outcome of these and other potential proceedings are uncertain.

PG&E Corporation and the Utility, as part of their efforts to emerge from bankruptcy, are engaged in discussions with holders of claims related to the 2017 Northern California wildfires and the 2018 Camp fire in an attempt to reach a global settlement of such claims. As discussed under the heading “Plan Support Agreements with Public Entities,” PG&E Corporation and the Utility have entered into agreements with certain government entity claimholders to potentially resolve their wildfire-related claims. The most recent settlement offers made by PG&E Corporation and the Utility to subrogated insurance claimholders and individual claimholders as of the date of this filing are discussed in further detail below under the heading “2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge.” PG&E Corporation and the Utility cannot predict the outcome or timing of discussions with other claimholders.  Even if discussions with claimholders were successful, the consummation of such a global settlement would likely be contingent on numerous uncertain conditions, including Bankruptcy Court approval and governmental action.

On March 16, 2018, PG&E Corporation and the Utility filed a demurrer to the inverse condemnation cause of action in the 2017 Northern California wildfires litigation. On May 21, 2018, the court overruled the motion. On July 20, 2018, PG&E Corporation and the Utility filed a writ in the Court of Appeal requesting appellate review of the trial court’s decision, which was denied on September 17, 2018. On September 27, 2018, PG&E Corporation and the Utility filed a petition for review to the California Supreme Court. On November 14, 2018, the California Supreme Court denied PG&E Corporation’s and the Utility’s petition for review.

Motions to Lift the Automatic Stay for Certain Tubbs Fire-Related Claims

On July 2, 2019, the TCC submitted a motion, pursuant to section 362(d)(1) of the Bankruptcy Code, for entry of an order terminating the automatic stay to permit certain individual plaintiffs (the “Tubbs Preference 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 the Tubbs Preference 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.

On July 19, 2019, PG&E Corporation and the Utility filed an objection to the motions of the TCC and the Ad Hoc Subrogation Group, requesting that the motions be denied. Also on July 19, 2019, the UCC and the Shareholder Group filed objections to the motions of the TCC and the Ad Hoc Subrogation Group with the Bankruptcy Court, requesting that the motions be denied. The Shareholder Group also joined in PG&E Corporation’s and the Utility’s objection to the motions of the TCC and the Ad Hoc Subrogation Group.

On July 22, 2019, the Bankruptcy Court issued an order continuing the hearings on the TCC’s and the Ad Hoc Subrogation Group’s motions for relief from the automatic stay to August 14, 2019.

Motion for the Establishment of Wildfire Claims Estimation Procedures

On July 18, 2019, PG&E Corporation and the Utility submitted a motion, pursuant to sections 105(a) and 502(c) of the Bankruptcy Code, for entry of an order establishing procedures and schedules for the estimation of PG&E Corporation’s and the Utility’s aggregate liability for contingent and/or unliquidated claims arising out of the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (which are collectively referred to in this paragraph as “wildfire claims”). In the motion, PG&E Corporation and the Utility proposed, among other things, the following general parameters of the estimation process:

• First, the Bankruptcy Court would address the legal issue of whether, pursuant to the state law doctrine of inverse condemnation, PG&E Corporation and the Utility may be held strictly liable for wildfire claims asserting property damages even where PG&E Corporation or the Utility were not negligent.

• Second, the Bankruptcy Court would schedule a hearing on the limited issue of causation of the Tubbs fire on October 7, 2019, or as soon as possible thereafter.

• Third, following the Bar Date, the Bankruptcy Court would determine the aggregate value of the wildfire claims in a hearing proposed to be scheduled for early December 2019. This phase of the estimation process would involve the resolution of questions around the likelihood of success of the wildfire claims on issues such as negligence, the recoverability of certain categories of damages and the aggregate estimate of overall damages based upon sampling of claims and expert testimony. In the motion, PG&E Corporation and the Utility indicated that they are prepared to agree that, as part of the proposed estimation process, they will not contest causation with respect to any wildfire for which Cal Fire has concluded that PG&E Corporation and the Utility are responsible, including the 2018 Camp fire and the 2017 Northern California wildfires identified above, except the Tubbs fire.

The motion is expected to be heard by the Bankruptcy Court on August 14, 2019. On August 7, 2019, certain third parties filed joinders and statements in support with the Bankruptcy Court with respect to PG&E Corporation’s and the Utility’s motion, including the Ad Hoc Noteholder Committee, the UCC and the Shareholder Group. Also on August 7, 2019, certain third parties filed objections to PG&E Corporation’s and the Utility’s motion with the Bankruptcy Court, including the City and County of San Francisco, the Ad Hoc Subrogation Group and the TCC. The objection of the City and County of San Francisco is limited to PG&E Corporation’s and the Utility’s proposal for the Bankruptcy Court to address the legal issue of whether, under the doctrine of inverse condemnation, PG&E Corporation and the Utility may be held strictly liable for wildfire claims asserting property damages even where it was not negligent.

Plan Support Agreements with Public Entities

On June 18, 2019, PG&E Corporation and the Utility entered into PSAs with certain local 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”). PG&E Corporation and the Utility’s Chapter 11 plan of reorganization currently is under development and has not yet been filed with the Bankruptcy Court.  PG&E Corporation and the Utility have entered into a PSA with each of the following public entities or group of public entities, as applicable: 

• the City of Clearlake, the City of Napa, the City of Santa Rosa, the County of Lake, the Lake County Sanitation District, the County of Mendocino, Napa County, the County of Nevada, the County of Sonoma, the Sonoma County Agricultural Preservation and Open Space District, the Sonoma County Community Development Commission, the Sonoma County Water Agency, the Sonoma Valley County Sanitation District and the County of Yuba (collectively, the “2017 Northern California Wildfire Public Entities”);

• the Town of Paradise;

• the County of Butte;

• the Paradise Recreation & Park District;

• the County of Yuba; and

• the Calaveras County Water District. 

For purposes of each PSA, the local public entities that are party to such PSA are referred to herein as “Supporting Public Entities.”

Each PSA provides that PG&E Corporation and the Utility’s Chapter 11 plan of reorganization will include, among other things, the following elements: 

• following the effective date of PG&E Corporation and the Utility’s Chapter 11 plan of reorganization, PG&E Corporation and the Utility will remit a Settlement Amount (as defined below) in the amount set forth below to the applicable Supporting Public Entities in full and final satisfaction and discharge of their Public Entity Wildfire Claims, and

• subject to the Supporting Public Entities voting affirmatively to accept PG&E Corporation and the Utility’s Chapter 11 plan of reorganization, following the effective date of PG&E Corporation and the Utility’s Chapter 11 plan of reorganization, PG&E Corporation and the Utility will create and promptly fund $10.0 million to a segregated fund to be used by the Supporting Public Entities collectively in connection with the defense or resolution of claims against the Supporting Public Entities by third parties relating to the wildfires noted above (“Third Party Claims”). 

The “Settlement Amount” set forth in each PSA is as follows: 

• for the 2017 Northern California Wildfire Public Entities, $415.0 million (which amount will be allocated among such entities),

• for the Town of Paradise, $270.0 million,

• for the County of Butte, $252.0 million,

• for the Paradise Recreation & Park District, $47.5 million,

• for the County of Yuba, $12.5 million, and

• for the Calaveras County Water District, $3.0 million.

Each PSA provides that, subject to certain terms and conditions, the Supporting Public Entities will support PG&E Corporation and the Utility’s Chapter 11 plan of reorganization with respect to its treatment of their respective Public Entity Wildfire Claims, including by voting to accept PG&E Corporation and the Utility’s Chapter 11 plan of reorganization in the Chapter 11 Cases.

Each PSA may be terminated by the applicable Supporting Public Entities under certain circumstances, including:

• if the Federal Emergency Management Agency or the OES fails to agree that no reimbursement is required from the Supporting Public Entities on account of assistance rendered by either agency in connection with the wildfires noted above, and

• by any individual Supporting Public Entity, if a material amount of Third Party Claims is filed against such Supporting Public Entity and such Third Party Claims are not released pursuant to PG&E Corporation and the Utility’s Chapter 11 plan of reorganization. 

Each PSA may be terminated by PG&E Corporation and the Utility under certain circumstances, including if:

• PG&E Corporation and the Utility do not obtain the consent, or the waiver of the lack of consent as a defense, of their insurance carriers for the policy years 2017 and 2018,

• the Board of Directors of either PG&E Corporation or the Utility determines in good faith that continued performance under the PSA would be inconsistent with the exercise of its fiduciary duties, and

• any Supporting Public Entity terminates a PSA, in which case PG&E Corporation and the Utility may terminate any other PSA.

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. These claims reflect insured property losses only. 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.

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, 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 wildfire-related claims that will be filed in the Chapter 11 Cases, 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 treated and whether such claims will be allowed, and 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. 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, which amount does not include potential punitive damages, fines and penalties or damages related to claims that have not manifested yet. 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, and 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. 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.

2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge

Following accounting rules, PG&E Corporation and the Utility record a liability when a loss is probable and reasonably estimable. In accordance with U.S. generally accepted accounting principles, 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 is the amount within the range that is a better estimate than any other amount 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.

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. Based on additional facts and circumstances available to the Utility as of the date of this filing, including the entry into the PSAs and the status of PG&E Corporation’s and the Utility’s efforts to reach a resolution with other holders of wildfire-related claims, PG&E Corporation and the Utility recorded an additional charge for claims in connection with the 2018 Camp fire in the amount of $1.9 billion for the three months ended June 30, 2019.

The aggregate liability of $12.4 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 total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. 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 2018 Camp fire may change, which could result in material increases to the loss accrued.

The $12.4 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.

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. Based on additional facts and circumstances available to the Utility as of the date of this filing, including additional information from Cal Fire, the entry into the PSAs and the status of PG&E Corporation’s and the Utility’s efforts to reach a resolution with other holders of wildfire-related claims, 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 June 30, 2019.

The aggregate liability of $5.5 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.

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. However, as a result of PG&E Corporation’s and the Utility’s most recent settlement offer to holders of claims related to the Tubbs and 37 fires as of the date of this filing, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with such fires. With respect to 17 of the other 19 of the 2017 Northern California wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, Blue, Pocket, Atlas, Cascade, Point and Sonoma/Napa merged fires (which include the Nuns, Norrbom, Adobe, Partrick and Pythian 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. With respect to 2 of the other 19 of the 2017 Northern California wildfires (the Youngs and Pressley fires), PG&E Corporation and the Utility have 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 based on information that became available to PG&E Corporation and the Utility after the filing of their last Quarterly Report on Form 10-Q.

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 total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. 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 $5.5 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 Accounting Charge

The aggregate liability of $17.9 billion for claims in connection with the 2018 Camp fire and the 2017 Northern California wildfires is comprised of (i) $8.5 billion for subrogated insurance claimholders, (ii) $7.5 billion for individual claimholders (including those with uninsured and underinsured property losses, among other claims), (iii) $1.0 billion for the Supporting Public Entities with respect to their Public Entity Wildfire Claims pursuant to the PSAs and (iv) $900 million for clean-up and fire suppression costs. The aggregate liabilities of $8.5 billion for subrogated insurance claimholders and $7.5 billion for individual claimholders are based on PG&E Corporation’s and the Utility’s estimates of probable loss developed from data and other information available to PG&E Corporation and the Utility and PG&E Corporation’s and the Utility’s most recent settlement offers to representatives of such claimholders as of the date of this filing. PG&E Corporation and the Utility cannot predict the outcome or timing of discussions with such claimholders. With respect to the $1.0 billion liability for claims held by the Supporting Public Entities, while PG&E Corporation and the Utility previously disclosed the existence of claims asserted by such entities, PG&E Corporation and the Utility had not previously taken a charge related to these claims as the amount of the liability could not be reasonably estimated. As described above, the aggregate liability of $17.9 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.)

