pcg-20200930

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C., 20549

FORM

10-Q

(Mark One)

☒

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

For the quarterly period ended

September 30, 2020

☐

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

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
Equity Units	PCGU	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

☐

Pacific Gas and Electric Company:

☒

Yes

☐

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

☐

Pacific Gas and Electric Company:

☒

Yes

☐

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

☒

Pacific Gas and Electric Company:

☐

Yes

☒

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

PG&E Corporation:

☒

Yes

☐

Pacific Gas and Electric Company:

☒

Yes

☐

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Common stock outstanding as of October 26, 2020:

PG&E Corporation:

1,984,565,829

Pacific Gas and Electric Company:

264,374,809

PG&E CORPORATION AND

PACIFIC GAS AND ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2020

TABLE OF CONTENTS


GLOSSARY
FORWARD-LOOKING STATEMENTS
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 SHAREHOLDERS ’ 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
			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
			CRITICAL ACCOUNTING POLICIES
			ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED
			ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
			ITEM 4. CONTROLS AND PROCEDURES
PART II. OTHER INFORMATION
			ITEM 1. LEGAL PROCEEDINGS
			ITEM 1A. RISK FACTORS
			ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
			ITEM 5. OTHER INFORMATION
			ITEM 6. EXHIBITS
			SIGNATURES

GLOSSARY

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


2019 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, 2019
2019 Wildfire Mitigation Plan			the wildfire mitigation plan for 2019 submitted by the Utility to the CPUC pursuant to SB 901, previously also referred to as the “2019 Wildfire Safety Plan”
AB			Assembly Bill
ABR			alternate base rate
ALJ			administrative law judge
ARO			asset retirement obligation
ASU			accounting standard update issued by the FASB (see below)
Backstop Party			a third-party investor party to a Backstop Commitment Letter
Bankruptcy Code			the United States Bankruptcy Code
Bankruptcy Court			the U.S. Bankruptcy Court for the Northern District of California
CAISO			California Independent System Operator
Cal Fire			California Department of Forestry and Fire Protection
CARB			California Air Resources Board
CARE			California Alternate Rates for Energy
CCA			Community Choice Aggregator
CEMA			Catastrophic Event Memorandum Account
CEP			Community Engagement Plan
Chapter 11			chapter 11 of title 11 of the U.S. Code
Chapter 11 Cases			the voluntary cases commenced by each of PG&E Corporation and the Utility under Chapter 11 on January 29, 2019
CHT			Customer Harm Threshold
CPUC			California Public Utilities Commission
CPPMA			COVID-19 Pandemic Protections Memorandum Account
CRRs			congestion revenue rights
CUE			Coalition of California Utility Employees
CVA			Climate Vulnerability Assessment
DA			Direct Access
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
DTSC			Department of Toxic Substances Control
EPS			earnings per common share
Effective Date			July 1, 2020, the effective date of the Plan in the Chapter 11 Cases
FASB			Financial Accounting Standards Board
FEMA			Federal Emergency Management Agency
FERC			Federal Energy Regulatory Commission
FHPMA			Fire Hazard Prevention Memorandum Account
Formula Rate Proceedings			consolidated proceedings for the TO18 and TO20 rate cases
FRMMA			Fire Risk Mitigation Memorandum Account
Fire Victim Trust			trust established pursuant to the Plan for the benefit of holders of the Fire Victim Claims into which the Aggregate Fire Victim Consideration (as defined in the Plan) has been, and will continue to be funded
GAAP			U.S. Generally Accepted Accounting Principles


GRC			general rate case
GT&S			gas transmission and storage
HSM			Hazardous Substance Memorandum Account
IOU(s)			investor-owned utility(ies)
LIBOR			London Interbank Offered Rate
LSTC			liabilities subject to compromise
MD&A			Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Item 2 of this Form 10-Q
MGP(s)			manufactured gas plants
the Monitor			third-party monitor retained as part of its compliance with the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction
NAV			net asset value
NBC			non-bypassable charge
NDCTP			Nuclear Decommissioning Cost Triennial Proceedings
NEIL			Nuclear Electric Insurance Limited
NRC			Nuclear Regulatory Commission
OII			order instituting investigation
OIR			order instituting rulemaking
PCIA			Power Charge Indifference Adjustment
PERA			Public Employees Retirement Association of New Mexico
POD			Presiding Officer’s Decision
PD			proposed decision
Petition Date			January 29, 2019
the Plan			Debtors’ and Shareholder Proponents’ Joint Chapter 11 Plan of Reorganization, dated June 19, 2020
PSA			plan support agreement
PSPS			Public Safety Power Shutoff
RA			resource adequacy
RAMP			Risk Assessment Mitigation Phase Report
ROE			return on equity
RSA			restructuring support agreement (as amended)
SB			Senate Bill
SEC			U.S. Securities and Exchange Commission
Securities Act			The Securities Act of 1933, as amended
SED			Safety and Enforcement Division of the CPUC
SPV			Special purpose vehicle
Tax Act			Tax Cuts and Jobs Act of 2017
TCC			Official Committee of Tort Claimants
TO			transmission owner
TURN			The Utility Reform Network
Utility			Pacific Gas and Electric Company
VIE(s)			variable interest entity(ies)
WEMA			Wildfire Expense Memorandum Account
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
Wildfires OII			Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire


WMCE			Wildfire Mitigation and Catastrophic Events
WMP			Wildfire Mitigation Plan
WMPMA			Wildfire Mitigation Plan Memorandum Account

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 capital expenditures; estimates and assumptions used in critical accounting policies, including those relating to liabilities subject to compromise, insurance receivable, regulatory assets and liabilities, environmental remediation, litigation, third-party claims, the Wildfire Fund, 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:

•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 and the financial and other restructuring recently undergone by PG&E Corporation and the Utility in connection with emergence from Chapter 11;

•the ability of PG&E Corporation and the Utility to raise financing for operations and investment;

•the risks and uncertainties associated with appeals to the Confirmation Order (as defined in Note 2 of the Notes to the Condensed Consolidated Financial Statements in Item 1);

•the risks and uncertainties associated with the 2019 Kincade fire, including the extent of the Utility’s liability in connection with the Kincade fire and whether the Utility will be able to timely recover related costs incurred therewith in excess of insurance; the timing of the insurance recoveries; the timing and outcome of the referral of the Cal Fire report in connection therewith to the Sonoma County District Attorney; and potential liabilities in connection with fines or penalties that could be imposed on the Utility if the CPUC or any other enforcement agency were to bring an enforcement action;

•the risks and uncertainties associated with any other wildfires, including the 2020 Zogg fire, that have occurred and/or may occur in the Utility’s service territory for which the cause has yet to be determined;

•the outcome of the Utility’s Community Wildfire Safety Program 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 its Wildfire Mitigation Plans; whether the Utility is able to retain or contract for the workforce necessary to execute its Community Wildfire Safety Program; and the cost of the program and the timing and outcome of any proceeding to recover such cost through rates;

•the ability of PG&E Corporation and the Utility to securitize $7.5 billion of costs related to the 2017 Northern California wildfires in a financing transaction that is designed to be rate neutral to customers;

•the impact of the Utility’s implementation of its PSPS program, including the timing and outcome of the OII to Examine the Late 2019 Public Safety Power Shutoff Events, and whether any fines or penalties or civil liability for damages will be imposed on the Utility as a result; the costs in connection with PSPS events, the timing and outcome of any proceeding to recover such cost through rates, and the effects on PG&E Corporation’s and the Utility’s reputations caused by implementation of the PSPS program;

•whether the Utility may be liable for future wildfires, and the impact of AB 1054 on potential losses in connection with such wildfires, including the CPUC’s implementation of the procedures for recovering such losses;

•the risks and uncertainties associated with the requirement under AB 1054 that the Utility maintain a valid safety certification pursuant to Section 8389(e) of the California Public Utilities Code and the potential unavailability of the Wildfire Fund in the event the Utility fails to maintain a valid safety certification;

•the timing and outcome of future regulatory and legislative developments, including future wildfire reforms, inverse condemnation reform, and other wildfire mitigation measures or other reforms targeted at the Utility or its industry;

•the severity, extent and duration of the global COVID-19 pandemic and its impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows, as well as on energy demand in the Utility’s service territory, the ability of the Utility to collect on customer invoices, the ability of the Utility to mitigate these effects, including with spending reductions, and the ability of the Utility to recover any losses incurred in connection with the COVID-19 pandemic, and the impact of workforce disruptions;

•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 challenging political and operating environment facing PG&E Corporation and the Utility;

•changes related to PG&E Corporation’s and the Utility’s pension and other post-retirement benefit plan obligations;

•the timing and outcomes of the 2020 GRC, FERC TO18, TO19, and TO20 rate cases, 2018 and 2019 CEMA applications, WEMA application, WMCE application, future applications for FRMMA, CPPMA, and WMPMA, future cost of capital proceedings, 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, or Western Electricity Coordinating Council, investigations that have been or may be commenced relating to the Utility’s compliance with natural gas- and electric- related laws and regulations, and the ultimate amount of fines, penalties, and remedial costs that the Utility may incur in connection with the outcomes including the costs of complying with any additional conditions of probation imposed in connection with the Utility’s federal criminal proceeding, such as expenses associated with any material expansion of the Utility’s vegetation management program, as well as the impact of additional conditions of probation on PG&E Corporation’s and the Utility’s ability to make distributions to shareholders;

•the effects on PG&E Corporation’s and the Utility’s reputations caused by matters such as the CPUC’s investigations and enforcement proceedings and the Utility’s criminal guilty plea as described in Note 10 of the Notes to the Condensed Consolidated Financial Statements under the heading “District Attorneys’ Offices Investigations”;

•the outcome of future legislative or regulatory actions as part of “Enhanced Enforcement” or otherwise that may be taken, such as requiring the Utility to transfer ownership of the Utility’s assets to municipalities or other public entities, or implement corporate governance, operational or other changes;

•whether the Utility can control its operating 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 in the Court of Appeals of the appeal of FERC’s order denying rehearing on March 17, 2020 granting the Utility a 50-basis point ROE incentive adder for continued participation in the CAISO;

•the outcome of current and future self-reports, investigations, or other enforcement proceedings that could be commenced or notices of violation that could be issued relating to the Utility’s compliance with laws, rules, regulations, or orders applicable to its operations, including the construction, expansion, or replacement of its electric and gas facilities, electric grid reliability, inspection and maintenance practices, customer billing and privacy, physical and cybersecurity, environmental laws and regulations; and the outcome of existing and future SED notices of violations;

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

•the impact of SB 100, signed into law on September 10, 2018, which increased 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;

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

•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 and the California governor’s executive order issued on September 23, 2020, requiring sales of all new passenger vehicles to be zero-emission by 2035 and additional measures to eliminate harmful emissions from the transportation sector;

•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, high winds, lightning 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;

•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 outcome of future legislative developments in connection with SB 350 (the Golden State Energy Act), a bill which was signed into law on June 30, 2020 and authorizes the creation by the California governor of a new entity “Golden State Energy,” a nonprofit public benefit corporation, for the purpose of acquiring the Utility’s assets and serving electric and gas in the Utility’s service territory in the event that the CPUC revokes the Utility’s Certificate of Public Convenience and Necessity;

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

•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, and 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 risks and uncertainties associated with any future substantial sales of shares of common stock of PG&E Corporation by existing shareholders, including the Fire Victim Trust, the investors party to the Investment Agreement (as defined in Note 6 of the Notes to the Condensed Consolidated Financial Statements in Item 1) and the Backstop Parties;

•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 Utility’s probation or 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;

•whether PG&E Corporation or the Utility undergoes an “ownership change” within the meaning of Section 382 of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), as a result of which, tax attributes could be limited;

•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 in Item 2. MD&A. PG&E Corporation and the Utility do not undertake any obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “PG&E Progress,” “Chapter 11,” “Wildfire Updates” and “News & Events: Events & Presentations” tabs, respectively, in order to publicly disseminate such information. It is possible that any of these filings or information included therein could be deemed to be material information. The information contained on such website is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC. PG&E Corporation and the Utility are providing the address to this website solely for the information of investors and do not intend the address to be an active link.

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	(Unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions, except per share amounts)	2020		2019		2020		2019
Operating Revenues
Electric	$	3,810	$	3,554	$	10,285	$	9,292
Natural gas	1,072		878		3,436		3,094
Total operating revenues	4,882		4,432		13,721		12,386
Operating Expenses
Cost of electricity	1,114		1,070		2,418		2,506
Cost of natural gas	90		68		508		515
Operating and maintenance	2,290		2,206		6,398		6,235
Wildfire-related claims, net of insurance recoveries	25		2,548		195		6,448
Wildfire fund expense	120		—		293		—
Depreciation, amortization, and decommissioning	845		840		2,574		2,433
Total operating expenses	4,484		6,732		12,386		18,137
Operating Income (Loss)	398		(2,300)		1,335		(5,751)
Interest income	5		18		33		62
Interest expense	(391)		(52)		(844)		(215)
Other income, net	102		62		299		199
Reorganization items, net	(137)		(73)		(1,937)		(256)
Loss Before Income Taxes	(23)		(2,345)		(1,114)		(5,961)
Income tax provision (benefit)	(109)		(729)		394		(1,932)
Net Income (Loss)	86		(1,616)		(1,508)		(4,029)
Preferred stock dividend requirement of subsidiary	3		3		10		10
Income (Loss) Attributable to Common Shareholders	$	83	$	(1,619)	$	(1,518)	$	(4,039)
Weighted Average Common Shares Outstanding, Basic	1,967		529		1,012		528
Weighted Average Common Shares Outstanding, Diluted	2,140		529		1,012		528
Net Earnings (Loss) Per Common Share, Basic	$	0.04	$	(3.06)	$	(1.50)	$	(7.65)
Net Earnings (Loss) Per Common Share, Diluted	$	0.04	$	(3.06)	$	(1.50)	$	(7.65)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	(Unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
Net Income (Loss)	$	86	$	(1,616)	$	(1,508)	$	(4,029)
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 Income (Loss)	86		(1,616)		(1,508)		(4,029)
Preferred stock dividend requirement of subsidiary	3		3		10		10
Comprehensive Income (Loss) Attributable to Common Shareholders	$	83	$	(1,619)	$	(1,518)	$	(4,039)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


	(Unaudited)
	Balance At
(in millions)	September 30, 2020		December 31, 2019
ASSETS
Current Assets
Cash and cash equivalents	$	464	$	1,570
Restricted cash	215		7
Accounts receivable:
Customers (net of allowance for doubtful accounts of $98 and $43 at respective dates)	1,775		1,287
Accrued unbilled revenue	1,078		969
Regulatory balancing accounts	2,608		2,114
Other	1,075		2,617
Regulatory assets	346		315
Inventories:
Gas stored underground and fuel oil	94		97
Materials and supplies	552		550
Wildfire fund asset	465		—
Other	1,126		639
Total current assets	9,798		10,165
Property, Plant, and Equipment
Electric	65,498		62,707
Gas	23,636		22,688
Construction work in progress	2,941		2,675
Other	21		20
Total property, plant, and equipment	92,096		88,090
Accumulated depreciation	(27,426)		(26,455)
Net property, plant, and equipment	64,670		61,635
Other Noncurrent Assets
Regulatory assets	7,986		6,066
Nuclear decommissioning trusts	3,318		3,173
Operating lease right of use asset	1,893		2,286
Wildfire fund asset	5,932		—
Income taxes receivable	67		67
Other	1,923		1,804
Total other noncurrent assets	21,119		13,396
TOTAL ASSETS	$	95,587	$	85,196