As of the date of this filing, PG&E Corporation and the Utility believe that the settlement discussions with representatives of subrogated insurance claimholders are in a particularly critical period of the negotiation. PG&E Corporation and the Utility believe that the potential exists for material developments in the negotiation in the near term. Accordingly, if PG&E Corporation, the Utility and such claimholders reach agreement, PG&E Corporation’s and the Utility’s probable loss contingency for the subrogated insurance claims may increase by a material amount, which would result in an additional accrual above the $8.5 billion reflected in this filing. Any such increase could be substantial and could be taken in the third quarter of 2019. In their motion submitted to the Bankruptcy Court on July 23, 2019, the Ad Hoc Subrogation Group stated that holders of subrogated insurance claims hold in excess of $20 billion of wildfire-related claims against PG&E Corporation and the Utility. In the “Restructuring Term Sheet” attached to such motion, the Ad Hoc Subrogation Group proposed terms for a plan of reorganization that would settle all such subrogated insurance claims for consideration valued at $15.8 billion. PG&E Corporation and the Utility cannot predict the outcome or timing of discussions with such claimholders.

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 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.

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 June 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.

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 following table presents changes in the insurance receivable for the six months ended June 30, 2019. The balance for insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:

(in millions)	Insurance Receivable
2018 Camp fire
Balance at December 31, 2018	$	1,380
Accrued insurance recoveries	—
Reimbursements	—
Balance at June 30, 2019	$	1,380
2017 Northern California wildfires
Balance at December 31, 2018	$	829
Accrued insurance recoveries	—
Reimbursements	—
Balance at June 30, 2019	$	829

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 customer harm threshold, 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 (the “Customer Harm Threshold”). 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 Customer Harm Threshold. 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 Customer Harm Threshold 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 Customer Harm Threshold 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 Customer Harm Threshold 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 Customer Harm Threshold 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 [Customer Harm Threshold], requires a utility to file a cost recovery application before the CHT [Customer Harm Threshold] will be determined, and erects ratepayer protection mechanisms as an extra-statutory hurdle for accessing the CHT [Customer Harm Threshold].” The Utility also argued that the CPUC should apply the Customer Harm Threshold methodology to costs related to the 2018 Camp fire.

The decision otherwise adopts a methodology to determine the Customer Harm Threshold 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 Customer Harm Threshold 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 Customer Harm Threshold. 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. 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.

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. 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. 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.

Wildfire-Related Securities Class Action Litigation

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 federal 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.

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, and PG&E Corporation and the Utility are currently seeking an order from the Bankruptcy Court to extend the stay to the officer, director, and underwriter defendants.

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.”

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 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.

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 $655 million for clean-up and repair of the Utility’s facilities (including $236 million in capital expenditures) through June 30, 2019, in connection with the 2018 Camp fire. The Utility also incurred costs of $334 million for clean-up and repair of the Utility’s facilities (including $161 million in capital expenditures) through June 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 June 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 June 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 will consist of $105 million deposited into a segregated account to be controlled by an independent third-party administrator appointed by the Bankruptcy Court, who will disburse and administer the funds. The administrator will be responsible for developing the specific eligibility requirements and application procedures for the distribution of the Wildfire Assistance Fund to eligible claimants. 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.

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.

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.

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. 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. It is expected that numerous wildfire-related claims will be filed against PG&E Corporation and the Utility in connection with the 2015 Butte fire through the Bar Date. 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 2015 Butte fire, as further described under the heading “Motion for the Establishment of Wildfire Claims Estimation Procedures” above.

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.

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 $226 million and $212 million as of December 31, 2018 and June 30, 2019, respectively, reflecting payments of $14 million in January 2019, prior to the Petition Date. As of June 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 June 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 $85 million and $50 million as of December 31, 2018 and June 30, 2019, respectively, reflecting reimbursements of $35 million during the six months ended June 30, 2019.

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.

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 Safety 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. As of April 30, 2019, to the Utility’s knowledge, no parties have submitted comments to the court on the 2019 Wildfire Safety Plan.

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’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’s Board of Directors assume responsibility for tracking progress of the 2019 Wildfire Safety 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.

CPUC and FERC Matters

Order Instituting an Investigation 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 requires 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 is 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 must 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.

The OII also indicates that the assigned commissioner shall set a prehearing conference for 45 to 60 days after the initiation of the proceeding or as soon as practicable after the CPUC makes the assignment. The assigned commissioner will also issue a scoping memo setting forth the scope of the proceeding and establishing a procedural schedule.

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.

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.

Order Instituting an Investigation 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.

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 reach a partial stipulation in order to streamline the proceeding.  On April 24, 2019, the Utility provided notice of a settlement conference and the parties have continued 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 the Utility’s 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. The parties continue settlement discussions. In accordance with the current procedural schedule issued by the ALJ on June 27, 2019, intervenor testimony is due August 16, 2019, and the Utility’s reply testimony is due September 18, 2019.  The SED’s rebuttal testimony is due October 4, 2019.  Evidentiary hearings are scheduled for October 21 to 25, 2019.

Based on the information available to PG&E Corporation and the Utility as of the date of this filing, PG&E Corporation and the Utility believe it is probable that the Utility will incur penalties, including fines or other remedies. Accordingly, PG&E Corporation and the Utility recorded a charge during the quarter ended June 30, 2019 for an amount that is not material, which corresponds to the lower end of the range of PG&E Corporation's and the Utility's reasonably estimated losses and is subject to change based on additional information.  PG&E Corporation and the Utility are unable to determine a better estimate within such range 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.

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.

Order Instituting an Investigation 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 (formerly known as the Office of Ratepayer Advocates or ORA), the SED, and TURN.

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 June 30, 2019, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets include an $16 million accrual 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 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 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.

At June 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. 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.

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)	June 30, 2019		December 31, 2018
Topock natural gas compressor station	$	346	$	369
Hinkley natural gas compressor station	142		146
Former manufactured gas plant sites owned by the Utility or third parties (1)	580		520
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	112		111
Fossil fuel-fired generation facilities and sites (3)	125		137
Total environmental remediation liability	$	1,305	$	1,283

⁽¹⁾ Primarily driven by the following sites: Vallejo, San Francisco East Harbor, Napa, Beach Street, San Francisco North Beach, and San Rafael MGP-Bio Marin MGP.

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

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

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 June 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 June 30, 2019, the Utility expected to recover $960 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 $302 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 2019 and finalized in 2020. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $139 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.

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 $528 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 $98 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 $86 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. For the period from August 1, 2019 through July 31, 2020, PG&E Corporation and the Utility have secured approximately $430 million for general wildfire liability (subject to an initial self-insured retention of $10 million per occurrence). PG&E Corporation and the Utility continue to pursue additional insurance coverage for the period from August 1, 2019 through July 30, 2020. 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 July 31, 2020 (consisting of the $430 million general wildfire liability coverage described above and $520 million for non-wildfire general liability) is approximately $190 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 June 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.

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 $5 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 June 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 six months ended June 30, 2019.

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SUBSEQUENT EVENTS

6 Months Ended

Jun. 30, 2019

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS

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.

AB 1054 provides that the Wildfire Fund will be established when Southern California Edison and San Diego Gas & Electric Company provide their initial contributions.

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;

• 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 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. The motion is expected to be heard on August 28, 2019, and objections and other responses are due August 21, 2019.

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 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.  The Utility is currently developing a Chapter 11 plan of reorganization that would provide for the financing of such required contributions, but there can be no assurance that PG&E Corporation and the Utility will successfully develop, 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.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

6 Months Ended

Jun. 30, 2019

Accounting Policies [Abstract]

Basis of Presentation

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 (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows for the periods presented.  The information at December 31, 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. 

Use of Estimates and Assumptions

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 pre-petition liabilities. 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

Variable Interest Entities

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 June 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 June 30, 2019, it did not consolidate any of them.

Pension and Other Post-Retirement Benefits

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.

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.

Revenue Recognition

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.

Recently Adopted Accounting Standards and Accounting Standards Issued But Not Yet Adopted

Recently Adopted Accounting Standards

Recognition of Lease Assets and Liabilities

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the guidance relating to the definition of a lease, the recognition of lease assets and lease liabilities on the balance sheet, and the disclosure of key information about leasing arrangements.  Under the new standard, all lessees must recognize a ROU asset, reflecting the right to use the underlying asset for the lease term, and a lease liability, reflecting the obligation to make lease payments, on the balance sheet. Operating leases were previously not recognized on the balance sheet.  PG&E Corporation and the Utility adopted the ASU 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, the Corporation and Utility elected to not separate lease and non-lease components. Additionally, PG&E Corporation and the Utility have elected not to restate comparative periods upon adoption.

PG&E Corporation and the Utility determine if an arrangement is a lease at inception. As most of the leases do not provide implicit discount rates, the Utility uses an estimate of its incremental secured borrowing rates based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities include only fixed lease payments. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Lease terms will only include options to extend or terminate the lease when it is reasonably certain that the Utility will exercise such options. The Utility recognizes lease expense in conformity with ratemaking.

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 six months ended June 30, 2019.

Cash payments arising from operating leases were $848 million for the six months ended June 30, 2019 and are presented within operating activities on the Condensed Consolidated Statement of Cash Flows. Cash payments for the principal portion of the financing lease liability will continue to be presented within financing activities. Variable lease payments not included in the financing lease liability, if any, are presented within operating activities. 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 fixed lease payments and excluding any variable lease payments. This amount is presented within the supplemental disclosures of noncash activities for the six months ended, June 30, 2019.

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, for terms between 5 years and 20 years. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related to property and land leases.

At June 30, 2019, the Utility’s operating 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 June 30, 2019		Six Months Ended June 30, 2019
Operating lease fixed cost	$	114	$	236
Operating lease variable cost	490		799
Total operating lease costs	$	604	$	1,035

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

(in millions)	June 30, 2019
2019 (1)	$	450
2020	679
2021	623
2022	548
2023	255
Thereafter	692
Total lease payments	3,247
Less imputed interest	(594		)
Total	$	2,653

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

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.

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. 

Use of Derivative Instruments

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.

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.

Valuation Techniques

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 six months ended June 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.

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

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.

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BANKRUPTCY FILING (Tables)

6 Months Ended

Jun. 30, 2019

Reorganizations [Abstract]

Schedule of Liabilities Subject to Compromise

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

(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Financing debt (2)	$	21,811	$	650	$	22,461
Wildfire-related claims (3)	18,012		—		18,012
Trade creditors	1,325		4		1,329
Non-qualified benefit plan	18		125		143
2001 bankruptcy disputed claims	221		—		221
Customer deposits & advances	278		—		278
Other	164		2		166
Total Liabilities Subject to Compromise	$	41,829	$	781	$	42,610

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

⁽²⁾ At June 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 $285 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. As described in Note 10 under the heading “Plan Support Agreements with Public Entities,” on June 18, 2019, PG&E Corporation and the Utility entered into agreements with certain local public entities to potentially resolve their wildfire-related claims through the Chapter 11 process.

Schedule of Debtor Reorganization Items

Reorganization items, net for the three months ended June 30, 2019 and from the Petition Date through June 30, 2019 include the following:

	Three Months Ended June 30, 2019
(in millions)	Utility			PG&E Corporation (1)			PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	—		$	—		$	—
Legal and other	75			1			76
Interest income	(18		)	(3		)	(21		)
Adjustments to LSTC	—			—			—
Trustee fees (2)	—			1			1
Total reorganization items, net	$	57		$	(1	)	$	56

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

⁽²⁾ PG&E Corporation and the Utility incurred $416,667 and $250,000, respectively, in fees to the U.S. Trustee in the three months ended June 30, 2019.