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS


	(Unaudited)
	Balance At
(in millions, except share amounts)	September 30, 2020		December 31, 2019
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	2,432	$	—
Debtor-in-possession financing, classified as current	—		1,500
Accounts payable:
Trade creditors	2,756		1,954
Regulatory balancing accounts	2,326		1,797
Other	719		566
Operating lease liabilities	536		556
Interest payable	327		4
Disputed claims and customer refunds	240		—
Wildfire-related claims	1,975		—
Other	2,010		1,254
Total current liabilities	13,321		7,631
Noncurrent Liabilities
Long-term debt	36,311		—
Regulatory liabilities	9,981		9,270
Pension and other post-retirement benefits	1,894		1,884
Asset retirement obligations	6,019		5,854
Deferred income taxes	1,225		320
Operating lease liabilities	1,357		1,730
Other	4,415		2,573
Total noncurrent liabilities	61,202		21,631
Liabilities Subject to Compromise	—		50,546
Equity
Shareholders’ Equity
Common stock, no par value, authorized 3,600,000,000 and 800,000,000 shares at respective dates; 1,984,562,035 and 529,236,741 shares outstanding at respective dates	30,222		13,038
Reinvested earnings	(9,400)		(7,892)
Accumulated other comprehensive loss	(10)		(10)
Total shareholders’ equity	20,812		5,136
Noncontrolling Interest - Preferred Stock of Subsidiary	252		252
Total equity	21,064		5,388
TOTAL LIABILITIES AND EQUITY	$	95,587	$	85,196

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	(Unaudited)
	Nine Months Ended September 30,
(in millions)	2020		2019
Cash Flows from Operating Activities
Net loss	$	(1,508)	$	(4,029)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,574		2,433
Allowance for equity funds used during construction	(43)		(64)
Deferred income taxes and tax credits, net	923		(1,548)
Reorganization items, net (Note 2)	1,597		97
Wildfire fund expense	293		—
Disallowed capital expenditures	16		232
Other	260		112
Effect of changes in operating assets and liabilities:
Accounts receivable	(1,012)		(264)
Wildfire-related insurance receivable	1,657		35
Inventories	(12)		(68)
Accounts payable	465		371
Wildfire-related claims	(16,800)		(114)
Income taxes receivable/payable	—		8
Other current assets and liabilities	(1,557)		(7)
Regulatory assets, liabilities, and balancing accounts, net	(1,393)		90
Liabilities subject to compromise	413		6,704
Contributions to wildfire fund	(5,008)		—
Other noncurrent assets and liabilities	(84)		79
Net cash provided by (used in) operating activities	(19,219)		4,067
Cash Flows from Investing Activities
Capital expenditures	(5,475)		(4,192)
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,144		808
Purchases of nuclear decommissioning trust investments	(1,203)		(874)
Other	10		8
Net cash used in investing activities	(5,524)		(4,250)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	500		1,850
Repayments of debtor-in-possession credit facility	(2,000)		(350)
Debtor-in-possession credit facility debt issuance costs	(3)		(114)
Bridge facility financing fees	(73)		—
Pre-petition long-term debt repaid	(750)		—
Borrowings under revolving credit facilities	2,420		—
Repayments under revolving credit facilities	(1,480)		—
Borrowings under term loan credit facilities	3,000		—
Credit facilities financing fees	(22)		—
Proceeds from issuance of long-term debt, net of discount and issuance costs of $178	13,497		—
Repayment of long-term debt	(7)		—
Exchanged debt financing fees	(103)		—


Common stock issued, net of issuance costs	7,582		85
Equity Units issued	1,304		—
Other	(20)		14
Net cash provided by financing activities	23,845		1,485
Net change in cash, cash equivalents, and restricted cash	(898)		1,302
Cash, cash equivalents, and restricted cash at January 1	1,577		1,675
Cash, cash equivalents, and restricted cash at September 30	$	679	$	2,977
Less: Restricted cash and restricted cash equivalents included in other current assets	(215)		(7)
Cash and cash equivalents at September 30	$	464	$	2,970


Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(1,372)	$	(38)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	404	$	981
Operating lease liabilities arising from obtaining right-of-use assets	13		2,816
Common stock issued in satisfaction of liabilities	8,276		—

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

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, 2019	529,236,741	$	13,038	$	(7,892)	$	(10)	$	5,136	$	252	$	5,388
Net income	—	—		374		—		374		—		374
Other comprehensive loss	—	—		—		—		—		—		—
Common stock issued, net	549,155	—		—		—		—		—		—
Stock-based compensation amortization	—	(3)		—		—		(3)		—		(3)
Balance at March 31, 2020	529,785,896	$	13,035	$	(7,518)	$	(10)	$	5,507	$	252	$	5,759
Net loss	—	—		(1,968)		—		(1,968)		—		(1,968)
Other comprehensive loss	—	—		—		—		—		—		—
Common stock issued, net	7,459	—		—		—		—		—		—
Stock-based compensation amortization	—	10		—		—		10		—		10
Balance at June 30, 2020	529,793,355	$	13,045	$	(9,486)	$	(10)	$	3,549	$	252	$	3,801
Net income	—	—		86		—		86		—		86
Other comprehensive loss	—	—		—		—		—		—		—
Common stock issued, net	1,454,768,680	15,855		—		—		15,855		—		15,855
Equity units issued	—	1,304		—		—		1,304		—		1,304
Stock-based compensation amortization	—	18		—		—		18		—		18
Balance at September 30, 2020	1,984,562,035	$	30,222	$	(9,400)	$	(10)	$	20,812	$	252	$	21,064


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


See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME


	(Unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
Operating Revenues
Electric	$	3,810	$	3,554	$	10,285	$	9,292
Natural gas	1,072		878		3,436		3,094
Total operating revenues	4,882		4,432		13,721		12,386
Operating Expenses
Cost of electricity	1,114		1,070		2,418		2,506
Cost of natural gas	90		68		508		515
Operating and maintenance	2,311		2,208		6,421		6,252
Wildfire-related claims, net of insurance recoveries	25		2,548		195		6,448
Wildfire fund expense	120		—		293		—
Depreciation, amortization, and decommissioning	845		840		2,574		2,433
Total operating expenses	4,505		6,734		12,409		18,154
Operating Income (Loss)	377		(2,302)		1,312		(5,768)
Interest income	5		18		33		61
Interest expense	(323)		(52)		(764)		(213)
Other income, net	101		57		287		187
Reorganization items, net	(82)		(69)		(286)		(237)
Income (Loss) Before Income Taxes	78		(2,348)		582		(5,970)
Income tax provision (benefit)	(92)		(738)		434		(1,943)
Net Income (Loss)	170		(1,610)		148		(4,027)
Preferred stock dividend requirement	3		3		10		10
Income (Loss) Attributable to Common Stock	$	167	$	(1,613)	$	138	$	(4,037)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	(Unaudited)
	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
Net Income (Loss)	$	170	$	(1,610)	$	148	$	(4,027)
Other Comprehensive Income
Pension and other post-retirement benefit plans obligations (net of taxes of $0, $0, $0, and $0, at respective dates)	1		—		1		—
Total other comprehensive income	1		—		1		—
Comprehensive Income (Loss)	$	171	$	(1,610)	$	149	$	(4,027)

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS


	(Unaudited)
	Balance At
(in millions)	September 30, 2020		December 31, 2019
ASSETS
Current Assets
Cash and cash equivalents	$	202	$	1,122
Restricted cash	215		7
Accounts receivable:
Customers (net of allowance for doubtful accounts of $98 and $43 at respective dates)	1,775		1,287
Accrued unbilled revenue	1,078		969
Regulatory balancing accounts	2,608		2,114
Other	1,081		2,647
Regulatory assets	346		315
Inventories:
Gas stored underground and fuel oil	94		97
Materials and supplies	552		550
Wildfire fund asset	465		—
Other	1,112		628
Total current assets	9,528		9,736
Property, Plant, and Equipment
Electric	65,498		62,707
Gas	23,636		22,688
Construction work in progress	2,941		2,675
Other	18		18
Total property, plant, and equipment	92,093		88,088
Accumulated depreciation	(27,423)		(26,453)
Net property, plant, and equipment	64,670		61,635
Other Noncurrent Assets
Regulatory assets	7,986		6,066
Nuclear decommissioning trusts	3,318		3,173
Operating lease right of use asset	1,887		2,279
Wildfire fund asset	5,932		—
Income taxes receivable	66		66
Other	1,764		1,659
Total other noncurrent assets	20,953		13,243
TOTAL ASSETS	$	95,151	$	84,614

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS


	(Unaudited)
	Balance At
(in millions. except share amounts)	September 30, 2020		December 31, 2019
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	2,432	$	—
Debtor-in-possession financing, classified as current	—		1,500
Accounts payable:
Trade creditors	2,719		1,949
Regulatory balancing accounts	2,326		1,797
Other	759		675
Operating lease liabilities	533		553
Interest payable	298		4
Disputed claims and customer refunds	240		—
Wildfire-related claims	1,975		—
Other	1,998		1,263
Total current liabilities	13,280		7,741
Noncurrent Liabilities
Long-term debt	31,657		—
Regulatory liabilities	9,981		9,270
Pension and other post-retirement benefits	1,797		1,884
Asset retirement obligations	6,019		5,854
Deferred income taxes	1,387		442
Operating lease liabilities	1,354		1,726
Other	4,456		2,626
Total noncurrent liabilities	56,651		21,802
Liabilities Subject to Compromise	—		49,736
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	28,286		8,550
Reinvested earnings	(4,648)		(4,796)
Accumulated other comprehensive income	2		1
Total shareholders’ equity	25,220		5,335
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	95,151	$	84,614

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	(Unaudited)
	Nine Months Ended September 30,
(in millions)	2020		2019
Cash Flows from Operating Activities
Net income (loss)	$	148	$	(4,027)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,574		2,433
Allowance for equity funds used during construction	(43)		(64)
Deferred income taxes and tax credits, net	961		(1,555)
Reorganization items, net (Note 2)	3		92
Wildfire fund expense	293		—
Disallowed capital expenditures	16		232
Other	237		79
Effect of changes in operating assets and liabilities:
Accounts receivable	(987)		(274)
Wildfire-related insurance receivable	1,657		35
Inventories	(12)		(68)
Accounts payable	423		418
Wildfire-related claims	(16,800)		(114)
Income taxes receivable/payable	—		1
Other current assets and liabilities	(1,594)		9
Regulatory assets, liabilities, and balancing accounts, net	(1,393)		90
Liabilities subject to compromise	401		6,695
Contributions to wildfire fund	(5,008)		—
Other noncurrent assets and liabilities	(46)		96
Net cash provided by (used in) operating activities	(19,170)		4,078
Cash Flows from Investing Activities
Capital expenditures	(5,475)		(4,192)
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,144		808
Purchases of nuclear decommissioning trust investments	(1,203)		(874)
Other	10		8
Net cash used in investing activities	(5,524)		(4,250)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility	500		1,850
Repayments of debtor-in-possession credit facility	(2,000)		(350)
Debtor-in-possession credit facility debt issuance costs	(3)		(98)
Bridge facility financing fees	(33)		—
Pre-petition long-term debt repaid	(100)		—
Borrowings under revolving credit facilities	2,420		—
Repayments under revolving credit facilities	(1,480)		—
Borrowings under term loan credit facilities	3,000		—
Credit facilities financing fees	(22)		—
Proceeds from issuance of long-term debt, net of discount and issuance costs of $88	8,837		—


Exchanged debt financing fees	(103)		—
Equity contribution from PG&E Corporation	12,986		—
Other	(20)		14
Net cash provided by financing activities	23,982		1,416
Net change in cash, cash equivalents, and restricted cash	(712)		1,244
Cash, cash equivalents, and restricted cash at January 1	1,129		1,302
Cash, cash equivalents, and restricted cash at September 30	$	417	$	2,546
Less: Restricted cash and restricted cash equivalents included in other current assets	(215)		(7)
Cash and cash equivalents at September 30	$	202	$	2,539


Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(1,305)	$	(36)
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	404	$	981
Operating lease liabilities arising from obtaining right-of-use assets	13		2,807
Common stock equity infusion from PG&E Corporation used to satisfy liabilities	6,750		—

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ 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, 2019	$	258	$	1,322	$	8,550	$	(4,796)	$	1	$	5,335
Net income	—		—		—		451		—		451
Balance at March 31, 2020	$	258	$	1,322	$	8,550	$	(4,345)	$	1	$	5,786
Net loss	—		—		—		(473)		—		(473)
Balance at June 30, 2020	$	258	$	1,322	$	8,550	$	(4,818)	$	1	$	5,313
Net income	—		—		—		170		—		170
Other comprehensive income	—		—		—		—		1		1
Equity contribution	—		—		19,736		—		—		19,736
Balance at September 30, 2020	$	258	$	1,322	$	28,286	$	(4,648)	$	2	$	25,220


(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
Balance at March 31, 2019	$	258	$	1,322	$	8,550	$	2,959	$	(1)	$	13,088
Net loss	—		—		—		(2,550)		—		(2,550)
Balance at June 30, 2019	$	258	$	1,322	$	8,550	$	409	$	(1)	$	10,538
Net loss	—		—		—		(1,610)		—		(1,610)
Balance at September 30, 2019	$	258	$	1,322	$	8,550	$	(1,201)	$	(1)	$	8,928


See accompanying Notes to the Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NOTE 1: 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 in one segment).

The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments 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, 2019 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in Item 8 of the 2019 Form 10-K. This quarterly report should be read in conjunction with the 2019 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, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, AROs, insurance receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred.

Chapter 11 Emergence 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. PG&E Corporation and the Utility suffered material losses as a result of the 2017 Northern California wildfires and the 2018 Camp fire, which contributed to the decision to file for Chapter 11 protection on January 29, 2019. Uncertainty regarding these matters previously raised substantial doubt about PG&E Corporation’s and the Utility’s abilities to continue as going concerns.

As a result of PG&E Corporation’s and the Utility’s emergence from Chapter 11 on the Effective Date of July 1, 2020, substantial doubt has been alleviated regarding the Company’s ability to meet its obligations as they become due within one year after the date the financial statements were issued. (For more information regarding the Chapter 11 Cases, see Note 2 below.)

NOTE 2: BANKRUPTCY FILING

Chapter 11 Proceedings

On January 29, 2019, PG&E Corporation and the Utility commenced the Chapter 11 Cases with the Bankruptcy Court. Prior to the Effective Date, PG&E Corporation and the Utility continued 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.

Except as otherwise set forth in the Plan, the Confirmation Order (as defined below) or another order of the Bankruptcy Court, substantially all pre-petition liabilities were discharged under the Plan.

Significant Bankruptcy Court Actions

Plan of Reorganization and Restructuring Support Agreements

On June 19, 2020, PG&E Corporation and the Utility, certain funds and accounts managed or advised by Abrams Capital Management, LP (“Abrams”), and certain funds and accounts managed or advised by Knighthead Capital Management, LLC (“Knighthead” and, together with Abrams, the “Shareholder Proponents”) filed PG&E Corporation’s and the Utility’s and the Shareholder Proponents’ Joint Chapter 11 Plan of Reorganization dated June 19, 2020 with the Bankruptcy Court (the “Plan”). On June 20, 2020, the Bankruptcy Court confirmed the Plan by issuing a confirmation order (the “Confirmation Order”). PG&E Corporation and the Utility emerged from Chapter 11 on July 1, 2020.

On September 22, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement with certain holders of wildfire insurance subrogation claims (as amended, the “Subrogation RSA”, and such claims, the “Subrogation Claims”). On December 19, 2019, the Bankruptcy Court entered an order approving the Subrogation RSA. As of September 30, 2020, PG&E Corporation and the Utility incurred $53 million in professional fees related to the Subrogation RSA. See “Restructuring Support Agreement with Holders of Subrogation Claims” in Note 10 for further information on the Subrogation RSA.

On December 6, 2019, PG&E Corporation and the Utility entered into a Restructuring Support Agreement, which was subsequently amended on December 16, 2019 (as amended, the “TCC RSA”), with the TCC, the attorneys and other advisors and agents for holders of claims against PG&E Corporation and the Utility relating to the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (other than the Subrogation Claims and Public Entity Wildfire Claims (as defined below)) (the “Fire Victim Claims”) that are signatories to the TCC RSA, and the Shareholder Proponents. On December 19, 2019, the Bankruptcy Court entered an order approving the TCC RSA. See “Restructuring Support Agreement with the TCC” in Note 10 for further information on the TCC RSA.