	Petition Date Through June 30, 2019
(in millions)	Utility			PG&E Corporation (1)			PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	97		$	17		$	114
Legal and other	98			2			100
Interest income	(27		)	(5		)	(32		)
Adjustments to LSTC	—			—			—
Trustee fees (2)	—			1			1
Total reorganization items, net	$	168		$	15		$	183

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

⁽²⁾ PG&E Corporation and the Utility incurred $416,667 and $250,000, respectively, in fees to the U.S. Trustee through June 30, 2019.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

6 Months Ended

Jun. 30, 2019

Accounting Policies [Abstract]

Components of Net Periodic Benefit Cost

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and six months ended June 30, 2019 and 2018 were as follows:

	Pension Benefits						Other Benefits
	Three Months Ended June 30,
(in millions)	2019			2018			2019			2018
Service cost for benefits earned (1)	$	111		$	129		$	14		$	17
Interest cost	190			172			19			18
Expected return on plan assets	(226		)	(256		)	(30		)	(32		)
Amortization of prior service cost	(2		)	(2		)	3			3
Amortization of net actuarial loss	—			2			(1		)	(2		)
Net periodic benefit cost	73			45			5			4
Regulatory account transfer (2)	10			39			—			—
Total	$	83		$	84		$	5		$	4

⁽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.

	Pension Benefits						Other Benefits
	Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Service cost for benefits earned (1)	$	222		$	257		$	28		$	33
Interest cost	379			344			38			35
Expected return on plan assets	(453		)	(511		)	(61		)	(65		)
Amortization of prior service cost	(3		)	(3		)	7			7
Amortization of net actuarial loss	1			3			(2		)	(3		)
Net periodic benefit cost	146			90			10			7
Regulatory account transfer (2)	21			77			—			—
Total	$	167		$	167		$	10		$	7

⁽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

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 June 30, 2019
Beginning balance	$	(21	)	$	17		$	(4	)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $1 and $1, respectively) (1)	(1		)	2			1
Amortization of net actuarial loss (net of taxes of $0 and $1, respectively) (1)	—			—			—
Regulatory account transfer (net of taxes of $1 and $0, respectively) (1)	1			(2		)	(1		)
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)	Three Months Ended June 30, 2018
Beginning balance	$	(30	)	$	17		$	(13	)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1 and $1, respectively)	(1		)	2			1
Amortization of net actuarial loss (net of taxes of $1 and $1, respectively)	1			(1		)	—
Regulatory account transfer (net of taxes of $0 and $0, respectively)	—			(1		)	(1		)
Net current period other comprehensive gain (loss)	—			—			—
Ending balance	$	(30	)	$	17		$	(13	)

⁽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)	Six Months Ended June 30, 2019
Beginning balance	$	(21	)	$	17		$	(4	)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $1 and $2, respectively) (1)	(2		)	5			3
Amortization of net actuarial loss (net of taxes of $0 and $1, respectively) (1)	1			(1		)	—
Regulatory account transfer (net of taxes of $1 and $1, respectively) (1)	1			(4		)	(3		)
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)	Six Months Ended June 30, 2018
Beginning balance	$	(25	)	$	17		$	(8	)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $1 and $2, respectively) (1)	(2		)	5			3
Amortization of net actuarial loss (net of taxes of $1 and $1, respectively) (1)	2			(2		)	—
Regulatory account transfer (net of taxes of $0 and $1, respectively) (1)	—			(3		)	(3		)
Reclassification of stranded income tax to retained earnings	(5		)	—			(5		)
Net current period other comprehensive gain (loss)	(5		)	—			(5		)
Ending balance	$	(30	)	$	17		$	(13	)

⁽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.)

Summary of Revenues Disaggregated by Type of Customer

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

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Electric
Revenue from contracts with customers
Residential	$	994		$	1,039		$	2,282		$	2,375
Commercial	1,135			1,234			2,088			2,307
Industrial	326			354			619			678
Agricultural	261			318			347			443
Public street and highway lighting	16			18			33			38
Other (1)	—			84			(309		)	(118		)
Total revenue from contracts with customers - electric	2,732			3,047			5,060			5,723
Regulatory balancing accounts (2)	214			265			678			540
Total electric operating revenue	$	2,946		$	3,312		$	5,738		$	6,263
Natural gas
Revenue from contracts with customers
Residential	$	343		$	452		$	1,515		$	1,410
Commercial	129			119			369			315
Transportation service only	304			264			686			560
Other (1)	(129		)	(128		)	(205		)	(179		)
Total revenue from contracts with customers - gas	647			707			2,365			2,106
Regulatory balancing accounts (2)	350			215			(149		)	(79		)
Total natural gas operating revenue	997			922			2,216			2,027
Total operating revenues	$	3,943		$	4,234		$	7,954		$	8,290

⁽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.

Schedule of Lease Expense

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 June 30, 2019		Six Months Ended June 30, 2019
Operating lease fixed cost	$	114	$	236
Operating lease variable cost	490		799
Total operating lease costs	$	604	$	1,035

Schedule of Future Expected Operating Lease Payments and Expected Obligations for Power Purchase and Other Lease Commitments

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

(in millions)	June 30, 2019
2019 (1)	$	450
2020	679
2021	623
2022	548
2023	255
Thereafter	692
Total lease payments	3,247
Less imputed interest	(594		)
Total	$	2,653

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

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

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Tables)

6 Months Ended

Jun. 30, 2019

Regulated Operations [Abstract]

Long-Term Regulatory Assets

Long-term regulatory assets are comprised of the following:

	Asset Balance at
(in millions)	June 30, 2019		December 31, 2018
Pension benefits (1)	$	1,928	$	1,947
Environmental compliance costs	997		1,013
Utility retained generation (2)	251		274
Price risk management	67		90
Unamortized loss, net of gain, on reacquired debt (3)	230		76
Catastrophic event memorandum account (4)	918		790
Wildfire expense memorandum account (5)	127		94
Fire hazard prevention memorandum account (6)	291		263
Fire risk mitigation memorandum account (7)	154		—
Other	386		417
Total long-term regulatory assets	$	5,349	$	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 the accelerated amortization of premiums and debt issuance costs on pre-petition debt.

⁽⁴⁾ 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.

⁽⁵⁾ Includes specific incremental wildfire liability costs the CPUC approved for tracking in June 2018. Recovery of WEMA costs are subject to CPUC review and approval.

⁽⁶⁾ 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.

⁽⁷⁾ Includes costs associated with the 2019 Wildfire Safety Plan. Recovery of FHPMA costs are subject to CPUC review and approval.

Long-Term Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

	Liability Balance at
(in millions)	June 30, 2019		December 31, 2018
Cost of removal obligations (1)	$	6,233	$	5,981
Deferred income taxes (2)	4		283
Recoveries in excess of AROs (3)	472		356
Public purpose programs (4)	785		674
Employee benefit plans (5)	423		421
Other	1,121		824
Total long-term regulatory liabilities	$	9,038	$	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 net of amounts owed to customers for deferred taxes collected at higher rates before the Tax Act and amounts owed to the Utility for reversal of deferred taxes subject to flow-through treatment.

⁽³⁾ 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.)

⁽⁴⁾ 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.

⁽⁵⁾ Represents cumulative differences between incurred costs and amounts collected in rates for Post-Retirement Medical, Post-Retirement Life and Long Term Disability Plans.

Regulatory Balancing Accounts Receivable

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

	Receivable Balance at
(in millions)	June 30, 2019		December 31, 2018
Electric distribution	$	465	$	160
Electric transmission	91		128
Utility generation	92		79
Gas distribution and transmission	173		462
Energy procurement	654		168
Public purpose programs	97		111
Other	312		327
Total regulatory balancing accounts receivable	$	1,884	$	1,435

Regulatory Balancing Accounts Payable

	Payable Balance at
(in millions)	June 30, 2019		December 31, 2018
Electric transmission	135		134
Gas distribution and transmission	6		9
Energy procurement	308		59
Public purpose programs	610		587
Other	311		287
Total regulatory balancing accounts payable	$	1,370	$	1,076

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DEBT (Tables)

6 Months Ended

Jun. 30, 2019

Debt Disclosure [Abstract]

Schedule of Debtor-in-Possession Financing

The following table summarizes the Utility’s outstanding borrowings and availability under the DIP Facilities at June 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	$	—	$	521	$	3,479

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

Schedule of 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	June 30, 2019		December 31, 2018
Debt Subject to Compromise (1)
PG&E Corporation
Borrowings under Pre-Petition Credit Facilities
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)	2,965		2,965
Other borrowings:
Term Loan - Stated Maturity: 2019	variable rate(10)	250		250
Total Borrowings under Pre-Petition Credit Facility Subject to Compromise		3,215		3,215
Total Utility Debt Subject to Compromise		21,603		21,425
Total PG&E Corporation Consolidated Debt Subject to Compromise		$	22,253	$	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 $285 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 June 30, 2019, the contractual LIBOR-based interest rate on loans was 3.87%.

⁽³⁾ At June 30, 2019, the contractual LIBOR-based interest rate on the term loan was 3.60%.

⁽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 June 30, 2019, the contractual interest rate on the letter of credit facility supporting these bonds was 7.70%.

⁽⁷⁾ At June 30, 2019, the contractual interest rate on the letter of credit facility supporting these bonds ranged from 7.70% to 7.83%.

⁽⁸⁾ Also includes $79 million in letters of credit.

⁽⁹⁾ At June 30, 2019, the contractual LIBOR-based interest rate on the loans was 3.67%.

⁽¹⁰⁾ At June 30, 2019, the contractual LIBOR-based interest rate on the term loan was 3.00%.

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EARNINGS PER SHARE (Tables)

6 Months Ended

Jun. 30, 2019

Earnings Per Share [Abstract]

Reconciliation of PG&E Corporation's Income Available for Common Shareholders and Weighted Average Common Shares Outstanding for Calculating 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 June 30,						Six Months Ended June 30,
(in millions, except per share amounts)	2019			2018			2019			2018
Loss attributable to common shareholders	$	(2,553	)	$	(984	)	$	(2,420	)	$	(542	)
Weighted average common shares outstanding, basic	529			516			528			516
Add incremental shares from assumed conversions:
Employee share-based compensation	—			—			—			1
Weighted average common shares outstanding, diluted	529			516			528			517
Total loss per common share, diluted	$	(4.83	)	$	(1.91	)	$	(4.58	)	$	(1.05	)

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DERIVATIVES (Tables)

6 Months Ended

Jun. 30, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Volumes Of Outstanding Derivative Contracts

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

		Contract Volume at
Underlying Product	Instruments	June 30, 2019	December 31, 2018
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	174,575,917	177,750,349
	Options	16,455,000	13,735,405
Electricity (Megawatt-hours)	Forwards, Futures and Swaps	2,999,616	3,833,490
	Options	912,033	—
	Congestion Revenue Rights (3)	329,571,344	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.

Schedule of Offsetting Assets

At June 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	$	47		$	(4	)	$	48	$	91
Other noncurrent assets – other	161			—			—		161
Current liabilities – other	(25		)	4			3		(18		)
Noncurrent liabilities – other	(67		)	—			—		(67		)
Total commodity risk	$	116		$	—		$	51	$	167

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

Schedule of Offsetting Liabilities

At June 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	$	47		$	(4	)	$	48	$	91
Other noncurrent assets – other	161			—			—		161
Current liabilities – other	(25		)	4			3		(18		)
Noncurrent liabilities – other	(67		)	—			—		(67		)
Total commodity risk	$	116		$	—		$	51	$	167

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

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FAIR VALUE MEASUREMENTS (Tables)

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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
	June 30, 2019
(in millions)	Level 1		Level 2		Level 3		Netting (1)			Total
Assets:
Short-term investments	$	3,402	$	—	$	—	$	—		$	3,402
Nuclear decommissioning trusts
Short-term investments	16		—		—		—			16
Global equity securities	1,959		—		—		—			1,959
Fixed-income securities	815		698		—		—			1,513
Assets measured at NAV	—		—		—		—			19
Total nuclear decommissioning trusts (2)	2,790		698		—		—			3,507
Price risk management instruments (Note 8)
Electricity	—		13		192		20			225
Gas	—		3		—		24			27
Total price risk management instruments	—		16		192		44			252
Rabbi trusts
Fixed-income securities	—		98		—		—			98
Life insurance contracts	—		71		—		—			71
Total rabbi trusts	—		169		—		—			169
Long-term disability trust
Short-term investments	5		—		—		—			5
Assets measured at NAV	—		—		—		—			142
Total long-term disability trust	5		—		—		—			147
TOTAL ASSETS	$	6,197	$	883	$	192	$	44		$	7,477
Liabilities:
Price risk management instruments (Note 8)
Electricity	$	—	$	4	$	83	$	(4	)	$	83
Gas	2		3		—		(3		)	2
TOTAL LIABILITIES	$	2	$	7	$	83	$	(7	)	$	85

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

⁽²⁾ Represents amount before deducting $491 million, primarily related to deferred taxes on appreciation of investment value.

	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.

Level 3 Measurements and Sensitivity Analysis

	Fair Value at
(in millions)	June 30, 2019
Fair Value Measurement	Assets		Liabilities		Valuation Technique	Unobservable Input	Range (1)
Congestion revenue rights	$	191	$	64	Market approach	CRR auction prices	$(13.11) - 22.76
Power purchase agreements	$	1	$	19	Discounted cash flow	Forward prices	$ 19.68 - 38.80

 ⁽¹⁾ Represents price per megawatt-hour.

	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 six months ended June 30, 2019 and 2018:

	Price Risk Management Instruments
(in millions)	2019			2018
Asset (liability) balance as of April 1	$	129		$	40
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)	(20		)	(6		)
Asset (liability) balance as of June 30	$	109		$	34

⁽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 (liability) balance as of January 1	$	95	$	42
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts (1)	14		(8		)
Asset (liability) balance as of June 30	$	109	$	34

⁽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.

Carrying Amount and Fair Value of Financial Instruments

The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):

	At June 30, 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		1,500		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 4.

⁽²⁾ The Utility drew $350 million from the DIP Revolving Facility on February 1, 2019 which was subsequently repaid on April 3, 2019 using certain of the proceeds of the DIP Initial Term Loan Facility.

Schedule of Unrealized Gains (Losses) Related to Available-For-Sale Investments

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

(in millions)
As of June 30, 2019	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Total Fair Value
Nuclear decommissioning trusts
Short-term investments	$	16	$	—	$	—		$	16
Global equity securities	496		1,486		(4		)	1,978
Fixed-income securities	1,431		84		(2		)	1,513
Total (1)	$	1,943	$	1,570	$	(6	)	$	3,507
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 $491 million and $408 million for the periods ended June 30, 2019 and December 31, 2018, respectively, primarily related to deferred taxes on appreciation of investment value.

Schedule of Maturities on Debt Instruments

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

	As of
(in millions)	June 30, 2019
Less than 1 year	$	26
1–5 years	541
5–10 years	340
More than 10 years	606
Total maturities of fixed-income securities	$	1,513

Schedule of Activity for Debt and Equity Securities

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

	Three Months Ended June 30,						Six Months Ended June 30,
(in millions)	2019			2018			2019			2018
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	171		$	308		$	517		$	802
Gross realized gains on securities	56			11			22			48
Gross realized losses on securities	(26		)	(5		)	(7		)	(9		)

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WILDFIRE-RELATED CONTINGENCIES (Tables)

6 Months Ended

Jun. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

Schedule of Environmental Remediation Liability

At June 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)	June 30, 2019		December 31, 2018
2015 Butte fire	$	212	$	226
2017 Northern California wildfires	5,500		3,500
2018 Camp fire	12,400		10,500
Total wildfire-related claims (1)	$	18,112	$	14,226

⁽¹⁾ On the Petition Date, all wildfire-related claims were classified as LSTC and all pending litigation was stayed. As of June 30, 2019, $100 million was reclassified from LSTC to current liabilities - wildfire-related claims to reflect Bankruptcy Court approval of contributions to the Wildfire Assistance Fund.

Change in Accruals Related to Third-Party Claims

The following table presents changes in the insurance receivable for the six months ended June 30, 2019. The balance for insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:

(in millions)	Insurance Receivable
2018 Camp fire
Balance at December 31, 2018	$	1,380
Accrued insurance recoveries	—
Reimbursements	—
Balance at June 30, 2019	$	1,380
2017 Northern California wildfires
Balance at December 31, 2018	$	829
Accrued insurance recoveries	—
Reimbursements	—
Balance at June 30, 2019	$	829

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OTHER CONTINGENCIES AND COMMITMENTS (Tables)

6 Months Ended

Jun. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

Schedule of Environmental Remediation Liability

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)	June 30, 2019		December 31, 2018
Topock natural gas compressor station	$	346	$	369
Hinkley natural gas compressor station	142		146
Former manufactured gas plant sites owned by the Utility or third parties (1)	580		520
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	112		111
Fossil fuel-fired generation facilities and sites (3)	125		137
Total environmental remediation liability	$	1,305	$	1,283

⁽¹⁾ Primarily driven by the following sites: Vallejo, San Francisco East Harbor, Napa, Beach Street, San Francisco North Beach, and San Rafael MGP-Bio Marin MGP.

⁽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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ORGANIZATION AND BASIS OF PRESENTATION (Details)	6 Months Ended
	Jun. 30, 2019 segment
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of operating segments (segment)	1

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BANKRUPTCY FILING (Narrative) (Details)	5 Months Ended	6 Months Ended
	Jun. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)	Jul. 17, 2019 unit	Feb. 01, 2019 USD ($)	Jan. 31, 2019 USD ($)
Debt Instrument [Line Items]
Contractual interest expense on prepetition liabilities not recorded in financial statements	$ 405,000,000
DIP Credit Agreement | Line of Credit | Senior Secured Superpriority Debt
Debt Instrument [Line Items]
Amount arranged	$ 5,500,000,000	$ 5,500,000,000		$ 5,500,000,000	$ 5,500,000,000
Pacific Gas & Electric Co
Debt Instrument [Line Items]
Payments for reorganization items		78,000,000
PG&E Corporation
Debt Instrument [Line Items]
Payments for reorganization items		$ 15,000,000
Subsequent Event | Pacific Gas & Electric Co
Debt Instrument [Line Items]
Number of collective bargaining units (unit) | unit			2

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BANKRUPTCY FILING (Schedule of Liabilities Subject to Compromise) (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Reorganizations [Line Items]
Financing debt	$ 22,461
Wildfire-related claims	18,012
Trade creditors	1,329
Non-qualified benefit plan	143
2001 bankruptcy disputed claims	221
Customer deposits & advances	278
Other	166
Total Liabilities Subject to Compromise	42,610	$ 0
Pacific Gas & Electric Co
Reorganizations [Line Items]
Financing debt	21,811
Wildfire-related claims	18,012
Trade creditors	1,325
Non-qualified benefit plan	18
2001 bankruptcy disputed claims	221
Customer deposits & advances	278
Other	164
Total Liabilities Subject to Compromise	41,829	$ 0
Aggregate principal amount of debt subject to compromise	21,526
Accrued contractual interest subject to compromise	285
PG&E Corporation
Reorganizations [Line Items]
Financing debt	650
Wildfire-related claims	0
Trade creditors	4
Non-qualified benefit plan	125
2001 bankruptcy disputed claims	0
Customer deposits & advances	0
Other	2
Total Liabilities Subject to Compromise	781
Aggregate principal amount of debt subject to compromise	$ 650

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Components of Net Periodic Benefit Cost) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	$ 111	$ 129	$ 222	$ 257
Interest cost	190	172	379	344
Expected return on plan assets	(226)	(256)	(453)	(511)
Amortization of prior service cost	(2)	(2)	(3)	(3)
Amortization of net actuarial loss	0	2	1	3
Net periodic benefit cost	73	45	146	90
Regulatory account transfer	10	39	21	77
Total	83	84	167	167
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost for benefits earned	14	17	28	33
Interest cost	19	18	38	35
Expected return on plan assets	(30)	(32)	(61)	(65)
Amortization of prior service cost	3	3	7	7
Amortization of net actuarial loss	(1)	(2)	(2)	(3)
Net periodic benefit cost	5	4	10	7
Regulatory account transfer	0	0	0	0
Total	$ 5	$ 4	$ 10	$ 7

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BANKRUPTCY FILING (Schedule of Debtor Reorganization Items) (Details) - USD ($)	3 Months Ended		5 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2019	Jun. 30, 2018
Reorganizations [Line Items]
Debtor-in-possession financing costs	$ 0		$ 114,000,000
Legal and other	76,000,000		100,000,000
Interest income	(21,000,000)		(32,000,000)
Adjustments to LSTC	0		0
Trustee fees	1,000,000		1,000,000
Total reorganization items, net	56,000,000	$ 0	183,000,000	$ 183,000,000	$ 0
PG&E Corporation
Reorganizations [Line Items]
Debtor-in-possession financing costs	0		17,000,000
Legal and other	1,000,000		2,000,000
Interest income	(3,000,000)		(5,000,000)
Adjustments to LSTC	0		0
Trustee fees	1,000,000		1,000,000
Total reorganization items, net	(1,000,000)		15,000,000
Fees paid to the U.S. Trustee	416,667		416,667
Utility
Reorganizations [Line Items]
Debtor-in-possession financing costs	0		97,000,000
Legal and other	75,000,000		98,000,000
Interest income	(18,000,000)		(27,000,000)
Adjustments to LSTC	0		0
Trustee fees	0		0
Total reorganization items, net	57,000,000	$ 0	168,000,000	$ 168,000,000	$ 0
Fees paid to the U.S. Trustee	$ 250,000		$ 250,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Reclassifications Out of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	$ 13,129		$ 12,903	$ 19,472
Net current period other comprehensive gain (loss)	0	$ 0	0	(5)
Ending balance	10,594	19,061	10,594	19,061
Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Net current period other comprehensive gain (loss)	0	0	0	(5)
Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Net current period other comprehensive gain (loss)	0	0	0	0
Accumulated Other Comprehensive Income (Loss)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(4)	(13)	(4)	(8)
Ending balance	(4)	(13)	(4)	(13)
Accumulated Other Comprehensive Income (Loss) | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	(21)	(30)	(21)	(25)
Ending balance	(21)	(30)	(21)	(30)
Accumulated Other Comprehensive Income (Loss) | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Beginning balance	17	17	17	17
Ending balance	17	17	17	17
Amortization of prior service cost
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	1	1	3	3
Amortization of prior service cost | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(1)	(1)	(2)	(2)
Amount attributable to tax	1	1	1	1
Amortization of prior service cost | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	2	2	5	5
Amount attributable to tax	1	1	2	2
Amortization of net actuarial loss
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	0	0	0	0
Amortization of net actuarial loss | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	0	1	1	2
Amount attributable to tax	0	1	0	1
Amortization of net actuarial loss | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	0	(1)	(1)	(2)
Amount attributable to tax	1	1	1	1
Regulatory account transfer
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(1)	(1)	(3)	(3)
Regulatory account transfer | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	1	0	1	0
Amount attributable to tax	1	0	1	0
Regulatory account transfer | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income	(2)	(1)	(4)	(3)
Amount attributable to tax	$ 0	$ 0	$ 1	1
Reclassification of stranded income tax to retained earnings
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income				(5)
Reclassification of stranded income tax to retained earnings | Pension Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income				(5)
Reclassification of stranded income tax to retained earnings | Other Benefits
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amounts reclassified from other comprehensive income				$ 0