On January 22, 2020, PG&E Corporation and the Utility entered into a Restructuring Support Agreement with those holders of senior unsecured debt of the Utility that are identified as “Consenting Noteholders” therein and the Shareholder Proponents (the “Noteholder RSA”). On February 5, 2020, the Bankruptcy Court entered an order approving the Noteholder RSA.

Confirmation of the Plan of Reorganization

The Plan as confirmed by the Confirmation Order provides for certain transactions and the satisfaction and treatment of claims against and interests in PG&E Corporation and the Utility, each in accordance with the terms of the Plan, including the transactions described below. The Plan provides for the following treatment of various classes of claims as described below. PG&E Corporation and the Utility are in the process of resolving and paying claims pursuant to the treatment provided under the Plan.

•PG&E Corporation and the Utility funded the Fire Victim Trust for the benefit of all holders of Fire Victim Claims, whose claims were channeled to the Fire Victim Trust on the Effective Date with no recourse to PG&E Corporation and the Utility. In full and final satisfaction, release, and discharge of all Fire Victim Claims, the Fire Victim Trust was funded with $5.4 billion in cash (with an additional $1.35 billion in cash to be funded on a deferred basis), common stock of PG&E Corporation representing 22.19% of the outstanding common stock of PG&E Corporation as of the Effective Date (subject to potential adjustments), plus the assignment of certain rights and causes of action. As a result of such funding, all Fire Victim Claims have been satisfied, released, discharged and channeled to the Fire Victim Trust with no recourse to PG&E Corporation or the Utility;

•PG&E Corporation and the Utility funded a trust (the “Subrogation Wildfire Trust”) for the benefit of holders of Subrogation Claims in the amount of $11.0 billion in cash. Such amount was initially funded into escrow and later paid to the Subrogation Wildfire Trust. As a result of such funding, all Subrogation Claims have been satisfied, released and discharged and channeled to the Subrogation Wildfire Trust with no recourse to PG&E Corporation or the Utility;

•PG&E Corporation and the Utility paid $1.0 billion in cash to certain local public entities (the “Settling Public Entities”) that entered into plan support agreements with PG&E Corporation and the Utility and established a segregated fund in the amount of $10 million to be used to reimburse the Settling Public Entities for any and all legal fees and costs associated with the defense or resolution of any third party claims against the Settling Public Entities in full and final satisfaction, release and discharge of such Settling Public Entities’ wildfire related claims;

•The following pre-petition notes of the Utility: (a) 3.50% Senior Notes due October 1, 2020; (b) 4.25% Senior Notes due May 15, 2021; (c) 3.25% Senior Notes due September 15, 2021; and (d) 2.45% Senior Notes due August 15, 2020), (collectively, the “Utility Short-Term Senior Notes”); the following pre-petition notes of the Utility: (a) 6.05% Senior Notes due 2034; (b) 5.80% Senior Notes due March 1, 2037; (c) 6.35% Senior Notes due February 15, 2038; (d) 6.25% Senior Notes due March 1, 2039; (e) 5.40% Senior Notes due January 15, 2040; and (f) 5.125% Senior Notes due November 15, 2043, (collectively, the “Utility Long-Term Senior Notes) and the pre-petition credit agreements of the Utility, including in connection with the pollution control bonds (except for $100 million of pollution control bonds (Series 2008F and 2010E), which were repaid in cash) (collectively, the “Utility Funded Debt”) were refinanced and all other Utility pre-petition senior notes (collectively, the “Utility Reinstated Senior Notes”) were reinstated and collateralized on or around the Effective Date through the issuance of a corresponding series of first mortgage bonds of the Utility;

•PG&E Corporation paid in full all of its pre-petition funded debt obligations that were allowed in the Chapter 11 Cases;

•PG&E Corporation and the Utility repaid all borrowings under the DIP Facilities (as defined in the DIP Credit Agreement) and will pay all other allowed administrative expense claims in accordance with the Plan;

•Holders of allowed claims by a governmental authority entitled to priority in payment under sections 502(i) and 507(a)(8) of the Bankruptcy Code (“Priority Tax Claims”) have received or will receive in the future, cash in an amount equal to such allowed Priority Tax Claims on the Effective Date or as soon as reasonably practicable thereafter;

•Holders of allowed secured claims other than Priority Tax Claims or secured claims related to the DIP facilities (“Other Secured Claims”) received cash in an amount equal to such Other Secured Claims;

•Holders of allowed claims other than administrative expense claims or Priority Tax Claims, entitled to priority in payment as specified in section 507(a)(3), (4), (5), (6), (7), or (9) of the Bankruptcy Code (“Priority Non-Tax Claims”) received cash in an amount equal to such allowed Priority Non-Tax Claims;

•PG&E Corporation and the Utility will pay in full all pre-petition unsecured claims that do not fall within any of the other classes of unsecured claims under the Plan (“General Unsecured Claims”) that are allowed in the Chapter 11 Cases; and

•PG&E Corporation and the Utility will pay all allowed claims that are subject to subordination under section 510(b) of the Bankruptcy Code other than subordinated claims related to the common stock of PG&E Corporation (“Subordinated Debt Claims”) in full and provide to each holder of an allowed claim that relates to the common stock of PG&E Corporation that is subject to subordination under section 510(b) of the Bankruptcy Code (a “HoldCo Rescission or Damage Claim”) a number of shares of PG&E Corporation common stock based on a formula as specified in the Plan that varies depending on when the claimant purchased the affected shares of common stock.

In addition, the Plan also provides for the following in connection with or following the implementation of the Plan:

•Holders of claims related to the 2016 Ghost Ship fire are entitled to pursue their claims against PG&E Corporation and the Utility (with any recovery being limited to amounts available under PG&E Corporation’s and the Utility’s insurance policies for the 2016 year);

•Holders of certain claims may be able to pursue their claims against PG&E Corporation and the Utility, such as administrative expense claims that have not been satisfied or come due by the Effective Date, claims arising from wildfires occurring after the Petition Date that have not been satisfied by the Effective Date (including the 2019 Kincade fire), and claims relating to certain FERC refund proceedings, workers’ compensation benefits and certain environmental claims;

•PG&E Corporation or the Utility, as applicable, assumed all of their respective power purchase agreements and community choice aggregation servicing agreements; and

•PG&E Corporation or the Utility, as applicable, assumed all of their respective pension obligations, other employee obligations, and collective bargaining agreements with labor.

The Confirmation Order contains a channeling injunction that is also in the Plan that provides, among other things, that the sole source of recovery for holders of Subrogation Claims will be from the Subrogation Wildfire Trust and the sole source of recovery for holders of Fire Victim Claims will be from the Fire Victim Trust. The holders of such claims will have no recourse to or claims whatsoever against PG&E Corporation and the Utility or their assets and properties.

The Plan as confirmed by the Confirmation Order provides for certain financing transactions as follows:

•one or more equity offerings of up to $9.0 billion of gross proceeds in cash through the issuance of common stock and/or other equity and/or equity-linked securities pursuant to one or more offerings and/or private placements;

•the issuance of $4.75 billion of new PG&E Corporation debt;

•the reinstatement of $9.575 billion of pre-petition debt of the Utility; and

•the issuance of $23.775 billion of new Utility debt, consisting of (i) $6.2 billion of the Utility’s 4.55% Senior Notes due 2030 and 4.95% Senior Notes due 2050 (the “New Utility Long-Term Bonds”) to be issued to holders of certain pre-petition senior notes of the Utility pursuant to the Plan, (ii) $1.75 billion of the Utility’s 3.45% Senior Notes due 2025 and 3.75% Senior Notes due 2028 (the “New Utility Short-Term Bonds”) to be issued to holders of certain pre-petition senior notes of the Utility pursuant to the Plan, (iii) $3.9 billion of the Utility’s 3.15% Senior Notes due 2025 and 4.50% Senior Notes due 2040 (the “New Utility Funded Debt Exchange Bonds”) to be issued to holders of certain pre-petition indebtedness of the Utility pursuant to the Plan and (iv) $11.925 billion of new debt securities or bank debt of the Utility to be issued to third parties for cash on or prior to the Effective Date (of which $6.0 billion is expected to be repaid with the proceeds of a new securitization transaction after the Effective Date) (see Note 5 below for a description of the debt transactions that occurred on or before the Effective Date).

The foregoing financing transactions occurred on or around the Effective Date.

On July 27, 2020, Elliott Management Corporation, a Consenting Noteholder, filed a motion with the Bankruptcy Court asserting an approximately $250 million administrative claim against PG&E Corporation and the Utility, alleging that PG&E Corporation and the Utility breached the Noteholder RSA by failing to use their best efforts to cause Backstop Parties to transfer up to $2.0 billion of Backstop Commitments to certain of the Consenting Noteholders. On August 26, 2020, PG&E Corporation and the Utility filed an initial legal opposition to the Elliott Management Corporation’s motion. Elliott Management Corporation filed its response on September 14, 2020, and PG&E Corporation and the Utility filed their reply on September 25, 2020. A hearing on the initial legal opposition to the motion was held on October 13, 2020. On October 22, 2020, the Bankruptcy Court issued a decision and separate orders disallowing the administrative expense claims asserted by Elliott Management Corporation and other Consenting Noteholders. PG&E Corporation and the Utility are unable to predict the timing and outcome of any appeals of the Bankruptcy Court’s decision and orders disallowing these claims.

On the Effective Date, pursuant to the Plan, the Utility entered into a tax benefits payment agreement (the “Tax Benefits Payment Agreement”) with the Fire Victim Trust, pursuant to which the Utility agreed to pay to the Fire Victim Trust in cash an aggregate amount of $1.35 billion, comprising (i) at least $650 million of tax benefits arising from certain tax deductions related to pre-petition wildfires (“Tax Benefits”) for fiscal year 2020 to be paid on or before January 15, 2021 (the “First Payment Date”) and (ii) of the remainder of $1.35 billion of Tax Benefits for fiscal year 2021 to be paid on or before January 15, 2022.

Also on the Effective Date, pursuant to the Plan, the Utility entered into an assignment agreement with the Fire Victim Trust, pursuant to which the Utility agreed to transfer to the Fire Victim Trust on the Effective Date 477 million shares (such shares, the “Fire Victim Trust Shares”) of common stock of PG&E Corporation, no par value (the “Common Stock”). As a result of the Equity Units Underwriters exercising their option to purchase 1.45 million additional Equity Units, on August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the assignment agreement with the Fire Victim Trust.

Further, on the Effective Date, PG&E Corporation and the Utility funded a $10 million fund established for the benefit of the Supporting Public Entities under the PSAs in accordance with the terms of the Plan and the PSAs with the Supporting Public Entities, and also made a payment of $1.0 billion in cash to the public entities who are party to the PSAs with the Supporting Public Entities. Also, on the Effective Date, PG&E Corporation and the Utility funded $100 million to the Subrogation Wildfire Trust and placed the balance of the $11.0 billion in a segregated escrow account established and owned by the Subrogation Wildfire Trust for the benefit of holders of Subrogation Claims, which was subsequently paid to the Subrogation Wildfire Trust.

Equity Financing

In connection with its emergence from Chapter 11 in July 2020, PG&E raised an aggregate of $9.0 billion of gross proceeds through the issuance of common stock and other equity-linked instruments. For more information, see Note 6 below.

Equity Backstop Commitments and Forward Stock Purchase Agreements

As of March 6, 2020, PG&E Corporation entered into Chapter 11 Plan Backstop Commitment Letters (collectively, as amended by the Consent Agreements (as defined below), the “Backstop Commitment Letters”) with investors (collectively, the “Backstop Parties”), pursuant to which the Backstop Parties severally agreed to fund up to $12.0 billion of proceeds to finance the Plan through the purchase of PG&E Corporation common stock, subject to the terms and conditions set forth in such Backstop Commitment Letters (the “Backstop Commitments”). As a result of PG&E Corporation emerging from Chapter 11 on July 1, 2020, the Backstop Commitments were not utilized and terminated in accordance with their terms.

The commitment premium for the Backstop Commitments was paid in shares of PG&E Corporation’s common stock (with each Backstop Party receiving its pro rata share of 119 million shares of PG&E Corporation’s common stock based on the proportion of the amount of such Backstop Party’s Backstop Commitment to $12.0 billion). PG&E Corporation issued the commitment premium shares to the Backstop Parties on July 1, 2020 in connection with emerging from Chapter 11.

On June 30, 2020, PG&E Corporation recorded approximately $1.1 billion of expense related to the Backstop Commitment premium in Reorganization items, net. This amount was primarily based on PG&E Corporation’s closing stock price on June 30, 2020 of $8.87 per share. On the Effective Date, PG&E Corporation’s closing price was $9.03 per share and as a result, PG&E Corporation recorded an additional $19 million expense as of September 30, 2020.

Under the Backstop Commitment Letters, PG&E Corporation and the Utility have also agreed to reimburse the Backstop Parties for reasonable professional fees and expenses of up to $34 million in the aggregate for the legal advisors and $19 million in the aggregate for the financial advisor, upon the terms and conditions set forth in the Backstop Commitment Letters. As of September 30, 2020, PG&E Corporation recorded $49 million in professional fees and related expenses to the Backstop Parties in Reorganization items, net.

In connection with PG&E Corporation’s underwritten offerings of up to $5.75 billion of equity securities to finance the transactions contemplated by the Plan (the “Offerings”), up to $523 million was issuable pursuant to customary options granted to the underwriters thereof to purchase the Option Securities (as defined below in Note 6).

On June 19, 2020, PG&E Corporation entered into prepaid forward contracts (the “Forward Stock Purchase Agreements”) with the Backstop Parties. Each Forward Stock Purchase Agreement provided that, subject to certain conditions, the Backstop Party will purchase on the Effective Date, and receive on the Settlement Date (as defined in each Forward Stock Purchase Agreement) an amount of common stock of PG&E Corporation equal to its pro rata share of the value of the Option Securities not purchased by the underwriters (such amount, each Backstop Party’s “Greenshoe Backstop Purchase Amount” and all Greenshoe Backstop Purchase Amounts in the aggregate, the “Aggregate Greenshoe Backstop Purchase Amount”), at a price per share equal to the lesser of (i) the lowest per share price of common stock sold on an underwritten basis to the public in an offering of common stock of PG&E Corporation, as disclosed on the cover page of the prospectus or prospectus supplement, and (ii) the price per share payable by the investors party to the Investment Agreement dated as of June 7, 2020 (such lesser price, the “Settlement Price”). The Settlement Price was $9.50 per share. Each Forward Stock Purchase Agreement expired on August 3, 2020.

On June 25, 2020, the Backstop Parties funded the Greenshoe Backstop Purchase Amount to PG&E Corporation in the amount of $523 million which was recorded in Other current liabilities on the Condensed Consolidated Financial Statements. PG&E Corporation applied the proceeds of such funding to distributions under the Plan on the Effective Date. On August 3, 2020, PG&E Corporation redeemed $120.5 million of the Forward Stock Purchase Agreements payable in cash as a result of the exercise by the underwriters of their option to purchase Equity Units pursuant to the Equity Units Underwriting Agreement (as defined below in Note 6). On August 3, 2020, PG&E Corporation delivered 42.3 million shares of PG&E Corporation common stock to the Backstop Parties to settle the portion of the Forward Stock Purchase Agreements that was not redeemed.

Additionally, each Forward Stock Purchase Agreement provided that, subject to the consummation by PG&E Corporation of the Offerings, PG&E Corporation would issue to each Backstop Party its pro rata share of 50 million shares of common stock (such shares, each Backstop Party’s “Additional Backstop Premium Shares”). The Additional Backstop Premium Shares were issued to Backstop Parties on the Effective Date. On June 30, 2020, PG&E Corporation recorded $444 million of expense related to the Additional Backstop Premium Shares in Reorganization items, net. This amount was based primarily on PG&E Corporation’s closing stock price on June 30, 2020 of $8.87 per share. On the Effective Date, PG&E Corporation’s closing stock price was $9.03 per share and as a result, PG&E Corporation recorded an additional $8 million expense as of September 30, 2020.