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jan. 01, 2019
Lessee, Lease, Description [Line Items]
Period for probable revenue recovery	24 months
Cash payments arising from operating leases	$ 848
ROU assets	2,662
Lease liabilities	$ 2,653
Weighted average remaining lease term	6 years 1 month 13 days
Weighted average discount rate	6.10%
Minimum
Lessee, Lease, Description [Line Items]
Power purchase agreement, term	5 years
Maximum
Lessee, Lease, Description [Line Items]
Power purchase agreement, term	20 years
Accounting Standards Update 2016-02
Lessee, Lease, Description [Line Items]
ROU assets		$ 2,800
Lease liabilities		$ 2,800

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Revenues Disaggregated by Type of Customer) (Details) - Pacific Gas & Electric Co - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Revenue from contracts with customers
Total operating revenues	$ 3,943	$ 4,234	$ 7,954	$ 8,290
Electric
Revenue from contracts with customers
Total revenue from contracts with customers	2,732	3,047	5,060	5,723
Regulatory balancing accounts	214	265	678	540
Total operating revenues	2,946	3,312	5,738	6,263
Electric | Residential
Revenue from contracts with customers
Total revenue from contracts with customers	994	1,039	2,282	2,375
Electric | Commercial
Revenue from contracts with customers
Total revenue from contracts with customers	1,135	1,234	2,088	2,307
Electric | Industrial
Revenue from contracts with customers
Total revenue from contracts with customers	326	354	619	678
Electric | Agricultural
Revenue from contracts with customers
Total revenue from contracts with customers	261	318	347	443
Electric | Public street and highway lighting
Revenue from contracts with customers
Total revenue from contracts with customers	16	18	33	38
Electric | Other
Revenue from contracts with customers
Total revenue from contracts with customers	0	84	(309)	(118)
Natural gas
Revenue from contracts with customers
Total revenue from contracts with customers	647	707	2,365	2,106
Regulatory balancing accounts	350	215	(149)	(79)
Total operating revenues	997	922	2,216	2,027
Natural gas | Residential
Revenue from contracts with customers
Total revenue from contracts with customers	343	452	1,515	1,410
Natural gas | Commercial
Revenue from contracts with customers
Total revenue from contracts with customers	129	119	369	315
Natural gas | Transportation service only
Revenue from contracts with customers
Total revenue from contracts with customers	304	264	686	560
Natural gas | Other
Revenue from contracts with customers
Total revenue from contracts with customers	$ (129)	$ (128)	$ (205)	$ (179)

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Schedule of Lease Expense) (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Accounting Policies [Abstract]
Operating lease fixed cost	$ 114	$ 236
Operating lease variable cost	490	799
Total operating lease costs	$ 604	$ 1,035

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Future Expected Operating Lease Payments and Expected Obligations for Power Purchase and Other Lease Commitments) (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Future Expected Operating Lease Payments
2019	$ 450
2020	679
2021	623
2022	548
2023	255
Thereafter	692
Total lease payments	3,247
Less imputed interest	(594)
Total	$ 2,653
Future Expected Obligations and Other Lease Commitments
2019		$ 684
2020		677
2021		621
2022		546
2023		252
Thereafter		581
Total lease commitments		$ 3,361

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Assets) (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 5,349	$ 4,964
Retained generation asset costs	1,200
Pension benefits
Regulatory Assets [Line Items]
Total long-term regulatory assets	1,928	1,947
Environmental compliance costs
Regulatory Assets [Line Items]
Total long-term regulatory assets	997	1,013
Utility retained generation
Regulatory Assets [Line Items]
Total long-term regulatory assets	251	274
Price risk management
Regulatory Assets [Line Items]
Total long-term regulatory assets	67	90
Unamortized loss, net of gain, on reacquired debt
Regulatory Assets [Line Items]
Total long-term regulatory assets	230	76
Catastrophic event memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	918	790
Wildfire expense memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	127	94
Fire hazard prevention memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	291	263
Fire risk mitigation memorandum account
Regulatory Assets [Line Items]
Total long-term regulatory assets	154	0
Other
Regulatory Assets [Line Items]
Total long-term regulatory assets	$ 386	$ 417

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Long-Term Regulatory Liabilities) (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 9,038	$ 8,539
Cost of removal obligations
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	6,233	5,981
Deferred income taxes
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	4	283
Recoveries in excess of AROs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	472	356
Public purpose programs
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	785	674
Employee benefit plans
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	423	421
Other
Regulatory Liabilities [Line Items]
Total long-term regulatory liabilities	$ 1,121	$ 824

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REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS (Current Regulatory Balancing Accounts, Net) (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Total regulatory balancing accounts receivable
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 1,884	$ 1,435
Total regulatory balancing accounts receivable | Electric distribution
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	465	160
Total regulatory balancing accounts receivable | Electric transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	91	128
Total regulatory balancing accounts receivable | Utility generation
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	92	79
Total regulatory balancing accounts receivable | Gas distribution and transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	173	462
Total regulatory balancing accounts receivable | Energy procurement
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	654	168
Total regulatory balancing accounts receivable | Public purpose programs
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	97	111
Total regulatory balancing accounts receivable | Other
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	312	327
Total regulatory balancing accounts payable
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	1,370	1,076
Total regulatory balancing accounts payable | Electric transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	135	134
Total regulatory balancing accounts payable | Gas distribution and transmission
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	6	9
Total regulatory balancing accounts payable | Energy procurement
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	308	59
Total regulatory balancing accounts payable | Public purpose programs
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	610	587
Total regulatory balancing accounts payable | Other
Regulatory Assets [Line Items]
Total regulatory balancing accounts, net	$ 311	$ 287

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DEBT (Debtor In Possession ("DIP") Facilities and Financing) (Details)	Jun. 30, 2019 USD ($)	Apr. 03, 2019 USD ($)	Mar. 27, 2019 USD ($)	Feb. 01, 2019 USD ($)	Jan. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Line of Credit Facility [Line Items]
Debtor-in-possession financing	$ 1,500,000,000					$ 0
Commercial Paper	0
Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Debtor-in-possession financing	1,500,000,000					0
Commercial Paper	0
Senior Secured Superpriority Debt | Line of Credit | DIP Credit Agreement
Line of Credit Facility [Line Items]
Amount arranged	5,500,000,000			$ 5,500,000,000	$ 5,500,000,000
DIP Revolving Facility | Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Revolver Borrowings	2,965,000,000					$ 2,965,000,000
Letters of Credit Outstanding	79,000,000
DIP Revolving Facility | DIP Credit Agreement | Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Aggregate Limit	5,500,000,000
Term Loan Borrowings	1,500,000,000
Revolver Borrowings	0
Letters of Credit Outstanding	521,000,000
Aggregate Availability	$ 3,479,000,000
Extension fee	0.25
DIP Revolving Facility | Line of Credit | DIP Credit Agreement
Line of Credit Facility [Line Items]
Amount arranged				3,500,000,000
DIP Revolving Facility | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Debtor-in-possession financing				1,500,000,000
Letter of Credit Subfacility | Line of Credit | DIP Credit Agreement
Line of Credit Facility [Line Items]
Amount arranged				1,500,000,000
Letter of Credit Subfacility | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Amount arranged			$ 1,500,000,000
Letters of credit available				750,000,000
DIP Initial Term Loan Facility | Line of Credit | DIP Credit Agreement
Line of Credit Facility [Line Items]
Amount arranged				1,500,000,000
DIP Initial Term Loan Facility | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Amount arranged		$ 1,500,000,000
DIP Delayed Draw Term Loan Facility | Line of Credit | DIP Credit Agreement
Line of Credit Facility [Line Items]
Amount arranged				500,000,000
DIP Delayed Draw Term Loan Facility | Line of Credit | DIP Credit Agreement | Pacific Gas & Electric Co
Line of Credit Facility [Line Items]
Amount arranged				350,000,000
Repayments of debt		$ 350,000,000
DIP Incremental Facilities | Line of Credit | DIP Credit Agreement
Line of Credit Facility [Line Items]
Amount arranged				$ 4,000,000,000.0

XML

DEBT (Schedule of Long-term Debt) (Details) - USD ($) $ in Millions	Mar. 31, 2019	Jun. 30, 2019	Dec. 31, 2018
Debt [Line Items]
Debt subject to compromise		$ 22,253	$ 22,075
Debtor reorganization items, write-off of debt issuance costs and debt discounts	$ 178
Pacific Gas & Electric Co
Debt [Line Items]
Debt subject to compromise		21,603	21,425
Borrowings under Pre-Petition Credit Facility		3,215	3,215
Pollution control bonds		863	863
Accrued contractual interest subject to compromise		285
PG&E Corporation
Debt [Line Items]
Debt subject to compromise		650	650
Term Loan - Stated Maturity: 2020 | PG&E Corporation
Debt [Line Items]
Debt subject to compromise		$ 350	350
Interest rate at period end		3.60%
Senior Notes Due 2020 | Pacific Gas & Electric Co
Debt [Line Items]
Contractual Interest Rates		3.50%
Senior Notes Due 2022 | Pacific Gas & Electric Co
Debt [Line Items]
Contractual Interest Rates		2.45%
Pollution Control Bonds - Series 2008 F and 2010 E, due 2026 | Pacific Gas & Electric Co
Debt [Line Items]
Contractual Interest Rates		1.75%
Pollution control bonds		$ 100	100
Pollution Control Bonds - Series 2009 A-B, due 2026 | Pacific Gas & Electric Co
Debt [Line Items]
Pollution control bonds		149	149
Pollution Control Bonds - Series 1996 C, E, F, 1997 B due 2026 | Pacific Gas & Electric Co
Debt [Line Items]
Pollution control bonds		614	614
Term Loan - Stated Maturity: 2019 | Pacific Gas & Electric Co
Debt [Line Items]
Other borrowings		$ 250	250
Interest rate at period end		3.00%
Revolving Credit Facility | Pacific Gas & Electric Co
Debt [Line Items]
Borrowings under Pre-Petition Credit Facilities		$ 2,965	2,965
Interest rate at period end		3.67%
Letters of credit outstanding		$ 79
Line of Credit | Revolving Credit Facility | PG&E Corporation
Debt [Line Items]
Debt subject to compromise		$ 300	300
Interest rate at period end		3.87%
Senior Notes | Pacific Gas & Electric Co
Debt [Line Items]
Unamortized discount, net of premium and debt issuance costs		$ 0	(178)
Borrowings under Pre-Petition Credit Facility		17,525	17,347
Senior Notes | Senior Notes Due 2020 | Pacific Gas & Electric Co
Debt [Line Items]
Senior notes		800	800
Senior Notes | Senior Notes Due 2021 | Pacific Gas & Electric Co
Debt [Line Items]
Senior notes		$ 550	550
Senior Notes | Senior Notes Due 2021 | Pacific Gas & Electric Co | Minimum
Debt [Line Items]
Contractual Interest Rates		3.25%
Senior Notes | Senior Notes Due 2021 | Pacific Gas & Electric Co | Maximum
Debt [Line Items]
Contractual Interest Rates		4.25%
Senior Notes | Senior Notes Due 2022 | Pacific Gas & Electric Co
Debt [Line Items]
Senior notes		$ 400	400
Senior Notes | Senior Notes Due 2023 | Pacific Gas & Electric Co
Debt [Line Items]
Senior notes		$ 1,175	1,175
Senior Notes | Senior Notes Due 2023 | Pacific Gas & Electric Co | Minimum
Debt [Line Items]
Contractual Interest Rates		3.25%
Senior Notes | Senior Notes Due 2023 | Pacific Gas & Electric Co | Maximum
Debt [Line Items]
Contractual Interest Rates		4.25%
Senior Notes | Senior Notes Due 2024 through 2047 | Pacific Gas & Electric Co
Debt [Line Items]
Senior notes		$ 14,600	$ 14,600
Senior Notes | Senior Notes Due 2024 through 2047 | Pacific Gas & Electric Co | Minimum
Debt [Line Items]
Contractual Interest Rates		2.95%
Senior Notes | Senior Notes Due 2024 through 2047 | Pacific Gas & Electric Co | Maximum
Debt [Line Items]
Contractual Interest Rates		6.35%
Letter of Credit | Pollution Control Bonds - Series 2009 A-B, due 2026 | Pacific Gas & Electric Co
Debt [Line Items]
Interest rate at period end		7.70%
Letter of Credit | Pollution Control Bonds - Series 1996 C, E, F, 1997 B due 2026 | Pacific Gas & Electric Co | Minimum
Debt [Line Items]
Interest rate at period end		7.70%
Letter of Credit | Pollution Control Bonds - Series 1996 C, E, F, 1997 B due 2026 | Pacific Gas & Electric Co | Maximum
Debt [Line Items]
Interest rate at period end		7.83%

XML

EQUITY (Details) - 401K Plan and Shared Based Compensation Plans shares in Millions, $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($) shares
Schedule Of Changes In Equity [Line Items]
Stock issued during period (in shares) | shares	8.9
Cash proceeds from stock issuance | $	$ 85

XML

EARNINGS PER SHARE (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Earnings Per Share [Abstract]
Loss attributable to common shareholders	$ (2,553)	$ (984)	$ (2,420)	$ (542)
Weighted average common shares outstanding, basic (in shares)	529	516	528	516
Add incremental shares from assumed conversions:
Employee share-based compensation (in shares)	0	0	0	1
Weighted average common shares outstanding, diluted (in shares)	529	516	528	517
Total loss per common share, diluted (in dollars per share)	$ (4.83)	$ (1.91)	$ (4.58)	$ (1.05)

XML

DERIVATIVES (Volumes of Outstanding Derivative Contracts, in Megawatt Hours Unless Otherwise Specified) (Details)	Jun. 30, 2019 MWh MMBTU	Dec. 31, 2018 MWh MMBTU
Forwards, Futures and Swaps | Natural Gas
Derivative [Line Items]
Contract Volume (mmbtu and mwh) | MMBTU	174,575,917	177,750,349
Forwards, Futures and Swaps | Electricity
Derivative [Line Items]
Contract Volume (mmbtu and mwh)	2,999,616	3,833,490
Options | Natural Gas
Derivative [Line Items]
Contract Volume (mmbtu and mwh) | MMBTU	16,455,000	13,735,405
Options | Electricity
Derivative [Line Items]
Contract Volume (mmbtu and mwh)	912,033	0
Congestion Revenue Rights | Electricity
Derivative [Line Items]
Contract Volume (mmbtu and mwh)	329,571,344	340,783,089

XML

FAIR VALUE MEASUREMENTS (Assets and Liabilities Measured at Fair Value on a Recurring Basis) (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Assets:
Short-term investments	$ 3,402	$ 1,593
Price risk management instruments, netting	44	88
Price risk management instruments, assets	252	297
TOTAL ASSETS	7,477	5,350
Liabilities:
Price risk management instruments, netting	(7)	(10)
TOTAL LIABILITIES	85	109
Amount primarily related to deferred taxes on appreciation of investment value	491	408
Nuclear decommissioning trusts
Assets:
Short-term investments	16	29
Global equity securities	1,959	1,793
Fixed-income securities	1,513	1,300
TOTAL ASSETS	3,507	3,138
Rabbi trusts
Assets:
Fixed-income securities	98	93
Life insurance contracts	71	67
TOTAL ASSETS	169	160
Long-term disability trust
Assets:
Short-term investments	5	7
TOTAL ASSETS	147	162
Price Risk Derivative, Electricity
Assets:
Price risk management instruments, netting	20	51
Price risk management instruments, assets	225	259
Liabilities:
Price risk management instruments, netting	(4)	(10)
Price risk management instruments, liabilities	83	107
Price Risk Derivative, Gas
Assets:
Price risk management instruments, netting	24	37
Price risk management instruments, assets	27	38
Liabilities:
Price risk management instruments, netting	(3)	0
Price risk management instruments, liabilities	2	2
Level 1
Assets:
Short-term investments	3,402	1,593
Price risk management instruments, gross subject to netting	0	0
TOTAL ASSETS	6,197	4,083
Liabilities:
TOTAL LIABILITIES	2	4
Level 1 | Nuclear decommissioning trusts
Assets:
Short-term investments	16	29
Global equity securities	1,959	1,793
Fixed-income securities	815	661
TOTAL ASSETS	2,790	2,483
Level 1 | Rabbi trusts
Assets:
Fixed-income securities	0	0
Life insurance contracts	0	0
TOTAL ASSETS	0	0
Level 1 | Long-term disability trust
Assets:
Short-term investments	5	7
TOTAL ASSETS	5	7
Level 1 | Price Risk Derivative, Electricity
Assets:
Price risk management instruments, gross subject to netting	0	0
Liabilities:
Price risk management instruments, gross subject to netting	0	4
Level 1 | Price Risk Derivative, Gas
Assets:
Price risk management instruments, gross subject to netting	0	0
Liabilities:
Price risk management instruments, gross subject to netting	2	0
Level 2
Assets:
Short-term investments	0	0
Price risk management instruments, gross subject to netting	16	6
TOTAL ASSETS	883	805
Liabilities:
TOTAL LIABILITIES	7	7
Level 2 | Nuclear decommissioning trusts
Assets:
Short-term investments	0	0
Global equity securities	0	0
Fixed-income securities	698	639
TOTAL ASSETS	698	639
Level 2 | Rabbi trusts
Assets:
Fixed-income securities	98	93
Life insurance contracts	71	67
TOTAL ASSETS	169	160
Level 2 | Long-term disability trust
Assets:
Short-term investments	0	0
TOTAL ASSETS	0	0
Level 2 | Price Risk Derivative, Electricity
Assets:
Price risk management instruments, gross subject to netting	13	5
Liabilities:
Price risk management instruments, gross subject to netting	4	5
Level 2 | Price Risk Derivative, Gas
Assets:
Price risk management instruments, gross subject to netting	3	1
Liabilities:
Price risk management instruments, gross subject to netting	3	2
Level 3
Assets:
Short-term investments	0	0
Price risk management instruments, gross subject to netting	192	203
TOTAL ASSETS	192	203
Liabilities:
TOTAL LIABILITIES	83	108
Level 3 | Nuclear decommissioning trusts
Assets:
Short-term investments	0	0
Global equity securities	0	0
Fixed-income securities	0	0
TOTAL ASSETS	0	0
Level 3 | Rabbi trusts
Assets:
Fixed-income securities	0	0
Life insurance contracts	0	0
TOTAL ASSETS	0	0
Level 3 | Long-term disability trust
Assets:
Short-term investments	0	0
TOTAL ASSETS	0	0
Level 3 | Price Risk Derivative, Electricity
Assets:
Price risk management instruments, gross subject to netting	192	203
Liabilities:
Price risk management instruments, gross subject to netting	83	108
Level 3 | Price Risk Derivative, Gas
Assets:
Price risk management instruments, gross subject to netting	0	0
Liabilities:
Price risk management instruments, gross subject to netting	0	0
Fair Value Measured at Net Asset Value | Nuclear decommissioning trusts
Assets:
Assets measured at NAV	19	16
Fair Value Measured at Net Asset Value | Long-term disability trust
Assets:
Assets measured at NAV	$ 142	$ 155

XML

DERIVATIVES (Outstanding Derivative Balances) (Details) - Commodity Risk - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	$ 116	$ 90
Derivative Asset, Netting	0	0
Cash Collateral	51	98
Total Derivative Balance, Assets	167	188
Current assets – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	47	44
Derivative Asset, Netting	(4)	(1)
Cash Collateral	48	89
Total Derivative Balance, Assets	91	132
Other noncurrent assets – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Assets	161	165
Derivative Asset, Netting	0	0
Cash Collateral	0	0
Total Derivative Balance, Assets	161	165
Current liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Liabilities	(25)	(29)
Derivative Liability, Netting	4	1
Cash Collateral	3	7
Total Derivative Balance, Liabilities	(18)	(21)
Noncurrent liabilities – other
Derivatives And Hedging Activities [Line Items]
Gross Derivative Liabilities	(67)	(90)
Derivative Liability, Netting	0	0
Cash Collateral	0	2
Total Derivative Balance, Liabilities	$ (67)	$ (88)

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FAIR VALUE MEASUREMENTS (Level 3 Measurements and Sensitivity Analysis) (Details) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2019 USD ($) $ / MWh	Dec. 31, 2018 USD ($) $ / MWh
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	$ 7,477	$ 5,350
Liabilities	$ 85	$ 109
Congestion revenue rights | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unobservable input (dollars per mwh) | $ / MWh	(13.11)	(18.61)
Congestion revenue rights | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unobservable input (dollars per mwh) | $ / MWh	22.76	32.26
Power purchase agreements | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unobservable input (dollars per mwh) | $ / MWh	19.68	19.81
Power purchase agreements | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unobservable input (dollars per mwh) | $ / MWh	38.80	38.80
Market approach | Congestion revenue rights
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	$ 191	$ 203
Liabilities	64	75
Discounted cash flow | Power purchase agreements
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	1	0
Liabilities	$ 19	$ 33

XML

FAIR VALUE MEASUREMENTS (Level 3 Reconciliation) (Details) - Level 3 - Price Risk Management Instruments - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning asset (liability) balance	$ 129	$ 40	$ 95	$ 42
Net realized and unrealized gains: Included in regulatory assets and liabilities or balancing accounts	(20)	(6)	14	(8)
Ending asset (liability) balance	$ 109	$ 34	$ 109	$ 34

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FAIR VALUE MEASUREMENTS (Carrying Amount and Fair Value of Financial Instruments) (Details) - USD ($) $ in Millions		6 Months Ended
	Feb. 01, 2019	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Proceeds from debtor-in-possession credit facility	$ 350	$ 1,850	$ 0
Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument		0		$ 350
Utility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument		3,215		3,215
Proceeds from debtor-in-possession credit facility		1,850	$ 0
Utility | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument		1,500		14,747
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument		0		350
Carrying Amount | Utility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt financial instrument		$ 1,500		$ 17,450

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FAIR VALUE MEASUREMENTS (Schedule of Unrealized Gains (Losses) Related to Available-for-Sale Investments) (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	$ 1,943	$ 1,885
Total Unrealized Gains	1,570	1,276
Total Unrealized Losses	(6)	(23)
Total Fair Value	3,507	3,138
Amount primarily related to deferred taxes on appreciation of investment value	491	408
Short-term investments
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	16	29
Total Unrealized Gains	0	0
Total Unrealized Losses	0	0
Total Fair Value	16	29
Global equity securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	496	568
Total Unrealized Gains	1,486	1,246
Total Unrealized Losses	(4)	(5)
Total Fair Value	1,978	1,809
Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Amortized Cost	1,431	1,288
Total Unrealized Gains	84	30
Total Unrealized Losses	(2)	(18)
Total Fair Value	$ 1,513	$ 1,300

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FAIR VALUE MEASUREMENTS (Schedule of Maturities on Debt Securities) (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Debt Securities, Available-for-sale [Line Items]
Total maturities of fixed-income securities	$ 3,507	$ 3,138
Fixed-income securities
Debt Securities, Available-for-sale [Line Items]
Less than 1 year	26
1–5 years	541
5–10 years	340
More than 10 years	606
Total maturities of fixed-income securities	$ 1,513	$ 1,300

XML

FAIR VALUE MEASUREMENTS (Schedule of Activity for Debt and Equity Securities) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Fair Value Disclosures [Abstract]
Proceeds from sales and maturities of nuclear decommissioning trust investments	$ 171	$ 308	$ 517	$ 802
Gross realized gains on securities	56	11	22	48
Gross realized losses on securities	$ (26)	$ (5)	$ (7)	$ (9)