Financial Reporting in Reorganization

Effective on the Petition Date and up to June 30, 2020, PG&E Corporation and the Utility applied 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 was directly associated with reorganization proceedings must have been reported separately as reorganization items, net in the Condensed Consolidated Statements of Income. In addition, the balance sheet must have distinguished pre-petition LSTC of PG&E Corporation and the Utility from pre-petition liabilities that were not subject to compromise, post-petition liabilities, and liabilities of the subsidiaries of PG&E Corporation that were not debtors in the Chapter 11 Cases in the Condensed Consolidated Balance Sheets. LSTC are pre-petition obligations that were not fully secured and had at least a possibility of not being repaid at the full claim amount. Where there was uncertainty about whether a secured claim would be paid or impaired pursuant to the Chapter 11 Cases, PG&E Corporation and the Utility classified the entire amount of the claim as LSTC.

Furthermore, the realization of assets and the satisfaction of liabilities are subject to uncertainty. Pursuant to the Plan and Confirmation Order, actions to enforce or otherwise effect the payment of certain claims against PG&E Corporation and the Utility in existence before the Petition Date were subject to an injunction and were subject to treatment under the Plan. These claims were reflected as LSTC in the Condensed Consolidated Balance Sheets at December 31, 2019. Additional claims may arise for contingencies and other unliquidated and 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.

Upon emergence from Chapter 11 on July 1, 2020, PG&E Corporation and the Utility were not required to apply fresh start accounting based on the provisions of ASC 852 since the entity’s reorganization value immediately before the date of confirmation is more than the total of all its post-petition liabilities and allowed claims.

Liabilities Subject to Compromise

As a result of the commencement of the Chapter 11 Cases, the payment of pre-petition liabilities was subject to compromise or other treatment pursuant to the Plan. Generally, actions to enforce or otherwise effect payment of pre-petition liabilities were subject to an injunction and will be satisfied pursuant to the Plan and the Chapter 11 claims reconciliation process.

Prior to June 30, 2020, pre-petition liabilities that were subject to compromise were required to be reported at the amounts expected to be allowed. Therefore, liabilities subject to compromise as of December 31, 2019 in the table below reflected management’s estimates of amounts expected to be allowed in the Chapter 11 Cases, based upon, among other things, the status of negotiations with creditors. As of June 30, 2020, such amounts were reclassified to current or non-current liabilities in the Condensed Consolidated Balance Sheets, based upon management’s judgment as to the timing for settlement of such liabilities.

Liabilities subject to compromise as of December 31, 2019 which were settled or reclassified during the nine months ended September 30, 2020 consist of the following:


(in millions)	Utility		PG&E Corporation (1)		December 31, 2019 PG&E Corporation Consolidated		Change in Estimated Allowed Claim 2020 (2)		Cash Payment		Reclassified as of June 30, 2020 (3)		Utility		PG&E Corporation (1)		September 30, 2020 PG&E Corporation Consolidated
Financing debt	$	22,450	$	666	$	23,116	$	351	$	—	$	(23,467)	$	—	$	—	$	—
Wildfire-related claims	25,548		—		25,548		18		(23)		(25,543)		—		—		—
Trade creditors (4)	1,183		5		1,188		6		(14)		(1,180)		—		—		—
Non-qualified benefit plan	20		137		157		—		—		(157)		—		—		—
2001 bankruptcy disputed claims	234		—		234		4		—		(238)		—		—		—
Customer deposits & advances	71		—		71		12		—		(83)		—		—		—
Other	230		2		232		59		—		(291)		—		—		—
Total Liabilities Subject to Compromise	$	49,736	$	810	$	50,546	$	450	$	(37)	$	(50,959)	$	—	$	—	$	—

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

(2) Change in estimated allowed claim amounts are primarily due to interest accruals with the exception of the “wildfire-related claims”, “customer deposits & advances”, and “other” line items which are mainly due to the adjustment to recorded liabilities.

(3) Amounts reclassified as of June 30, 2020 included $8.6 million to Accounts payable - other, $237.6 million to Disputed claims and customer refunds, $1,347.4 million to Interest payable, $21,425.7 million to Long-term debt, $300.0 million to Short-term borrowings, $450.0 million to Long-term debt, classified as current, $301.0 million to Other current liabilities, $97.9 million to Other non-current liabilities, $121.3 million to Pension and other post-retirement benefits, $1,126.9 million to Accounts payable - trade creditors, and $25,542.7 million to Wildfire-related claims on the Condensed Consolidated Balance Sheets.

(4) As of October 23, 2020, $5 million and $801 million has been repaid by PG&E Corporation and the Utility, respectively.

Chapter 11 Claims Process

PG&E Corporation and the Utility have received over 100,000 proofs of claim since the Petition Date, of which approximately 80,000 were channeled to the Subrogation Wildfire Trust and Fire Victim Trust. The claims channeled to the Subrogation Wildfire Trust and Fire Victim Trust will be resolved by such trusts and PG&E Corporation and the Utility have no further liability in connection with such claims. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims including litigation claims, trade creditor claims, non-qualified benefit plan claims, along with other tax and regulatory claims, and therefore the ultimate liability of PG&E Corporation or the Utility for such claims may differ from the amounts asserted in such claims. Allowed claims are paid in accordance with the Plan and the Confirmation Order.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation, other than as provided in the Plan or the Confirmation Order.

The Plan, however, provides that the holders of certain claims may pursue their claims against PG&E Corporation and the Utility on or after the Effective Date, including, but not limited to, the following:

•claims arising after the January 29, 2019 Petition Date that constitute administrative expense claims, which will not be discharged pursuant to the Plan, other than allowed administrative expense claims that have been paid in cash or otherwise satisfied in the ordinary course in an amount equal to the allowed amount of such claim on or prior to the Effective Date;

•claims of the Ghost Ship fire litigation (with any recovery being limited to amounts available under PG&E Corporation’s and the Utility’s insurance policies for the 2016 year);

•claims arising out of or based on the 2019 Kincade fire, which the California Department of Forestry and Fire Protection has determined was caused by the Utility’s transmission lines; which is currently under investigation by the CPUC and the Sonoma County District Attorney’s Office; and which may also be under investigation by various other entities, including law enforcement agencies; and

•certain FERC refund proceedings, workers’ compensation benefits and environmental claims.

Furthermore, holders of certain claims may assert that they are entitled under the Plan or the Bankruptcy Code to pursue, or continue to pursue, their claims against PG&E Corporation and the Utility on or after the Effective Date, including but not limited to, claims arising from or relating to:

•the purported de-energization securities class action filed in October 2019 and amended to add PG&E Corporation in April 2020. For more information on the filing, see Note 10 below;

•the purported PSPS class action filed in December 2019 and seeking up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid, was dismissed on April 3, 2020, and subsequently appealed on April 6, 2020. For more information on the filing, see Note 11 below; and

•indemnification or contributing claims, including with respect to the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire.

In addition, claims continue to be pursued against PG&E Corporation and the Utility and certain of their respective current and former directors and officers as well as certain underwriters, in connection with three purported securities class actions, as further described in Note 10 under the heading “Securities Class Action Litigation.”

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. Pursuant to the Plan, on and after the Effective Date, the holders of such claims are entitled to pursue their claims against the Reorganized Utility as if the Chapter 11 Cases had not been commenced.

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 and other. Cash paid for reorganization items, net was $96 million and $300 million for PG&E Corporation and the Utility, respectively, during the nine months ended September 30, 2020 as compared to $13 million and $145 million for PG&E Corporation and the Utility, respectively, during the same period in 2019. Cash paid for reorganization items, net was $6 million and $93 million for PG&E Corporation and the Utility, respectively, during the three months ended September 30, 2020 as compared to cash received in the amount of $2 million and cash paid in the amount of $67 million for PG&E Corporation and the Utility, respectively, during the same period in 2019. Of the $300 million in cash paid for the Utility’s reorganization items, during the nine months ended September 30, 2020, $35 million in facility fees related to the Debt Commitment Letters were recorded to a regulatory asset as they were deemed probable of recovery. Reorganization items, net for the three and nine months ended September 30, 2020 include the following:


	Three Months Ended September 30, 2020
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	—	$	—	$	—
Legal and other	90		55		145
Interest and other	(8)		—		(8)
Total reorganization items, net	$	82	$	55	$	137

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


	Nine Months Ended September 30, 2020
(in millions)	Utility		PG&E Corporation (1)		PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	3	$	—	$	3
Legal and other (2)	296		1,653		1,949
Interest and other	(13)		(2)		(15)
Total reorganization items, net	$	286	$	1,651	$	1,937

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

(2) Amount includes $1.5 billion in equity backstop premium expense and bridge loan facility fees.

Reorganization items, net for the three months ended September 30, 2019 and from the Petition Date through September 30, 2019 include the following:


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

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


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

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

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 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K.

Variable Interest Entities

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

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility has a controlling interest or was the primary beneficiary of any of these VIEs at September 30, 2020, the Utility assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at September 30, 2020, it did not consolidate any of them.

Pension and Other Post-Retirement Benefits

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

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2020 and 2019 were as follows:


	Pension Benefits				Other Benefits
	Three Months Ended September 30,
(in millions)	2020		2019		2020		2019
Service cost for benefits earned (1)	$	133	$	110	$	15	$	14
Interest cost	178		189		16		19
Expected return on plan assets	(261)		(226)		(34)		(31)
Amortization of prior service cost	(1)		(1)		3		3
Amortization of net actuarial loss	1		1		(5)		—
Net periodic benefit cost	50		73		(5)		5
Regulatory account transfer (2)	34		10		—		—
Total	$	84	$	83	$	(5)	$	5

(1) A portion of service costs are capitalized pursuant to GAAP.

(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
	Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
Service cost for benefits earned (1)	$	397	$	332	$	46	$	42
Interest cost	535		568		47		57
Expected return on plan assets	(783)		(679)		(103)		(92)
Amortization of prior service cost	(4)		(4)		10		10
Amortization of net actuarial loss	3		2		(15)		(2)
Net periodic benefit cost	148		219		(15)		15
Regulatory account transfer (2)	102		31		—		—
Total	$	250	$	250	$	(15)	$	15

(1) A portion of service costs are capitalized pursuant to GAAP.

(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.

Pursuant to the Plan and Confirmation Order, all existing pension and other benefit plans were deemed assumed by PG&E Corporation and the Utility.

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) consisted of the following:


	Pension Benefits		Other Benefits		Total
(in millions, net of income tax)	Three Months Ended September 30, 2020
Beginning balance	$	(22)	$	17	$	(5)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $0 and $1, respectively)	(1)		2		1
Amortization of net actuarial loss (net of taxes of $0 and $1, respectively)	1		(4)		(3)
Regulatory account transfer (net of taxes of $1 and $0, respectively)	—		2		2
Net current period other comprehensive gain (loss)	—		—		—
Ending balance	$	(22)	$	17	$	(5)

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


	Pension Benefits		Other Benefits		Total
(in millions, net of income tax)	Nine Months Ended September 30, 2020
Beginning balance	$	(22)	$	17	$	(5)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1 and $3, respectively)	(3)		7		4
Amortization of net actuarial loss (net of taxes of $1 and $4, respectively)	2		(11)		(9)
Regulatory account transfer (net of taxes of $1 and $1, respectively)	1		4		5
Net current period other comprehensive gain (loss)	—		—		—
Ending balance	$	(22)	$	17	$	(5)


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

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 GT&S rate cases, 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 September 30,				Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
Electric
Revenue from contracts with customers
Residential	$	1,862	$	1,557	$	4,092	$	3,839
Commercial	1,455		1,481		3,537		3,568
Industrial	453		466		1,135		1,085
Agricultural	657		496		1,149		844
Public street and highway lighting	17		17		51		50
Other (1)	(148)		(82)		54		(391)
Total revenue from contracts with customers - electric	4,296		3,935		10,018		8,995
Regulatory balancing accounts (2)	(486)		(381)		267		297
Total electric operating revenue	$	3,810	$	3,554	$	10,285	$	9,292

Natural gas
Revenue from contracts with customers
Residential	$	303	$	249	$	1,795	$	1,764
Commercial	90		92		434		461
Transportation service only	259		264		902		950
Other (1)	27		(98)		(153)		(303)
Total revenue from contracts with customers - gas	679		507		2,978		2,872
Regulatory balancing accounts (2)	393		371		458		222
Total natural gas operating revenue	1,072		878		3,436		3,094
Total operating revenues	$	4,882	$	4,432	$	13,721	$	12,386

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

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

Initial and annual contributions to the Wildfire Fund established pursuant to AB 1054

On the Effective Date, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. As of September 30, 2020, PG&E Corporation and the Utility have nine remaining annual contributions of $193 million. PG&E Corporation and the Utility account for the contributions to the Wildfire Fund similarly to prepaid insurance with expense being allocated to periods ratably based on an estimated period of coverage. The Wildfire Fund is available to pay for eligible claims arising as of July 12, 2019, the effective date of AB 1054, subject to a limit of 40% of the amount of such claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11. The Wildfire Fund is additionally 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.

In the second quarter of 2020, PG&E Corporation and the Utility recorded a current liability of $5.2 billion in “Wildfire fund liability” and $1.5 billion in Other noncurrent liabilities for the present value of unpaid contribution amounts, as well as $6.5 billion in assets for its commitment to make contributions, reduced by amortization, of which $6.0 billion were non-current, called “Wildfire fund asset” in the Condensed Consolidated Balance Sheets. The initial contribution and first annual contribution were paid in the third quarter of 2020. During the three and nine months ended September 30, 2020, the Utility recorded amortization and accretion expense of $120 million and $293 million, respectively. The amortization of the asset, accretion of the liability, and if applicable, impairment of the asset is reflected in “Wildfire fund expense” in the Condensed Consolidated Statements of Income. Expected contributions are discounted to the present value using the 10-year US treasury rate at the date PG&E Corporation and the Utility satisfied all the eligibility requirements to participate in the Wildfire Fund. A useful life of 15 years is being used to amortize the Wildfire Fund asset.

AB 1054 did not specify a period of coverage; therefore, this accounting treatment is subject to significant accounting judgments and estimates. In estimating the period of coverage, PG&E Corporation and the Utility use a Monte Carlo simulation starting with 12 years of historical, publicly available fire-loss data from wildfires caused by electrical equipment. The period of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the useful life. These assumptions along with the other assumptions below create a high degree of uncertainty related to the estimated useful life of the Wildfire Fund. The simulation results in the estimated number and severity of catastrophic fires that could occur in California within the participating electric utilities’ service territories during the term of the Wildfire Fund. Using a 5 year period of historical data, with average annual statewide claims or settlements of approximately $6.5 billion, compared to approximately $2.9 billion for the 12-year historical data, would decrease the amortization period to 6 years. Similarly, a ten percent change to the assumption around current and future mitigation effort effectiveness would increase the amortization period to 17 years assuming greater effectiveness and would decrease the amortization period to 12 years assuming less effectiveness.

Other assumptions used to estimate the useful life include the estimated cost of wildfires caused by other electric utilities, the amount at which wildfire claims would be settled, the likely adjudication of the CPUC in cases of electric utility-caused wildfires, the impacts of climate change, the level of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of other electric utilities. Significant changes in any of these estimates could materially impact the amortization period.

PG&E Corporation and the Utility evaluate all assumptions quarterly, or upon claims being made from the Wildfire Fund for catastrophic wildfires, and the expected life of the Wildfire Fund will be adjusted as required. The Wildfire Fund is available to other participating utilities in California and the amount of claims that a participating utility incurs is not limited to their individual contribution amounts. PG&E Corporation and the Utility will assess the Wildfire Fund asset for impairment in the event that a participating utility's electrical equipment is found to be the substantial cause of a catastrophic wildfire. Timing of any such impairment could lag as the emergence of sufficient cause and claims information can take many quarters and could be limited to public disclosure of the participating electric utility, if ignition were to occur outside the Utility’s service territory. At September 30, 2020, there were no such known events requiring a reduction of the Wildfire Fund asset nor have there been any claims or withdrawals by the participating utilities against the Wildfire Fund.