XML

WILDFIRE-RELATED CONTINGENCIES (Summary of Estimated Liabilities) (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Loss Contingencies [Line Items]
Wildfire-related claims reclassified to current liabilities	$ 100	$ 14,226
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Total wildfire-related claims	18,112	14,226
Wildfire-related claims reclassified from liabilities subject to compromise	100
Wildfire-related claims reclassified to current liabilities	100	14,226
Pacific Gas & Electric Co | 2015 Butte fire
Loss Contingencies [Line Items]
Total wildfire-related claims	212	226
Pacific Gas & Electric Co | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Total wildfire-related claims	5,500	3,500
Pacific Gas & Electric Co | 2018 Camp fire
Loss Contingencies [Line Items]
Total wildfire-related claims	$ 12,400	$ 10,500

XML

WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Claims Narrative) (Details) - Pacific Gas & Electric Co - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
2018 Camp fire
Loss Contingencies [Line Items]
Legal and other costs	$ 19		$ 32
2017 Northern California wildfires
Loss Contingencies [Line Items]
Legal and other costs	$ 7	$ 46	$ 41	$ 68

XML

WILDFIRE-RELATED CONTINGENCIES (2018 Camp Fire Background) (Details) - Pacific Gas & Electric Co - 2018 Camp fire	Jan. 04, 2019 a residence fatality structure
Loss Contingencies [Line Items]
Number of acres burned (acre) | a	153,336
Number of fatalities (fatality)	85
Number of residences destroyed (residence) | residence	13,972
Number of commercial structures destroyed (structure) | structure	528
Number of other buildings destroyed (building)	4,293

XML

WILDFIRE-RELATED CONTINGENCIES (2017 Northern California Wildfires Background) (Details) - Pacific Gas & Electric Co a in Thousands	Jun. 30, 2019 wildfire report	Jun. 27, 2019 wildfire violation	Jan. 04, 2019 wildfire	Jun. 30, 2018 wildfire	Oct. 30, 2017 a wildfire fatality structure
2017 Northern California wildfires
Loss Contingencies [Line Items]
Number of wildfires (wildfire) | wildfire			18		21
Number of acres burned (acre) | a					245
Number of structures destroyed (structure) | structure					8,900
Number of fatalities (fatality) | fatality					44
Number of investigation reports issued (report) | report	19
Number of supplementary investigation reports issued (report) | report	2
Number of fires in which determination has been reported on (wildfire) | wildfire	21			16
Number of alleged violations (violation) | violation		27
Alleged violations, number of wildfires (wildfire) | wildfire		12
Cherokee, La Porte and Tubbs Fires
Loss Contingencies [Line Items]
Number of alleged violations (violation) | violation		0
37 Fire
Loss Contingencies [Line Items]
Number of alleged violations (violation) | violation		0

XML

WILDFIRE-RELATED CONTINGENCIES (Third-Party Claims, Investigations and Other Proceedings Related to the 2018 Camp Fire and 2017 Northern California Wildfires) (Details) - Pending Litigation	Jan. 28, 2019 wildfire complaint plaintiff
Complaints Against PG&E Corporation and the Utility in Sacramento County Superior Court | 2018 Camp fire
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint)	100
Number of plaintiffs in lawsuit (at least) (plaintiff) | plaintiff	4,200
Complaints Against PG&E Corporation and the Utility in Sacramento County Superior Court, Classified as Class Action | 2018 Camp fire
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint) | wildfire	9
Complaints Against PG&E Corporation and the Utility in San Francisco Counties Superior Courts | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint)	750
Number of plaintiffs in lawsuit (at least) (plaintiff) | plaintiff	3,800
Lawsuits Against PG&E Corporation and the Utility in the Sonoma, Napa and San Francisco Counties Superior Courts, Classified As Class Actions | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint) | wildfire	5
Subrogation Complaints Against PG&E Corporation and the Utility in San Francisco County Superior Courts | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint)	52
Subrogation Complaints Against PG&E Corporation and the Utility in Sacramento County Superior Court | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint)	39

XML

WILDFIRE-RELATED CONTINGENCIES (Plan Support Agreements with Public Entities) (Details) - Settled Litigation	Jun. 18, 2019 USD ($)
Public Entity Wildfire Claims
Loss Contingencies [Line Items]
Settlement reached	$ 1,000,000,000.0
Fund to support defense or resolution of claims for each PSA	10,000,000.0
2017 Northern California Wildfire Public Entities Claims
Loss Contingencies [Line Items]
Settlement reached	415,000,000.0
Town Of Paradise Wildfire Claims
Loss Contingencies [Line Items]
Settlement reached	270,000,000.0
County Of Butte Wildfire Claims
Loss Contingencies [Line Items]
Settlement reached	252,000,000.0
Paradise Recreation & Park District Wildfire Claims
Loss Contingencies [Line Items]
Settlement reached	47,500,000
County Of Yuba Wildfire Claims
Loss Contingencies [Line Items]
Settlement reached	12,500,000
Calaveras County Water District Wildfire Claims
Loss Contingencies [Line Items]
Settlement reached	$ 3,000,000.0

XML

WILDFIRE-RELATED CONTINGENCIES (Potential Losses in Connection with the 2018 Camp Fire and 2017 Northern California Wildfires) (Details) insurance_claim in Thousands, $ in Millions			3 Months Ended	6 Months Ended	12 Months Ended
	May 08, 2019 USD ($)	Sep. 06, 2018 USD ($) insurance_claim	Jun. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2015 USD ($)
November 2018 Fires
Loss Contingencies [Line Items]
Total insurance claims received by insurers	$ 12,000
2018 Camp fire
Loss Contingencies [Line Items]
Total insurance claims received by insurers	8,600
Loss in period			$ 1,900	$ 12,400	$ 10,500
2017 Northern California wildfires
Loss Contingencies [Line Items]
Total insurance claims received by insurers		$ 12,280
Insurance claims received by insurers (insurance claim) | insurance_claim		55
Statewide insurance claims related to wildfire		$ 10,000
2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Total insurance claims received by insurers	$ 18,600
Estimate of possible losses			$ 30,000	$ 30,000
Pacific Gas & Electric Co | San Bruno Natural Gas Explosion
Loss Contingencies [Line Items]
Loss in period						$ 1,600
Loss contingency liability						$ 558

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WILDFIRE-RELATED CONTINGENCIES (2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge) (Details) $ in Millions		3 Months Ended			6 Months Ended	12 Months Ended
	Jul. 23, 2019 USD ($)	Jun. 30, 2019 USD ($) wildfire	Dec. 31, 2018 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2019 USD ($) wildfire	Dec. 31, 2018 USD ($)
2018 Camp fire
Loss Contingencies [Line Items]
Accrued losses		$ 1,900			$ 12,400	$ 10,500
2017 Northern California wildfires
Loss Contingencies [Line Items]
Number of fires with probable losses (wildfire) | wildfire		21			21
Loss from claims related to wildfire		$ 2,000	$ 1,000	$ 2,500	$ 5,500	$ 3,500
2017 Northern California Wildfires, other than Tubbs and 37 Fires
Loss Contingencies [Line Items]
Number of fires with probable losses (wildfire) | wildfire		19			19
Number of fires with probable losses, as previously determined (wildfire) | wildfire		17			17
2017 Northern California Wildfires, Youngs and Pressley Fires
Loss Contingencies [Line Items]
Number of fires with probable losses (wildfire) | wildfire		2			2
2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Loss from claims related to wildfire					$ 17,900
2018 Camp Fire and 2017 Northern California Wildfires, Clean-up and Fire Suppression Costs
Loss Contingencies [Line Items]
Loss from claims related to wildfire					900
Subrogated Insurance Claimholders | 2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Loss from claims related to wildfire					8,500
Individual Claimholders | 2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Loss from claims related to wildfire					7,500
Supporting Public Entities | 2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Loss from claims related to wildfire					$ 1,000
Subsequent Event | Subrogated Insurance Claimholders | 2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Insurance claims (in excess of)	$ 20,000
Plan of reorganization, settlement value of insurance claims	$ 15,800

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WILDFIRE-RELATED CONTINGENCIES (Loss Recoveries) (Details) - USD ($) $ in Millions	Jul. 08, 2019	Jun. 30, 2019	Sep. 30, 2018	Jul. 31, 2018
2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Liability insurance coverage			$ 1,400	$ 842
Initial self-insured retention per occurrence			10	10
Further retention per occurrence				$ 40
Liability insurance coverage, general liability			700
Liability insurance coverage, property damages			700
Liability insurance coverage, property damages, reinsurance			$ 200
2018 Camp fire
Loss Contingencies [Line Items]
Estimated insurance recoveries		$ 1,380
2017 Northern California wildfires
Loss Contingencies [Line Items]
Estimated insurance recoveries		$ 842
Subsequent Event | 2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Customer Harm Threshold, potential regulatory adjustment, percentage	20.00%
Customer Harm Threshold, potential regulatory adjustment, percentage of total disallowed wildlife liability	5.00%

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WILDFIRE-RELATED CONTINGENCIES (Summary of Insurance Receivables) (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Insurance Receivable [Roll Forward]
Reimbursements	$ 35	$ (144)
2018 Camp fire
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance	1,380
Accrued insurance recoveries	0
Reimbursements	0
Insurance Receivable, Ending Balance	1,380
2017 Northern California wildfires
Insurance Receivable [Roll Forward]
Insurance Receivable, Beginning Balance	829
Accrued insurance recoveries	0
Reimbursements	0
Insurance Receivable, Ending Balance	$ 829

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WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Derivative Litigation) (Details)	Nov. 20, 2017 lawsuit
Derivative Lawsuits Filed in the San Francisco County Superior Court | Breach of Fiduciary Duties
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint)	2

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WILDFIRE-RELATED CONTINGENCIES (Wildfire-Related Securities Class Action Litigation) (Details) - Securities Class Actions Filed in United States District Court for the Northern District of California	Feb. 22, 2019 offering	Jun. 30, 2018 lawsuit
Loss Contingencies [Line Items]
Number of lawsuits filed against company (lawsuit, complaint) | lawsuit		2
Number of public offerings of notes with complaints against underwriters (offering) | offering	4

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WILDFIRE-RELATED CONTINGENCIES (District Attorneys Offices Investigations) (Details) - Pacific Gas & Electric Co - Complaints Brought By Butte County District Attorney - Loss from Wildfires $ in Millions	1 Months Ended
	Oct. 31, 2018 USD ($)
Loss Contingencies [Line Items]
Settlement agreement term	4 years
Settlement expense	$ 1.5

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WILDFIRE-RELATED CONTINGENCIES (Clean-up and Repair Costs) (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Loss Contingencies [Line Items]
Capital expenditures	$ 836	$ 317
Total long-term regulatory assets	5,349		$ 4,964
Catastrophic event memorandum account
Loss Contingencies [Line Items]
Total long-term regulatory assets	918		790
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Capital expenditures	836	$ 317
Total long-term regulatory assets	5,349		$ 4,964
Pacific Gas & Electric Co | 2018 Camp fire
Loss Contingencies [Line Items]
Service restoration and repair costs	655
Capital expenditures	236
Pacific Gas & Electric Co | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Service restoration and repair costs	334
Capital expenditures	161
Pacific Gas & Electric Co | Catastrophic event memorandum account | 2018 Camp fire
Loss Contingencies [Line Items]
Total long-term regulatory assets	0
Pacific Gas & Electric Co | Catastrophic event memorandum account | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Total long-term regulatory assets	$ 88

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WILDFIRE-RELATED CONTINGENCIES (Wildfire Assistance Fund) (Details) - USD ($) $ in Millions	Aug. 02, 2019	Jun. 30, 2019	May 24, 2019	Dec. 31, 2018
Loss Contingencies [Line Items]
Wildfire-related claims		$ 100		$ 14,226
2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Wildfire Assistance Fund, amount sought			$ 105
Wildfire Assistance Fund, amount sought, portion available for administrative expenses			$ 5
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Wildfire-related claims		$ 100		$ 14,226
Subsequent Event | 2018 Camp Fire and 2017 Northern California Wildfires
Loss Contingencies [Line Items]
Wildfire-related claims	$ 105