Recently Adopted Accounting Standards

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. PG&E Corporation and the Utility adopted the ASU on January 1, 2020. The adoption of this ASU did not have a material impact on the 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): Measurement of Credit Losses On Financial Instruments, 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. PG&E Corporation and the Utility adopted the ASU on January 1, 2020.

PG&E Corporation and the Utility have three categories of financial assets in scope, each with their own associated credit risks. In applying the new guidance, PG&E Corporation and the Utility have incorporated forward-looking data in its estimate of credit loss as follows. Trade receivables are represented by customer accounts receivable and have credit exposure risk related to California unemployment rates. Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Lastly, available-for-sale debt securities requires each company to determine if a decline in fair value is below amortized costs basis, or, impaired. Furthermore, if an impairment exists on available-for-sale debt securities, PG&E Corporation and the Utility will examine if there is an intent to sell, if it is more likely than not a requirement to sell prior to recovery, and if a portion of the unrealized loss is a result of credit loss. During the three and nine months ended September 30, 2020, expected credit losses of $33 million and $96 million, respectively, were recorded in Operating and maintenance expense on the Condensed Consolidated Statements of Income for credit losses associated with trade receivables. Of these amounts recorded during the three and nine months ended September 30, 2020, $17 million and $48 million, respectively, were deemed probable of recovery and deferred to the CPPMA.

Reference Rate Reform

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional guidance for a limited period of time to ease the potential burden in accounting for (or recognizing the effects of) reference rate reform on financial reporting. PG&E Corporation and the Utility adopted this ASU on April 1, 2020 and elected the optional amendments for contract modifications prospectively. There was no material impact to PG&E Corporation or the Utility’s Condensed Consolidated Financial Statements resulting from the adoption of this ASU.

Accounting Standards Issued But Not Yet Adopted

Defined Benefit Plans

In August 2018, the FASB issued ASU No. 2018-14, Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20): Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans, which amends the existing guidance relating to the disclosure requirements for Defined Benefit Plans. PG&E Corporation and the Utility are evaluating the impact and will incorporate the new disclosure requirements in the fourth quarter of 2020.

Income Taxes

In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes, which amends the existing guidance to reduce complexity relating to Income Tax disclosures. PG&E Corporation and the Utility plan to adopt this guidance in the first quarter of 2021. PG&E Corporation and the Utility do not anticipate the guidance will have a material impact on their Condensed Consolidated Financial Statements and related disclosures.

Debt

In August 2020, the FASB issued ASU No. 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity, which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity’s own equity. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2022, 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.

NOTE 4: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets and Liabilities

Regulatory Assets

Long-term regulatory assets are comprised of the following:


	Balance at
(in millions)	September 30, 2020		December 31, 2019
Pension benefits (1)	$	1,723	$	1,823
Environmental compliance costs	1,089		1,062
Utility retained generation (2)	194		228
Price risk management	209		124
Unamortized loss, net of gain, on reacquired debt	53		63
Catastrophic event memorandum account (3)	771		656
Wildfire expense memorandum account (4)	419		423
Fire hazard prevention memorandum account (5)	259		259
Fire risk mitigation memorandum account (6)	99		95
Wildfire mitigation plan memorandum account (7)	1,080		558
Deferred income taxes (8)	729		252
Insurance premium costs (9)	588		—
COVID-19 pandemic protection memorandum accounts (10)	53		—
Other	720		523
Total long-term regulatory assets	$	7,986	$	6,066

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

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

(3) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. As of September 30, 2020, $41 million in COVID-19 related costs was recorded to CEMA regulatory assets. Recovery of CEMA costs are subject to CPUC review and approval.

(4) Includes incremental wildfire liability insurance premium costs the CPUC approved for tracking in June 2018 for the period July 26, 2017 through December 31, 2019. Recovery of WEMA costs are subject to CPUC review and approval.

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

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

(7) Includes costs associated with the 2019 Wildfire Mitigation Plan for the period June 5, 2019 through December 31, 2019 and the 2020 Wildfire Mitigation Plan for the period of January 1, 2020 through September 30, 2020. Recovery of WMPMA costs are subject to CPUC review and approval.

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

(9) Represents incremental liability insurance premium costs for the period January 1, 2020 through September 30, 2020. Approval of costs is pending final 2020 GRC decision.

(10)On April 16, 2020, the CPUC passed a resolution that established a COVID-19 Pandemic Protections Memorandum Account (CPPMA) to recover costs associated with customer protections, including higher uncollectible costs related to a moratorium on electric and gas service disconnections for residential and small business customers. The CPPMA applies only to residential and small business customers and was approved on July 27, 2020 with an effective date of March 4, 2020. As of September 30, 2020, the Utility had recorded an aggregate under-collection of $48 million, representing incremental bad debt expense over what was collected in rates for the period the CPPMA is in effect. The remaining $5 million is associated with program costs and higher accounts receivable financing costs. Recovery of CPPMA costs are subject to CPUC review and approval.

Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:


	Balance at
(in millions)	September 30, 2020		December 31, 2019
Cost of removal obligations (1)	$	6,902	$	6,456
Recoveries in excess of AROs (2)	351		393
Public purpose programs (3)	930		817
Employee benefit plans (4)	774		750
Other	1,024		854
Total long-term regulatory liabilities	$	9,981	$	9,270

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

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

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

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

Regulatory Balancing Accounts

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


	Receivable Balance at
(in millions)	September 30, 2020		December 31, 2019
Electric transmission	$	—	$	9
Gas distribution and transmission	385		363
Energy procurement	1,168		901
Public purpose programs	289		209
Other	766		632
Total regulatory balancing accounts receivable	$	2,608	$	2,114


	Payable Balance at
(in millions)	September 30, 2020		December 31, 2019
Electric distribution	$	227	$	31
Electric transmission	237		119
Gas distribution and transmission	65		45
Energy procurement	859		649
Public purpose programs	500		559
Other	438		394
Total regulatory balancing accounts payable	$	2,326	$	1,797

For more information, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K.

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. (“JPM”), as administrative agent, Citibank, N.A., as collateral agent, and the lenders and issuing banks party thereto.

On July 1, 2020, the DIP Facilities were repaid in full and all commitments thereunder were terminated in connection with emergence from Chapter 11.

Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities at September 30, 2020:


(in millions)	Termination Date	Facility Limit			Borrowings Outstanding		Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	July 2023	$	3,500	(1)	$	940	$	852	$	1,708
Utility term loan credit facility	Various(2)	3,000			3,000		—		—
PG&E Corporation revolving credit facility	July 2023	500			—		—		500
Total credit facilities		$	7,000		$	3,940	$	852	$	2,208

(1) Includes a $1.5 billion letter of credit sublimit.

(2) This includes a $1.5 billion term loan credit facility with a termination date of June 2021 and a $1.5 billion term loan credit facility due January 2022.

Utility

On July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Facility”) with JPM, and Citibank, N.A. as co-administrative agents, and Citibank, N.A., as designated agent. The Utility Revolving Credit Agreement has a maturity date three years after the Effective Date, subject to two one-year extensions at the option of the Utility.

Borrowings under the Utility Revolving Credit Facility bear interest based on the Utility’s election of either (1) LIBOR plus an applicable margin of 1.375% to 2.50% based on the Utility’s credit rating or (2) the base rate plus an applicable margin of 0.375% to 1.50% based on the Utility’s credit rating. In addition to interest on outstanding principal under the Utility Revolving Credit Facility, the Utility is required to pay a commitment fee to the lenders in respect of the unutilized commitments thereunder, ranging from 0.25% to 0.50% per annum depending on the Utility’s credit rating. The Utility Revolving Credit Facility has a maximum letter of credit sublimit equal to $1.5 billion. The Utility may also pay customary letter of credit fees based on letters of credit issued under the Utility Revolving Credit Facility.

The Utility’s obligations under the Utility Revolving Credit Facility are secured by the issuance of a first mortgage bond, issued pursuant to the Utility’s mortgage indenture, secured by a first lien on substantially all of the Utility’s real property and certain tangible personal property related to its facilities, subject to certain exceptions, and which rank pari passu with the Utility’s other first mortgage bonds.

The Utility Revolving Credit Facility includes usual and customary provisions for revolving credit agreements of this type, including covenants limiting, with certain exceptions, (1) liens, (2) indebtedness, (3) sale and leaseback transactions, and (4) fundamental changes. In addition, the Utility Revolving Credit Facility requires that the Utility maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 65% as of the end of each fiscal quarter. As of September 30, 2020, the Utility was in compliance with this covenant.

In the event of a default by the Utility under the Utility Revolving Credit Facility, including cross-defaults relating to specified other debt of the Utility or any of its significant subsidiaries in excess of $200 million, the designated agent may, with the consent of the required lenders (or upon the request of the required lenders), declare the amounts outstanding under the Utility Revolving Credit Facility, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Utility Revolving Credit Facility become payable immediately.

The Utility may voluntarily repay outstanding loans under the Utility Revolving Credit Facility at any time without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans. Any voluntary prepayments made by the Utility will not reduce the commitments under the Utility Revolving Credit Facility.

In addition, on July 1, 2020, the Utility obtained a $3.0 billion secured term loan under a term loan credit agreement (the “Utility Term Loan Credit Facility”) with JPM, as administrative agent. The credit facilities under the Utility Term Loan Credit Facility consist of a $1.5 billion 364-day term loan facility (the “Utility 364-Day Term Loan Facility”) and a $1.5 billion 18-month term loan facility (the “Utility 18-Month Term Loan Facility”). The maturity date for the 364-Day Term Loan Facility is June 30, 2021 and the maturity date for the Utility 18-Month Term Loan Facility is January 1, 2022. The Utility borrowed the entire amount of the Utility 364-Day Term Loan Facility and the Utility 18-Month Term Loan Facility on July 1, 2020. The proceeds were used to fund transactions contemplated under the Plan.

Borrowings under the Utility Term Loan Credit Facility bear interest based on the Utility’s election of either (1) LIBOR plus an applicable margin of 2.00% with respect to the Utility 364-Day Term Loan Facility and 2.25% with respect to the Utility 18-Month Term Loan Facility, or (2) the base rate plus an applicable margin of 1.00% with respect to the Utility 364-Day Term Loan Facility and 1.25% with respect to the Utility 18-Month Term Loan Facility.

The Utility’s obligations under the Utility Term Loan Credit Facility are secured by the issuance of first mortgage bonds, issued pursuant to the Utility’s mortgage indenture, secured by a first lien on substantially all of the Utility’s real property and certain tangible personal property related to its facilities, subject to certain exceptions, and which rank pari passu with the Utility’s other first mortgage bonds.

The Utility Term Loan Credit Facility includes usual and customary provisions for term loan agreements of this type, including covenants limiting, with certain exceptions, (1) liens, (2) indebtedness, (3) sale and leaseback transactions, (4) fundamental changes, (5) entering into swap agreements and (6) modifications to the Utility’s mortgage indenture. In addition, the Utility Term Loan Credit Facility will require that the Utility maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 65% as of the end of each fiscal quarter. As of September 30, 2020, the Utility was in compliance with this covenant.

In the event of a default by the Utility under the Utility Term Loan Credit Facility, including cross-defaults relating to specified other debt of the Utility or any of its significant subsidiaries in excess of $200 million, the administrative agent may, with the consent of the required lenders (or upon the request of the required lenders, shall), declare the amounts outstanding under the Utility Term Loan Credit Facility, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Utility Term Loan Credit Facility become payable immediately.

The Utility is required to prepay outstanding term loans under the Utility Term Loan Credit Facility (with all outstanding term loans made under the Utility 364-Day Term Loan Facility being paid first), subject to certain exceptions, with 100% of the net cash proceeds of certain securitization transactions. The Utility may voluntarily repay outstanding loans under the Utility Term Loan Credit Facility at any time without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans.

PG&E Corporation

On July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the “Corporation Revolving Credit Facility”) with JPM, as administrative agent and collateral agent. The Corporation Revolving Credit Facility has a maturity date three years after the Effective Date, subject to two one-year extensions at the option of PG&E Corporation. The proceeds from the loans under the Corporation Revolving Credit Facility will be used to finance working capital needs, capital expenditures and other general corporate purposes of PG&E Corporation and its subsidiaries.

Borrowings under the Corporation Revolving Credit Facility bear interest based on PG&E Corporation’s election of either (1) LIBOR plus an applicable margin of 3.00% to 4.25% based on PG&E Corporation’s credit rating or (2) the base rate plus an applicable margin of 2.00% to 3.25% based on PG&E Corporation’s credit rating. In addition to interest on outstanding principal under the Corporation Revolving Credit Facility, PG&E Corporation is required to pay a commitment fee to the lenders in respect of the unutilized commitments thereunder, ranging from 0.50% to 0.75% per annum depending on PG&E Corporation’s credit rating.

PG&E Corporation’s obligations under the Corporation Revolving Credit Facility are secured by a pledge of PG&E Corporation’s ownership interest in 100% of the shares of common stock of the Utility.

The Corporation Revolving Credit Facility includes usual and customary provisions for revolving credit agreements of this type, including covenants limiting, with certain exceptions, (1) liens, (2) indebtedness, (3) sale and leaseback transactions, (4) investments, (5) dispositions, (6) changes in the nature of business, (7) transactions with affiliates, (8) burdensome agreements, (9) restricted payments, (10) fundamental changes, (11) use of proceeds, (12) entering into swap agreements and (13) the ability to dispose of common stock of the Utility. In addition, the Corporation Revolving Credit Facility will require that PG&E Corporation (1) maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 70% as of the end of each fiscal quarter and (2) if revolving loans are outstanding as of the end of a fiscal quarter, a ratio of adjusted cash to fixed charges, as of the end of such fiscal quarter, of at least 150% prior to the date that PG&E Corporation first declares a cash dividend on its common stock and at least 100% thereafter.

In the event of a default by PG&E Corporation under the Corporation Revolving Credit Facility, including cross-defaults relating to specified other debt of PG&E Corporation or any of its significant subsidiaries in excess of $200 million, the administrative agent may, with the consent of the required lenders (or upon the request of the required lenders, shall), declare the amounts outstanding under the Corporation Revolving Credit Facility, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Corporation Revolving Credit Facility become payable immediately.

PG&E Corporation may voluntarily repay outstanding loans under the Corporation Revolving Credit Facility at any time without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans. Any voluntary repayments made by PG&E Corporation will not reduce the commitments under the Corporation Revolving Credit Facility.

On the Effective Date, PG&E Corporation repaid and terminated (i) $300 million of outstanding borrowings under the Second Amended and Restated Credit Agreement, dated as of April 27, 2015, among PG&E Corporation, as borrower, the several lenders party thereto and Bank of America, N.A., as administrative agent and (ii) $350 million of borrowings, plus interest, fees and other expenses arising under or in connection with the Term Loan Agreement, dated as of April 16, 2018, among PG&E Corporation, as borrower, the several lenders party thereto and Mizuho Bank Ltd., as administrative agent.

Accounts Receivable Financing

On October 5, 2020, the Utility, in its individual capacity and in its capacity as initial servicer, entered into an accounts receivable securitization program (the “Receivables Securitization Program”), providing for the sale of a portion of the Utility's accounts receivable to PG&E AR Facility, LLC (the “SPV”), a limited liability company wholly owned by the Utility. Pursuant to the Receivables Securitization Program, the Utility will sell certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables and certain other related rights to the SPV, which, in turn, will obtain loans secured by the receivables from financial institutions (the “Lenders”). The Utility has pledged to the Lenders 100% of the equity interests in the SPV as security for the repayment of the loans. The aggregate principal amount of the loans made by the Lenders cannot exceed $1 billion outstanding at any time.