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WILDFIRE-RELATED CONTINGENCIES (2015 Butte Fire) (Details) household in Thousands, $ in Millions						1 Months Ended			2 Months Ended	6 Months Ended
	Jan. 28, 2019 contractor household plaintiff	Sep. 06, 2018 plaintiff	Mar. 02, 2018 USD ($)	Mar. 01, 2018 USD ($)	Apr. 13, 2017 USD ($)	Jan. 29, 2019 USD ($)	Nov. 30, 2018 USD ($)	May 31, 2017 USD ($)	Sep. 30, 2018 plaintiff	Jun. 30, 2019 USD ($)	Jun. 30, 2018 USD ($)	Dec. 31, 2018 USD ($)	May 01, 2018 decision	May 23, 2016 contractor	Apr. 28, 2016 a outbuilding fatality home comercial_property structure
Loss Contingencies [Line Items]
Wildfire-related insurance receivable										$ 35.0	$ (144.0)
2015 Butte fire
Loss Contingencies [Line Items]
Loss contingency liability										212.0		$ 226.0
Payments for claims						$ (14.0)
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Wildfire-related insurance receivable										35.0	$ (144.0)
Pacific Gas & Electric Co | 2015 Butte fire
Loss Contingencies [Line Items]
Number of acres burned (acre) | a															70,868
Number of fatalities caused by fire (fatality) | fatality															2
Number of homes destroyed by fire (home) | home															549
Number of outbuildings damaged by fire (outbuilding) | outbuilding															368
Number of commercial properties damaged by fire (commercial property) | comercial_property															4
Number of structures damaged (structure) | structure															44
Number of vegetation management contractors (contractor) | contractor														2
Number of complaints filed (complaint) | contractor	95
Number of plaintiffs (plaintiff) | plaintiff	3,900
Number of households represented in court (household) | household	2
Number of vegetation management contractors dismissed from complaints (contractor) | contractor	2
Number of plaintiffs, smaller public entities (plaintiff) | plaintiff									4
Number of plaintiffs, fire districts (plaintiff) | plaintiff									3
Fire fighting costs recovery requested					$ 87.0
Value of claims brought against the company								$ 190.0
Reasonably possible loss to be incurred										1,100.0
Coverage for third party liability										922.0
Probable insurance recoveries										922.0
Cumulative reimbursements from insurance policies										60.0
Loss contingency liability										212.0		226.0
Payments for claims						$ (14.0)
Settlement agreement paid										888.0
Settlement agreements entered										904.0
Insurance settlements receivable										50.0		$ 85.0
Wildfire-related insurance receivable										$ (35.0)
Agreement Reached in Litigation to Stipulate to Judgment on Inverse Condemnation Grounds | Pacific Gas & Electric Co | 2015 Butte fire
Loss Contingencies [Line Items]
Number of previous appellate courts decisions (decision) | decision													2
Number of plaintiffs in lawsuit (plaintiff) | plaintiff		2
County of Calaveras | Pacific Gas & Electric Co | 2015 Butte fire
Loss Contingencies [Line Items]
Value of claims brought against company			$ 167.0	$ 85.0
Settlement reached							$ 25.4
Settled Litigation | Pacific Gas & Electric Co | 2015 Butte fire
Loss Contingencies [Line Items]
Number of plaintiffs, fire districts (plaintiff) | plaintiff									3

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OTHER CONTINGENCIES AND COMMITMENTS (Enforcement and Litigation Matters) (Details) - Pacific Gas & Electric Co $ in Millions	Apr. 16, 2019	Jan. 31, 2017 USD ($)	May 14, 2019 condition	Jan. 04, 2019 wildfire	Oct. 30, 2017 wildfire	Aug. 09, 2016 count
2017 Northern California wildfires
Loss Contingencies [Line Items]
Number of wildfires (wildfire) | wildfire				18	21
Judicial Ruling | Unfavorable Regulatory Action
Loss Contingencies [Line Items]
Number of guilty counts of obstructing a federal agency proceeding						1
Number of guilty counts of violating pipeline integrity management regulations						5
Corporate probation period, term	5 years	5 years
Oversight by third-party monitor period, application for early termination, term		3 years
Damages awarded, value | $		$ 3
Number of additional probation conditions (condition) | condition			2

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OTHER CONTINGENCIES AND COMMITMENTS (CPUC and FERC Matters) (Details) $ in Thousands	Jun. 30, 2019 USD ($)	Jun. 27, 2019 wildfire violation	Sep. 21, 2018	May 17, 2018 USD ($)	Apr. 26, 2018 USD ($)	Jun. 28, 2019 USD ($)	Dec. 06, 2018 consultant
Ex Parte Communications
Loss Contingencies [Line Items]
Proposed penalty					$ 97,500
Payment to State General Fund				$ 12,000	12,000
Gas transmission and storage revenue reduction					63,500
2018 GT&S revenue requirement reduction					31,750
2019 GT&S revenue requirement reduction					31,750
Revenue requirement reduction in next GRC cycle					10,000
Payment to city of San Bruno				6,000	6,000
Payment to city of San Carlos				$ 6,000	$ 6,000
Settlement agreement, proposed penalty						$ 10,000
Settlement agreement, proposed payment to California General Fund						2,000
Settlement agreement, proposed forgone revenue collection, 2019 GT&S rate case						5,000
Settlement agreement, proposed forgone revenue collection, 2020 GRC cycle						1,000
Settlement agreement, proposed compensation payments						2,000
Settlement agreement, proposed compensation payments, San Bruno						1,000
Settlement agreement, proposed compensation payments, San Carlos						$ 1,000
Loss contingency liability	$ 4,000
Disallowance of Plant Costs
Loss Contingencies [Line Items]
Accrual for GTandS revenue requirement reduction	16,000
Pacific Gas & Electric Co | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Number of alleged violations (violation) | violation		27
Alleged violations, number of wildfires (wildfire) | wildfire		12
Qualifications of vegetation management personnel, corrective actions, period		30 days
Pacific Gas & Electric Co | Cherokee, La Porte and Tubbs Fires
Loss Contingencies [Line Items]
Number of alleged violations (violation) | violation		0
Pacific Gas & Electric Co | 37 Fire
Loss Contingencies [Line Items]
Number of alleged violations (violation) | violation		0
Pacific Gas & Electric Co | Ex Parte Communications
Loss Contingencies [Line Items]
Loss contingency liability	$ 4,000
Pacific Gas & Electric Co | Pending Litigation | Unfavorable Regulatory Action
Loss Contingencies [Line Items]
Number of consultants retained | consultant							2
Electric | Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Requested revenue rate			98.85%
Minimum | Pacific Gas & Electric Co | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Prehearing conference, period after initiation of proceedings		45 days
Maximum | Pacific Gas & Electric Co | 2017 Northern California wildfires
Loss Contingencies [Line Items]
Prehearing conference, period after initiation of proceedings		60 days

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OTHER CONTINGENCIES AND COMMITMENTS (Other Matters) (Details) - USD ($) $ in Millions	Jun. 23, 2016	Dec. 31, 2018
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Accrued legal liabilities		$ 98
Disallowance of Plant Costs
Loss Contingencies [Line Items]
Gas transmission and storage capital disallowance	$ 696
Permanently disallowed capital	120
Amount subject to audit	$ 576

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OTHER CONTINGENCIES AND COMMITMENTS (Schedule of Environmental Remediation Liability Composed) (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Disclosure Commitments And Contingencies Environmental Remediation Liability Composed [Abstract]
Topock natural gas compressor station	$ 346	$ 369
Hinkley natural gas compressor station	142	146
Former manufactured gas plant sites owned by the Utility or third parties	580	520
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites	112	111
Fossil fuel-fired generation facilities and sites	125	137
Total environmental remediation liability	$ 1,305	$ 1,283

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OTHER CONTINGENCIES AND COMMITMENTS (Environmental Remediation Contingencies Narrative) (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Long-term Purchase Commitment [Line Items]
Amount of environmental loss accrual expected to be recovered	$ 960
Pacific Gas & Electric Co
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	18,112	$ 14,226
Topock Site
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 302
Topock Site | Pacific Gas & Electric Co
Long-term Purchase Commitment [Line Items]
Remediation cost recovery percentage	90.00%
Hinkley Natural Gas Compressor Station
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 139
Former Manufactured Gas Plant
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 528
Remediation cost recovery percentage	90.00%
Utility Owned Generation Facilities and Third Party Disposal Sites
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 98
Utility Owned Generation Facilities and Third Party Disposal Sites | Pacific Gas & Electric Co
Long-term Purchase Commitment [Line Items]
Remediation cost recovery percentage	90.00%
Fossil Fuel Fired Generation
Long-term Purchase Commitment [Line Items]
Utility undiscounted future costs	$ 86

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OTHER CONTINGENCIES AND COMMITMENTS (Wildfire Insurance) (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jul. 01, 2019	Dec. 31, 2018
Loss Contingencies [Line Items]
Costs for insurance coverage	$ 190
Pacific Gas & Electric Co
Loss Contingencies [Line Items]
Costs for insurance coverage	50
Insurance Coverage for Wildfire Events
Loss Contingencies [Line Items]
Liability insurance coverage			$ 1,400
Insurance Coverage for Wildfire Liabilities
Loss Contingencies [Line Items]
Liability insurance coverage			700
Catastrophic bond reinsurance instrument			10
Insurance Coverage for Property Damages
Loss Contingencies [Line Items]
Liability insurance coverage			700
Catastrophic bond reinsurance instrument			$ 200
2018 Camp fire
Loss Contingencies [Line Items]
Estimated insurance recoveries	1,380
2017 Northern California wildfires
Loss Contingencies [Line Items]
Estimated insurance recoveries	$ 842
Subsequent Event | Insurance Coverage for Wildfire Events
Loss Contingencies [Line Items]
Liability insurance coverage		$ 430
Subsequent Event | Insurance Coverage for Wildfire Liabilities
Loss Contingencies [Line Items]
Liability insurance coverage		520
Catastrophic bond reinsurance instrument		$ 10

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OTHER CONTINGENCIES AND COMMITMENTS (Nuclear Insurance) (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($) nuclear_generating_unit
Long-term Purchase Commitment [Line Items]
Number of nuclear generating units (nuclear generating unit) | nuclear_generating_unit	2
Nuclear Electric Insurance Limited
Long-term Purchase Commitment [Line Items]
Amount of property damage and business interruption coverage provided by NEIL for Diablo Canyon	$ 41
European Mutual Association for Nuclear Insurance
Long-term Purchase Commitment [Line Items]
Amount of property damage coverage provided by NEIL	$ 5

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OTHER CONTINGENCIES AND COMMITMENTS (Tax Matters) (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($)
Pacific Gas & Electric Co
Disaggregation of Revenue [Line Items]
Unrecognized tax benefits, decrease resulting from settlements with taxing authorities	$ 10

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OTHER CONTINGENCIES AND COMMITMENTS (Purchase Commitments) (Details) $ in Billions	Dec. 31, 2018 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Recorded unconditional purchase obligation	$ 40

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SUBSEQUENT EVENTS (Details) - Unfavorable Regulatory Action - Pacific Gas & Electric Co - Subsequent Event $ in Millions	Jul. 12, 2019 USD ($)
Subsequent Event [Line Items]
Disallowance cap, transmission and distribution equity rate base	$ 2,300
Expected wildfire fund allocation metric, percentage	64.20%
Expected wildfire fund allocation metric, initial contribution	$ 4,800
Expected wildfire fund allocation metric, annual contributions	$ 193