The loans under the Receivables Securitization Program will bear interest based on a spread over LIBOR dependent on the tranche period thereto and any breakage fees accrued. The receivables financing agreement contains customary LIBOR benchmark replacement language giving the administrative agent, with consent from the SPV as to the successor rate, the right to determine such successor rate. The Receivables Securitization Program contains certain customary representations and warranties and affirmative and negative covenants, including as to the eligibility of the receivables being sold by the Utility and securing the loans made by the Lenders, as well as customary reserve requirements, Receivables Securitization Program termination events, and servicer defaults. The Receivables Securitization Program termination events permit the Lenders to terminate the agreement upon the occurrence of certain specified events, including failure by the SPV to pay amounts when due, certain defaults on indebtedness under the Utility’s credit facility, certain judgments, a change of control, certain events negatively affecting the overall credit quality of transferred receivables and bankruptcy and insolvency events.

The Receivables Securitization Program is scheduled to terminate on October 5, 2022, unless extended or earlier terminated, at which time no further advances will be available and the obligations thereunder must be repaid in full no later than (i) the date that is 180 days following such date or (ii) such earlier date on which the loans under the program become due and payable.

The Utility closed the Receivables Securitization Program on October 5, 2020. As of October 27, 2020, the Utility has obtained $1 billion in loans under the Receivables Securitization Program and the proceeds were primarily used to reduce borrowings outstanding on the Utility Revolving Credit Facility. In general, the proceeds from the sale of the accounts receivable will be used by the SPV to pay the purchase price for accounts receivables it acquires from the Utility and may be used to fund capital expenditures, repay borrowings on the Utility Revolving Credit Facility, satisfy maturing debt obligations, as well as fund working capital needs and other approved uses.

Although PG&E AR Facility, LLC is a wholly owned consolidated subsidiary of the Utility, PG&E AR Facility, LLC is legally separate from the Utility. The assets of PG&E AR Facility, LLC (including the accounts receivables) are not available to creditors of the Utility or PG&E Corporation, and the accounts receivables are not legally assets of the Utility or PG&E Corporation. The Receivables Securitization Program will be accounted for as a secured financing. When amounts are received from the Lenders, the pledged receivables and the corresponding debt will be included in Accounts receivable and Short-term borrowings, respectively, on the Condensed Consolidated Balance Sheets.

Long-Term Debt

Utility

On June 19, 2020, the Utility completed the sale of (i) $500 million aggregate principal amount of Floating Rate First Mortgage Bonds due June 16, 2022, (ii) $2.5 billion aggregate principal amount of 1.75% First Mortgage Bonds due June 16, 2022, (iii) $1 billion aggregate principal amount of 2.10% First Mortgage Bonds due August 1, 2027, (iv) $2 billion aggregate principal amount of 2.50% First Mortgage Bonds due February 1, 2031, (v) $1 billion aggregate principal amount of 3.30% First Mortgage Bonds due August 1, 2040, and (vi) $1.925 billion aggregate principal amount of 3.50% First Mortgage Bonds due August 1, 2050 (collectively, the “Mortgage Bonds”). The proceeds of the Mortgage Bonds were deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and among the Escrow Agent and the Utility. On July 1, 2020, the net proceeds were released from escrow and, together with the net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of the Utility and PG&E Corporation in accordance with the terms and conditions contained in the Plan.

On the Effective Date, pursuant to the Plan, the Utility issued approximately $11.9 billion of its first mortgage bonds (the “New Mortgage Bonds”) in satisfaction of certain of its pre-petition senior unsecured debt, as described in the table below.

On the Effective Date, pursuant to the Plan, the Utility reinstated approximately $9.6 billion aggregate principal amount of the Utility Reinstated Senior Notes. On the Effective Date, each series of the Utility Reinstated Senior Notes was collateralized by the Utility’s delivery of a first mortgage bond in a corresponding principal amount to the applicable trustee for the benefit of the holders of the Utility Reinstated Senior Notes.

The Mortgage Bonds, the New Mortgage Bonds and the Utility Reinstated Senior Notes are secured by a first lien, subject to permitted liens, on substantially all of the Utility’s real property and certain tangible property related to its facilities. The Mortgage Bonds, the New Mortgage Bonds and the Utility Reinstated Senior Notes are the Utility’s senior obligations and rank equally in right of payment with the Utility’s other existing or future first mortgage bonds issued under the Utility’s mortgage indenture.

On the Effective Date, by operation of the Plan, all outstanding obligations under the Utility Short-Term Senior Notes, the Utility Long-Term Senior Notes and the Utility Funded Debt were cancelled and the applicable agreements governing such obligations were terminated.

In addition, on July 1, 2020, the Utility obtained a $1.5 billion 18-month secured term loan under a term loan credit agreement. For more information, see “Credit Facilities” discussion above.

PG&E Corporation

On June 23, 2020, PG&E Corporation obtained a $2.75 billion secured term loan (the “Term Loan”) under a term loan credit agreement (the “Term Loan Agreement”) with JPM, and other lenders from time to time party thereto (collectively, the “Lenders”), JPM, as Administrative Agent and as Collateral Agent. The proceeds of the Term Loan were deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and among the Collateral Agent, the Escrow Agent, the Administrative Agent and PG&E Corporation and subsequently released from escrow on the Effective Date pursuant to the Plan.

In accordance with the Term Loan Agreement, PG&E Corporation is required to repay the principal amount outstanding on the Term Loan by $6.875 million on the last day of each quarter. The Term Loan matures on June 23, 2025, unless extended by PG&E Corporation pursuant to the terms of the Term Loan Agreement. The Term Loan bears interest based, at PG&E Corporation’s election, on (1) LIBOR (but in no event less than 1.0%) plus an applicable margin or (2) ABR (but in no event less than 2.0%) plus an applicable margin. ABR will equal the highest of the following: the prime rate, 0.5% above the overnight federal funds rate, and the one-month LIBOR plus 1.0%. The applicable margin for LIBOR loans is 4.5% and the applicable margin for ABR loans is 3.5%. PG&E Corporation may prepay the Term Loan in whole, at any time, and in part, from time to time, without premium or penalty, other than customary “breakage” costs with respect to eurodollar rate loans; provided, however, that any voluntary prepayment, refinancing or repricing of the Term Loan in connection with certain repricing transactions that occur on or prior to the first anniversary of the Effective Date shall be subject to a prepayment premium of 1.0% of the principal amount of the term loans so prepaid, refinanced or repriced.

The Term Loan Agreement includes usual and customary covenants for loan agreements of this type, including covenants limiting: (1) liens, (2) mergers, (3) sales of all or substantially all of PG&E Corporation’s assets, and (4) sale and leaseback transactions. In addition, the Term Loan Agreement requires that PG&E Corporation maintain ownership, either directly or indirectly, through one or more subsidiaries, of at least 100% of the outstanding common stock of the Utility.

In the event of a default by PG&E Corporation under the Term Loan Agreement, including cross-defaults relating to specified other debt of PG&E Corporation or any of its significant subsidiaries in excess of $200 million, the Administrative Agent may, with the consent of the required Lenders (or upon the request of the required Lenders, shall), declare the amounts outstanding under the Term Loan Agreement, including all accrued interest, payable immediately. For events of default relating to insolvency, bankruptcy or receivership, the amounts outstanding under the Term Loan Agreement become payable immediately.

On the Effective Date, the obligations under the Term Loan Agreement became secured by a pledge of PG&E Corporation’s ownership interest in 100% of the shares of common stock of the Utility. On July 1, 2020, the net proceeds from the Term Loan were released from escrow and were used to fund, in part, the transactions contemplated under the Plan.

Additionally, on June 23, 2020, PG&E Corporation completed the sale of (i) $1.0 billion aggregate principal amount of 5.00% Senior Secured Notes due July 1, 2028 (the “2028 Notes”) and (ii) $1.0 billion aggregate principal amount of 5.25% Senior Secured Notes due July 1, 2030 (the “2030 Notes,” and together with the 2028 Notes, the “Notes”). The proceeds of the Notes were deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and among the Escrow Agent and PG&E Corporation. Prior to July 1, 2023, in the case of the 2028 Notes, and prior to July 1, 2025, in the case of the 2030 Notes, (i) PG&E Corporation may redeem all or part of the Notes of the applicable series, on any one or more occasions at a redemption price equal to 100% of the principal amount of Notes of such series to be redeemed, plus a “make-whole” premium, plus accrued and unpaid interest, if any, to, but not including, the redemption date or (ii) PG&E Corporation may redeem up to 40% of the aggregate principal amount of the Notes of the applicable series on any one or more occasions at certain specified redemption prices with the net cash proceeds from certain equity offerings. On or after July 1, 2023, in the case of the 2028 Notes, and July 1, 2025, in the case of the 2030 Notes, PG&E Corporation may redeem the Notes of a series at certain specified redemption prices, plus accrued and unpaid interest thereon, if any, to but not including, the applicable redemption date.

On July 1, 2020, the net proceeds from the sale of the Notes were released from escrow and, together with the net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of the Corporation and the Utility in accordance with the terms and conditions contained in the Plan. The Notes are secured by a pledge of PG&E Corporation’s ownership interest in 100% of the shares of common stock of the Utility.

The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:


		Balance at
(in millions)	Contractual Interest Rates (3)	September 30, 2020		December 31, 2019		Treatment under Plan on the Effective Date (1)
Pre-Petition Debt (2)
PG&E Corporation
Borrowings under Pre-Petition Credit Facility
PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022	variable rate (4)	$	—	$	300	Repaid in cash (13)
Other borrowings
Term Loan - Stated Maturity: 2020	variable rate (5)	—		350		Repaid in cash (12)
Total PG&E Corporation Pre-Petition Long-Term Debt		—		650

Utility
Senior Notes - Stated Maturity:
2020 through 2022	2.45% to 4.25%	—		1,750		Exchanged (14)
2023 through 2028	2.95% to 4.65%	—		5,025		Reinstated (15)
2034 through 2040	5.40% to 6.35%	—		5,700		Exchanged (16)
2041 through 2042	3.75% to 4.50%	—		1,000		Reinstated (15)
2043	5.13%	—		500		Exchanged (16)
2043 through 2047	3.95% to 4.75%	—		3,550		Reinstated (15)
Total Pre-Petition Senior Notes		—		17,525
Pollution Control Bonds - Stated Maturity:
Series 2008 F and 2010 E, due 2026	1.75%	—		100		Repaid in cash (13)
Series 2009 A-B, due 2026	variable rate (6)	—		149		Exchanged (17)
Series 1996 C, E, F, 1997 B due 2026	variable rate (7)	—		614		Exchanged (17)
Total Pre-Petition Pollution Control Bonds		—		863
Borrowings under Pre-Petition Credit Facilities
Utility Revolving Credit Facilities - Stated Maturity: 2022	variable rate (8)	—		2,888		Exchanged (17)
Other borrowings:
Term Loan - Stated Maturity: 2019	variable rate (9)	—		250		Exchanged (17)
Total Borrowings under Pre-Petition Credit Facility		—		3,138
Total Utility Pre-Petition Debt		—		21,526
Total PG&E Corporation Consolidated Pre-Petition Debt		$	—	$	22,176

New Long-Term Debt
PG&E Corporation
Term Loan - Stated Maturity: 2025	variable rate (10)	$	2,743	$	—
Senior Secured Notes due 2028	5.00%	1,000		—
Senior Secured Notes due 2030	5.25%	1,000		—
Unamortized discount, net of premium and debt issuance costs		(89)		—
Total PG&E Corporation New Long-Term Debt		4,654		—


Utility
Pre-Petition Senior Notes Reinstated as First Mortgage Bonds - Stated Maturity:
2023 through 2028	2.95% to 4.65%	5,025		—
2041 through 2042	3.75% to 4.50%	1,000		—
2043 through 2047	3.95% to 4.75%	3,550		—
Unamortized discount, net of premium and debt issuance costs		—		—
Total Utility Reinstated New Long-Term Debt		9,575		—
Pre-Petition Debt Exchanged for First Mortgage Bonds - Stated Maturity:
2025	3.45%	875		—
2026	3.15%	1,951		—
2028	3.75%	875		—
2030	4.55%	3,100		—
2040	4.50%	1,951		—
2050	4.95%	3,100		—
Unamortized discount, net of premium and debt issuance costs		(101)		—
Total Utility Exchanged New Long-Term Debt		11,751		—
New First Mortgage Bonds - Stated Maturity:
2022	variable rate (11)	500		—
2022	1.75%	2,500		—
2027	2.10%	1,000		—
2031	2.50%	2,000		—
2040	3.30%	1,000		—
2050	3.50%	1,925		—
Unamortized discount, net of premium and debt issuance costs		(87)		—
Total Utility New First Mortgage Bonds		8,838		—
Utility 18-Month Term Loan	variable rate (12)	1,500		—
Unamortized discount, net of premium and debt issuance costs		(7)		—
Total Utility New Long-Term Debt		31,657		—
Total PG&E Corporation Consolidated New Long-Term Debt		$	36,311	$	—

(1) The treatments of pre-petition debt under the Plan, as described in this column, relate only to the treatment of principal amounts and not pre-petition or post-petition interest. See “Plan of Reorganization and Restructuring Support Agreements” in Note 2.

(2) As of December 31, 2019, pre-petition debt was reported at the amounts expected to be allowed by the Bankruptcy Court.

(3) The contractual interest rates for pre-petition debt and new debt are presented as of December 31, 2019 and September 30, 2020, respectively.

(4) At December 31, 2019, the contractual LIBOR-based interest rate on loans was 3.24%.

(5) At December 31, 2019, the contractual LIBOR-based interest rate on the term loan was 2.96%.

(6) At December 31, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds was 7.95%.

(7) At December 31, 2019, the contractual interest rate on the letter of credit facilities supporting these bonds ranged from 7.95% to 8.08%.

(8) At December 31, 2019, the contractual LIBOR-based interest rate on the loans was 3.04%.

(9) At December 31, 2019, the contractual LIBOR-based interest rate on the term loan was 2.36%.

(10) At September 30, 2020, the contractual LIBOR-based interest rate on the loans was 5.50%.

(11) At September 30, 2020, the contractual LIBOR-based interest rate on the first mortgage bonds was 1.72%.

(12) At September 30, 2020, the contractual LIBOR-based interest rate on the first mortgage bonds was 2.44%.

(13) In accordance with the Plan, these borrowings were repaid in cash on July 1, 2020.

(14) In accordance with the Plan, on July 1, 2020, the Utility issued $875 million aggregate principal amount of 3.45% first mortgage bonds due 2025 and $875 million aggregate principal amount of 3.75% first mortgage bonds due 2028, in satisfaction of these Senior Notes. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above.

(15) In accordance with the Plan, these Senior Notes were reinstated (and secured by First Mortgage Bonds) on July 1, 2020. See “Pre-Petition Senior Notes Reinstated (and secured by First Mortgage Bonds)” in the table above.

(16) In accordance with the Plan, on July 1, 2020, the Utility issued $3.1 billion aggregate principal amount of 4.55% first mortgage bonds due 2030 and $3.1 billion aggregate principal amount of 4.95% first mortgage bonds due 2050, in satisfaction of these Senior Notes. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above.

(17) In accordance with the Plan, on July 1, 2020, the Utility issued $1.95 billion aggregate principal amount of 3.15% first mortgage bonds due 2026 and $1.95 billion aggregate principal amount of 4.50% first mortgage bonds due 2040, in satisfaction of these pre-petition liabilities. See “Pre-Petition Debt Exchanged for First Mortgage Bonds” in the table above.

NOTE 6: EQUITY

Increase in Authorized Capitalization

On June 22, 2020, PG&E Corporation filed the Amended Articles with the Secretary of State of California which increased the authorized number of shares of common stock to 3.6 billion and the authorized number of shares of preferred stock to 400 million.

Plan Equity Financings

In connection with emergence from Chapter 11, in July 2020, PG&E Corporation raised an aggregate of $9.0 billion of gross proceeds through the issuance of common stock and other equity-linked instruments as described below.

PG&E Corporation Investment Agreement

On June 7, 2020, PG&E Corporation entered into an Investment Agreement (the “Investment Agreement”) with certain investors (the “Investors”) relating to the issuance and sale to the Investors of an aggregate of $3.25 billion of PG&E Corporation’s common stock. Per the Investment Agreement, the price per share was equal to $9.50 per share, which was the public equity offering price in the Common Stock Offering (as defined below in “Equity Offerings”).

On July 1, 2020, pursuant to the terms of the Investment Agreement, PG&E Corporation issued to the Investors 342.1 million shares of common stock. The Investors and their affiliates have certain customary registration rights with respect to the Shares held by such Investor pursuant to the terms of the Investment Agreement.

Equity Offerings

On June 25, 2020, PG&E Corporation priced (i) an offering of 423.4 million shares of its common stock (the “Common Stock Offering”), and (ii) a concurrent offering of 14.5 million of its equity units (the “Equity Units,” and such offering the “Equity Units Offering”), for total net proceeds to PG&E Corporation, after deducting the underwriting discounts and before estimated offering expenses payable by the PG&E Corporation, of $3.97 billion and $1.19 billion, respectively.

On June 25, 2020, in connection with the Common Stock Offering, the Corporation entered into an underwriting agreement (the “Common Stock Underwriting Agreement”) with Goldman Sachs & Co. LLC and J.P. Morgan Securities LLC, as representatives of several underwriters named in the Common Stock Underwriting Agreement (the “Common Stock Underwriters”), pursuant to which the Corporation agreed to issue and sell 423.4 million shares of its common stock to the Common Stock Underwriters. In addition, on June 25, 2020, the Corporation entered into an underwriting agreement (the “Equity Units Underwriting Agreement”) with Goldman Sachs & Co. LLC and J.P. Morgan Securities LLC, as representatives of the several underwriters named in the Equity Units Underwriting Agreement (the “Equity Units Underwriters”), pursuant to which PG&E Corporation agreed to issue and sell 14.5 million prepaid forward stock purchase contracts (the “Purchase Contracts”) to the Equity Underwriters in order for the Equity Units Underwriters to sell 14.5 million Equity Units.

In connection with the Common Stock Offering and pursuant to the Common Stock Underwriting Agreement, PG&E Corporation granted the underwriters a 30-day over-allotment option to purchase up to an additional 42.3 million shares of common stock. In addition, in connection with the Equity Units Offering and pursuant to the Equity Units Underwriting Agreement, the Corporation also granted the underwriters a 30-day over-allotment option to purchase up to an additional 1.45 million Purchase Contracts to be used by the Equity Units Underwriters to create up to an additional 1.45 million Equity Units (together with the 42.3 million shares of common stock, the “Option Securities”).

The Common Stock Offering and the Equity Units Offering closed on July 1, 2020, and PG&E Corporation issued and sold a total of 423.4 million shares of its common stock and 14.5 million Purchase Contracts for total net proceeds of $5.2 billion. On July 24, 2020, the Equity Units Underwriters exercised in full, the over-allotment option in the Equity Units Underwriting Agreement and on August 3, 2020, PG&E Corporation issued and sold 1.45 million Equity Units to the Equity Units Underwriters (the “Additional Units Issuance”). The prepaid forward stock purchase contract portion of the Equity Units issued in the Equity Units Offering and the Additional Units Issuance represents the right of the unitholders to receive, on the settlement date, between 125 million and 153 million shares, and between 12.5 million and 15.3 million shares, respectively, of PG&E Corporation common stock, based on the value of PG&E Corporation common stock over a measurement period specified in the purchase contracts and subject to certain adjustments as provided herein. The settlement date of the purchase contract is August 16, 2023, subject to acceleration or postponement as provided in the purchase contracts. The Common Stock Underwriters did not exercise their option to purchase any additional shares of common stock.

PG&E Corporation applied accounting standards applicable to prepaid forward contracts to purchase common stock in order to determine the proper balance sheet classification for the Equity Units issued and sold during the three months ended, September 30, 2020. The Equity Units are considered a range forward contract, in that the settlement of common stock shares is based on a range of potential settlement outcomes. PG&E Corporation used various inputs, including stock price volatility, and determined that the potential outcomes are predominantly fixed share settlements. As such, PG&E Corporation does not view the Equity Units as an obligation to issue a variable number of shares and has concluded that the Equity Units meet all conditions for equity classification and do not meet any of the other conditions that would result in asset or liability classification. The Equity Units issued and sold are classified as Common stock on PG&E Corporation’s Condensed Consolidated Balance Sheet.

Equity Backstop Commitments and Forward Stock Purchase Agreements

See “Equity Financing” in Note 2 above for discussion of the equity backstop commitments which resulted in total net proceeds of $523 million (of which $120.5 million were returned to the Backstop Parties pursuant to the Forward Stock Purchase Agreements, as described below).

In connection with the Additional Units Issuance and pursuant to the terms of the Forward Stock Purchase Agreements, on August 3, 2020, PG&E Corporation (i) redeemed a portion of the rights under the Forward Stock Purchase Agreements to receive shares of Common Stock and returned approximately $120.5 million to the Backstop Parties and (ii) issued and delivered to the Backstop Parties 42.3 million shares of Common Stock, representing the unredeemed portion of the Aggregate Greenshoe Backstop Purchase Amount divided by the Settlement Price (without any issuance in respect of fractional shares).

Equity Issuances to the Fire Victim Trust

On the Effective Date, pursuant to the Plan, the Utility entered into an assignment agreement with the Fire Victim Trust, pursuant to which the Utility transferred to the Fire Victim Trust 477 million shares of common stock of PG&E Corporation. As a result of the Equity Units Underwriters exercising their option to purchase 1.45 million additional Equity Units, on August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the assignment agreement with the Fire Victim Trust.

Contribution to the Utility Pursuant to the Plan

On the Effective Date, PG&E Corporation made an equity contribution of $12.9 billion in cash, along with the Fire Victim Trust Shares, to the Utility, which used the funds and shares to satisfy and discharge certain liabilities of PG&E Corporation and the Utility under the Plan and transferred the Fire Victim Trust Shares to the Fire Victim Trust as described above. PG&E Corporation’s cash equity contribution was funded by proceeds from the financing transactions described herein.

Ownership Restrictions in PG&E Corporation’s Amended Articles

Under Section 382 of the Internal Revenue Code, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations (which could limit PG&E Corporation or the Utility’s ability to use these deferred tax assets to offset taxable income). In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally 5% shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s ownership of PG&E Corporation’s equity securities to more than 4.75% prior to the Restriction Release Date without approval by the Board of Directors. The calculation of the percentage ownership may differ depending on whether the Fire Victim Trust is treated as a qualified settlement trust or grantor trust.

In 2019, $6.75 billion of the liability to be paid to the Fire Victim Trust in PG&E Corporation’s common stock was accrued by the Utility. Because the corresponding tax deduction generally occurs no earlier than payment, the Utility established a deferred tax asset for the accrual in 2019. Because of the price of the stock on the date of transfer, the shares transferred to the Fire Victim Trust were valued at $4.53 billion, $2.22 billion less than the $6.75 billion that had been accrued as a liability in the Condensed Consolidated Financial Statements as of June 30, 2020. Therefore, in the quarter ended June 30, 2020, the Utility recorded a charge of $619 million to adjust the measurement of the deferred tax asset to reflect the tax-effected difference between the accrual of $6.75 billion and the tax deduction of $4.53 billion for the transfer of PG&E Corporation’s shares to the Fire Victim Trust. On July 1, 2020, the Utility paid to the Fire Victim Trust 477 million shares of PG&E Corporation’s common stock.

In addition, this deferred tax asset reflects PG&E Corporation’s conclusion as of September 30, 2020 that it is more likely than not that the Fire Victim Trust will be treated as a “qualified settlement fund” for U.S. federal income tax purposes, in which case the corresponding tax deduction will have occurred at the time the PG&E Corporation common stock was transferred to the Fire Victim Trust. PG&E Corporation believes that it may be beneficial to elect to treat the Fire Victim Trust as a “grantor trust,” but only if PG&E Corporation receives favorable determinations from the IRS regarding certain aspects of such election. If PG&E Corporation makes a “grantor trust” election for the Fire Victim Trust, the Utility’s tax deduction will occur instead at the time the Fire Victim Trust pays the fire victims and will be based on the price at which the Fire Victim Trust sells the shares. In this case, the accounting treatment will require a re-evaluation under applicable accounting guidance of the remaining deferred tax asset and could result in a further impairment thereof or other material impact on the Condensed Consolidated Financial Statements. Additionally, the value of the deduction may be materially different than the value of the deduction if the Fire Victim Trust is treated as a “qualified settlement fund.”

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.

On April 3, 2019, the court overseeing the Utility’s probation issued an order imposing new conditions of probation, including forgoing issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements” under applicable law and the Utility’s Wildfire Mitigation Plan.

On March 20, 2020, PG&E Corporation and the Utility filed a Case Resolution Contingency Process Motion with the Bankruptcy Court that includes a dividend restriction for PG&E Corporation. According to the dividend restriction, PG&E Corporation “will not pay common dividends until it has recognized $6.2 billion in non-GAAP core earnings following the Effective Date” of the Plan. The Bankruptcy Court entered the order approving the motion on April 9, 2020.

In addition, the Corporation Revolving Credit Agreement requires that PG&E Corporation (1) maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 70% as of the end of each fiscal quarter and (2) if revolving loans are outstanding as of the end of a fiscal quarter, a ratio of adjusted cash to fixed charges, as of the end of such fiscal quarter, of at least 150% prior to the date that PG&E Corporation first declares a cash dividend on its common stock and at least 100% thereafter.

Under the Utility’s Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility’s preferred stock have been paid. The Utility’s preferred stock is cumulative and any dividends in arrears must be paid before the Utility may pay any common stock dividends. Additionally, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on average. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility’s exit from Chapter 11.

Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of the Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant. As of September 30, 2020, it is uncertain when PG&E Corporation and the Utility will commence the payment of dividends on their common stock and when the Utility will commence the payment of dividends on its preferred stock.

Miscellaneous

On July 23, 2020, PG&E Corporation sent a notice of termination to the managers of the Amended and Restated Equity Distribution Agreement, dated as of February 17, 2017, effectively terminating the agreement on that date. As of the termination date for this agreement, no amounts were outstanding which required repayment.

NOTE 7: EARNINGS PER SHARE

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


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions, except per share amounts)	2020		2019		2020		2019
Income (Loss) attributable to common shareholders	$	83	$	(1,619)	$	(1,518)	$	(4,039)
Weighted average common shares outstanding, basic	1,967		529		1,012		528
Add incremental shares from assumed conversions:
Employee share-based compensation	5		—		—		—
Equity Units	168		—		—		—
Weighted average common shares outstanding, diluted	2,140		529		1,012		528
Total Income (loss) per common share, diluted	$	0.04	$	(3.06)	$	(1.50)	$	(7.65)

All potentially dilutive securities were excluded from the calculation of outstanding common shares on a diluted basis in periods where PG&E Corporation has incurred a net loss.

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.

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

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

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

Volume of Derivative Activity

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


		Contract Volume at
Underlying Product	Instruments	September 30, 2020	December 31, 2019
Natural Gas (1) (MMBtus (2))	Forwards, Futures and Swaps	159,168,216	131,896,159
	Options	43,210,000	14,720,000
Electricity (Megawatt-hours)	Forwards, Futures and Swaps	9,925,993	18,675,852
	Options	584,800	—
	Congestion Revenue Rights (3)	275,838,390	308,467,999

(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.

(2) Million British Thermal Units.

(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

Presentation of Derivative Instruments in the Financial Statements

At September 30, 2020, 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	$	51	$	(4)	$	50	$	97
Other noncurrent assets – other	118		—		—		118
Current liabilities – other	(37)		4		—		(33)
Noncurrent liabilities – other	(209)		—		—		(209)
Total commodity risk	$	(77)	$	—	$	50	$	(27)

At December 31, 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	$	36	$	(6)	$	4	$	34
Other noncurrent assets – other	130		(6)		—		124
Current liabilities – other	(31)		6		2		(23)
Noncurrent liabilities – other	(130)		6		—		(124)
Total commodity risk	$	5	$	—	$	6	$	11

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. Upon emergence from Chapter 11, multiple credit agencies continue to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of September 30, 2020, the Utility satisfied or has otherwise addressed 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.

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


	Fair Value Measurements
	September 30, 2020
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	446	$	—	$	—	$	—	$	446
Nuclear decommissioning trusts
Short-term investments	12		—		—		—		12
Global equity securities	2,222		—		—		—		2,222
Fixed-income securities	856		791		—		—		1,647
Assets measured at NAV	—		—		—		—		23
Total nuclear decommissioning trusts (2)	3,090		791		—		—		3,904
Price risk management instruments (Note 8)
Electricity	—		13		142		41		196
Gas	—		14		—		5		19
Total price risk management instruments	—		27		142		46		215
Rabbi trusts
Fixed-income securities	—		105		—		—		105
Life insurance contracts	—		78		—		—		78
Total rabbi trusts	—		183		—		—		183
Long-term disability trust
Short-term investments	5		—		—		—		5
Assets measured at NAV	—		—		—		—		144
Total long-term disability trust	5		—		—		—		149
TOTAL ASSETS	$	3,541	$	1001	$	142	$	46	$	4,897
Liabilities:
Price risk management instruments (Note 8)
Electricity	—		4		239		(3)		240
Gas	—		3		—		(1)		2
TOTAL LIABILITIES	$	—	$	7	$	239	$	(4)	$	242

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

(2) Represents amount before deducting $586 million, primarily related to deferred taxes on appreciation of investment value.


	Fair Value Measurements
	December 31, 2019
(in millions)	Level 1		Level 2		Level 3		Netting (1)		Total
Assets:
Short-term investments	$	1,323	$	—	$	—	$	—	$	1,323
Nuclear decommissioning trusts
Short-term investments	6		—		—		—		6
Global equity securities	2,086		—		—		—		2,086
Fixed-income securities	862		728		—		—		1,590
Assets measured at NAV	—		—		—		—		21
Total nuclear decommissioning trusts (2)	2,954		728		—		—		3,703
Price risk management instruments (Note 8)
Electricity	—		2		161		(11)		152
Gas	—		3		—		3		6
Total price risk management instruments	—		5		161		(8)		158
Rabbi trusts
Fixed-income securities	—		100		—		—		100
Life insurance contracts	—		73		—		—		73
Total rabbi trusts	—		173		—		—		173
Long-term disability trust
Short-term investments	10		—		—		—		10
Assets measured at NAV	—		—		—		—		156
Total long-term disability trust	10		—		—		—		166
TOTAL ASSETS	$	4,287	$	906	$	161	$	(8)	$	5,523
Liabilities:
Price risk management instruments (Note 8)
Electricity	$	1	$	2	$	156	$	(13)	$	146
Gas	—		2		—		(1)		1
TOTAL LIABILITIES	$	1	$	4	$	156	$	(14)	$	147

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

(2) Represents amount before deducting $530 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. There were no material transfers between any levels for the three and nine months ended September 30, 2020 and 2019.

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 as 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 Uncertainty Analysis

Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.

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

Fair Value at

(in millions)

September 30, 2020

Fair Value Measurement

Assets

Liabilities

Valuation
Technique

Unobservable
Input

Range(1) /Weighted-Average Price (2)

Congestion revenue rights

131

Market approach

CRR auction prices

$(20.20) - $20.20 / 0.27

Power purchase agreements

182

Discounted cash flow

Forward prices

$11.92 - $97.45 / 33.25

(1) Represents price per megawatt-hour.

(2) Unobservable inputs were weighted by the relative fair value of the instruments.

Fair Value at

(in millions)

December 31, 2019

Fair Value Measurement

Assets

Liabilities

Valuation Technique

Unobservable Input

Range (1)/Weighted-Average Price (2)

Congestion revenue rights

140

Market approach

CRR auction prices

$(20.20) - $20.20 / 0.28

Power purchase agreements

112

Discounted cash flow

Forward prices

$11.77 - $59.38 / 33.62

(1) Represents price per megawatt-hour.

(2) Unobservable inputs were weighted by the relative fair value of the instruments.

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 instruments for the three and nine months ended September 30, 2020 and 2019:


	Price Risk Management Instruments
(in millions)	2020		2019
Asset (liability) balance as of July 1	$	(66)	$	109
Net realized and unrealized losses:
Included in regulatory assets and liabilities or balancing accounts (1)	(31)		(75)
Asset (liability) balance as of September 30	$	(97)	$	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)	2020		2019
Asset balance as of January 1	$	5	$	95
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)	(102)		(61)
Asset (liability) balance as of September 30	$	(97)	$	34

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable; short-term borrowings; accounts payable; and customer deposits approximate their carrying values at September 30, 2020 and December 31, 2019, as they are short-term in nature.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):


	At September 30, 2020				At December 31, 2019
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount(1)		Level 2 Fair Value(1)(2)
Debt (Note 5)
PG&E Corporation	$	1,904	$	1,942	$	—	$	—
Utility	29,657		30,637		1,500		1,500

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

(2) The fair value of the Utility pre-petition debt was $17.9 billion at December 31, 2019. For more information, see Note 2 and Note 5.

Nuclear Decommissioning Trust Investments

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


(in millions)
As of September 30, 2020	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
Nuclear decommissioning trusts
Short-term investments	$	12	$	—	$	—	$	12
Global equity securities	584		1,670		(9)		2,245
Fixed-income securities	1,486		164		(3)		1,647
Total (1)	$	2,082	$	1,834	$	(12)	$	3,904
As of December 31, 2019
Nuclear decommissioning trusts
Short-term investments	$	6	$	—	$	—	$	6
Global equity securities	500		1,609		(2)		2,107
Fixed-income securities	1,505		89		(4)		1,590
Total (1)	$	2,011	$	1,698	$	(6)	$	3,703

(1) Represents amounts before deducting $586 million and $530 million for the periods ended September 30, 2020 and December 31, 2019, respectively, primarily related to deferred taxes on appreciation of investment value.

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


	As of
(in millions)	September 30, 2020
Less than 1 year	$	23
1–5 years	452
5–10 years	402
More than 10 years	770
Total maturities of fixed-income securities	$	1,647

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


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	890	$	346	$	1,144	$	808
Gross realized gains on securities	51		45		59		67
Gross realized losses on securities	(22)		(5)		(34)		(12)

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.

2015 Butte Fire

In September 2015, a wildfire (the “2015 Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. Cal Fire 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.

During the quarter ended September 30, 2020, the remaining 2015 Butte fire claims were satisfied and discharged in accordance with the Plan. See “Pre-Petition Wildfire-Related Claims and Discharge Upon Plan Effective Date” and “District Attorneys’ Office Investigations” below for more information on the 2015 Butte fire.

2018 Camp Fire and 2017 Northern California Wildfires Background

According to Cal Fire, on November 8, 2018 at approximately 6:33 a.m., 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 November 15, 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 18,804 structures resulting from the 2018 Camp fire.

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.

PG&E Corporation and the Utility were subject to numerous claims in connection with the 2018 Camp fire and 2017 Northern California wildfires. These included claims by various groups of wildfire victims, including individual plaintiffs, holders of insurance subrogation claims, and various federal, state and local entities. During the quarter ended September 30, 2020, these claims have been satisfied and discharged in accordance with the Plan, as described below.

Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date

Pre-petition 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.

On July 1, 2020, pursuant to the Plan, PG&E Corporation and the Utility funded the Fire Victim Trust with $5.4 billion in cash (with an additional $1.35 billion to be funded on a deferred basis), 477.0 million shares of common stock of PG&E Corporation (representing 22.19% of the outstanding common stock of PG&E Corporation as of the Effective Date (subject to potential adjustments)), plus the assignment of certain rights and causes of action. Additionally, as a result of the Equity Units Underwriters exercising their option to purchase 1.45 million additional Equity Units, on August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the assignment agreement with the Fire Victim Trust. In accordance with the Plan and the Confirmation Order, as a result of such funding, all Fire Victim Claims have been fully and finally satisfied, released and discharged and channeled to the Fire Victim Trust with no recourse to PG&E Corporation or the Utility. Accordingly, $12.15 billion of the $13.5 billion liability as of June 30, 2020 was extinguished in the third quarter of 2020, and the remaining $1.35 billion will be paid out under the terms of the Tax Benefits Payment Agreement, as described in Note 2 under the heading “Significant Bankruptcy Court Actions.”

On July 1, 2020, PG&E Corporation and the Utility funded the Subrogation Wildfire Trust for the benefit of holders of Subrogation Claims in the amount of $11.0 billion in cash and paid approximately $43 million in respect of professional fees of such claimants, for a total of approximately $52 million for subrogation wildfire claimants’ professional fees. Such amount was initially funded into escrow and later paid to the Subrogation Wildfire Trust. In accordance with the Plan and the Confirmation Order, as a result of such funding, all Subrogation Claims have been satisfied, released and discharged and channeled to the Subrogation Wildfire Trust with no recourse to PG&E Corporation or the Utility. Accordingly, the $11.0 billion liability accrual for Subrogation Claims and $47.5 million liability for professional fees was extinguished in the third quarter of 2020.

On July 1, 2020, PG&E Corporation and the Utility paid $1.0 billion in cash to the Settling Public Entities and established a segregated fund in the amount of $10 million to be used to reimburse the Settling Public Entities for any and all legal fees and costs associated with the defense or resolution of any third party claims against the Settling Public Entities. In accordance with the Plan and the Confirmation Order, as a result of such payments, the $1.0 billion liability for the Public Entity Wildfire Claims has been satisfied, released and discharged in the third quarter of 2020.

Plan Support Agreements with Public Entities

On June 18, 2019, PG&E Corporation and the Utility entered into PSAs with certain local public entities (collectively, the “Supporting Public Entities”) providing for an aggregate of $1.0 billion to be paid by PG&E Corporation and the Utility to such public entities pursuant to the Plan in order to fully and finally settle and discharge 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”).

The PSAs also provide that, following the Effective Date, PG&E Corporation and the Utility would create and promptly fund $10 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”).

These elements were incorporated into the Plan which was approved by the Bankruptcy Court in the Confirmation Order. As described in Note 2 under the heading “Significant Bankruptcy Court Actions,” the actions required by each PSA were taken on or around the Effective Date.

Restructuring Support Agreement with Holders of Subrogation Claims

On September 22, 2019, PG&E Corporation and the Utility entered into the Subrogation RSA. The Subrogation RSA provides for an aggregate amount of $11.0 billion to be paid by PG&E Corporation and the Utility pursuant to the Plan in order to fully and finally settle the Subrogation Claims, upon the terms and conditions set forth in the Subrogation RSA. Under the Subrogation RSA, PG&E Corporation and the Utility have also agreed to reimburse the holders of Subrogation Claims for professional fees of up to $55 million, upon the terms and conditions set forth in the Subrogation RSA.

As described above under the heading “Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date,” the payments described in the Subrogation RSA were made on the Effective Date.

Restructuring Support Agreement with the TCC

On December 6, 2019, PG&E Corporation and the Utility entered into the TCC RSA. The TCC RSA provides for, among other things, a combination of cash and common stock of the reorganized PG&E Corporation to be provided by PG&E Corporation and the Utility pursuant to the Plan (together with certain additional rights, the “Aggregate Fire Victim Consideration”) in order to settle and discharge the Fire Victim Claims, upon the terms and conditions set forth in the TCC RSA and the Plan. The Aggregate Fire Victim Consideration that will fund the Fire Victim Trust pursuant to the Plan for the benefit of holders of the Fire Victim Claims will consist of (a) $5.4 billion in cash that was contributed on the Effective Date of the Plan, (b) $1.35 billion in cash consisting of (i) $650 million to be paid in cash on or before January 15, 2021 and (ii) the remaining balance of $1.35 billion to be paid in cash on or before January 15, 2022, in each case pursuant to the terms of a tax benefit payment agreement to be entered into between the Fire Victim Trust and the reorganized Utility, and (c) an amount of common stock of the reorganized PG&E Corporation valued at 14.9 times Normalized Estimated Net Income (as defined in the TCC RSA), except that the Fire Victim Trust’s share ownership of the reorganized PG&E Corporation would not be less than 20.9% based on the number of fully diluted shares of the reorganized PG&E Corporation outstanding as of the Effective Date of the Plan, assuming the Utility’s allowed ROE as of the date of the TCC RSA. Under certain circumstances, including certain change of control transactions and in connection with the monetization of certain tax benefits related to the payment of wildfire-related claims, the payments described in clause (b) will be accelerated and payable upon an earlier date. The Aggregate Fire Victim Consideration also includes (1) the assignment by PG&E Corporation and the Utility to the Fire Victim Trust of certain rights and causes of action related to the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (together, the “Fires”) that PG&E Corporation and the Utility may have against certain third parties and (2) the assignment of rights under the 2015 insurance policies to resolve any claims related to the Fires in those policy years, other than the rights of PG&E Corporation and the Utility to be reimbursed under the 2015 insurance policies for claims submitted to and paid by PG&E Corporation and the Utility prior to the Petition Date to resolve any claims related to the Fires in those policy years. On June 11, 2020, PG&E Corporation and the Utility and the TCC agreed that the percentage ownership of the Fire Victim Trust will be 22.19% of the outstanding shares of the PG&E Corporation on the Effective Date, subject to potential adjustments.

Pursuant to further discussions with claimants relating to the Ghost Ship fire, certain provisions of the TCC RSA were superseded by the terms of the Plan, and accordingly the above description of the TCC RSA has been revised to reflect the fact that claims arising out of the Ghost Ship fire will be resolved separately from the TCC RSA.

As described above under the heading “Pre-petition Wildfire-Related Claims and Discharge Upon Plan Effective Date,” the funding to be made pursuant to the TCC RSA and the Plan were made on the Effective Date.

2019 Kincade Fire

According to Cal Fire, on October 23, 2019 at approximately 9:27 p.m., a wildfire began northeast of Geyserville in Sonoma County, California (the “2019 Kincade fire”), located in the service territory of the Utility. The Cal Fire Kincade Fire Incident Update dated November 20, 2019, 11:02 a.m. Pacific Time (the “incident update”) indicated that the 2019 Kincade fire had consumed 77,758 acres. In the incident update, Cal Fire reported no fatalities and four first responder injuries. The incident update also indicates the following: structures destroyed, 374 (consisting of 174 residential structures, 11 commercial structures and 189 other structures); and structures damaged, 60 (consisting of 35 residential structures, one commercial structure and 24 other structures). In connection with the 2019 Kincade fire, state and local officials issued numerous mandatory evacuation orders and evacuation warnings at various times for certain areas of the region. Based on County of Sonoma information, PG&E Corporation and the Utility understand that the geographic zones subject to either a mandatory evacuation order or an evacuation warning between October 23, 2019 and November 4, 2019 included approximately 200,000 persons.

On October 23, 2019, by 3:00 p.m. Pacific Time, the Utility had conducted a PSPS event and turned off the power to approximately 27,837 customers in Sonoma County, including Geyserville and the surrounding area. As part of the PSPS, the Utility’s distribution lines in these areas were deenergized. Following the Utility’s established and CPUC-approved PSPS protocols and procedures, transmission lines in these areas remained energized.

The Utility has submitted electric incident reports to the CPUC indicating that:

•at approximately 9:19 p.m. Pacific Time on October 23, 2019, the Utility became aware of a transmission level outage on the Geysers #9 Lakeville 230 kV line when the line relayed and did not reclose;

•various generating facilities on the Geysers #9 Lakeville 230kV line detected the disturbance and separated at approximately the same time;

•at approximately 9:21 p.m. Pacific Time, the PG&E Grid Control Center received a report that a fire had started in an area near transmission tower 001/006;

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

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

On July 16, 2020, Cal Fire issued a press release addressing the cause of the 2019 Kincade fire. Cal Fire has determined that “the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.”

Cal Fire also indicated that its investigative report has been forwarded to the Sonoma County District Attorney’s Office, which is investigating the matter. On September 25, 2020, the Utility entered into a tolling agreement with the Sonoma County District Attorney’s Office in which the Utility agreed to waive any applicable statute of limitations for violations related to the Kincade fire that would otherwise have expired on or about October 23, 2020, for a period of six months, until April 23, 2021.

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

Potential liabilities related to the Kincade fire depend on various factors, including but not limited to the cause of the fire, contributing causes of the fire (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, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties, fines, or restitution that may be imposed by governmental entities.

If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the Kincade fire, 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.)

In light of the current state of the law concerning inverse condemnation and the information currently available to PG&E Corporation and the Utility, including the information contained in the electric incident reports, Cal Fire’s determination of the cause, and other information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2019 Kincade fire. PG&E Corporation and the Utility recorded a charge in the amount of $600 million for the six months ended June 30, 2020 (before available insurance). Based on additional facts and circumstances available to the Utility as of the date of this filing, PG&E Corporation and the Utility recorded an additional charge for potential losses in connection with the 2019 Kincade fire in the amount of $25 million for the three months ended September 30, 2020.

The aggregate liability of $625 million for claims in connection with the 2019 Kincade fire (before available insurance) corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses and is subject to change based on additional information. The $625 million estimate does not include, among other things, (i) any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) any amounts in respect of compensation claims by Federal or state agencies other than state fire suppression costs, (iv) evacuation costs or (v) any other amounts that are not reasonably estimable.

The $600 million estimate of the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses from the end of the prior quarter was based primarily on publicly available information and the Utility had not received significant data regarding actual claimed losses from potential claimants. Since that time, the Utility has received certain information from potential claimants, including certain information received from holders of certain insurance subrogation claims, leading to an increase in such estimate of the lower end. The Utility believes it will continue to receive additional information from potential claimants as litigation or resolution efforts progress. Any such additional information may potentially allow PG&E Corporation and the Utility to refine such estimate and may result in additional changes to the accrual depending on the information provided.

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of loss could be greater than $625 million (before available insurance) but are unable to reasonably estimate the additional loss and the upper end of the range because, as described above, 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. If the liability for the 2019 Kincade fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount, subject to the 40% limitation on claims arising before emergence from bankruptcy. 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 potential damages.

The process for estimating losses associated with potential claims related to the 2019 Kincade fire requires management to exercise significant judgment based on a number of assumptions and subjective factors, including the 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 potential financial impact of the 2019 Kincade fire may change.

The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Kincade fire in an aggregate amount of $430 million. The Utility records insurance recoveries when it is deemed probable that recovery will occur, and the Utility can reasonably estimate the amount or its range. As of September 30, 2020, the Utility has recorded an insurance receivable for the full amount of the $430 million. 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.

PG&E Corporation and the Utility have received and are responding to data requests from the SED relating to the Kincade fire. The Sonoma County District Attorney’s Office is currently investigating the fire and various other entities may also be investigating the fire. It is uncertain when the investigations will be complete.

As of October 28, 2020, PG&E Corporation and the Utility are aware of 16 complaints on behalf of approximately 377 plaintiffs related to the 2019 Kincade fire and expects that they may receive further such complaints. The complaints were filed in the California Superior Court for the County of Sonoma and include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect and de-energize their transmission lines was the cause of the 2019 Kincade fire. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees and other damages.

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.

2020 Zogg Fire

According to Cal Fire, on September 27, 2020, a wildfire began in the area of Zogg Mine Road and Jenny Bird Lane, north of Igo in Shasta County, California (the “2020 Zogg fire”), located in the service territory of the Utility. The Cal Fire Zogg fire Incident Update dated October 16, 2020, 3:08 p.m. Pacific Time (the “incident update”), indicated that the 2020 Zogg fire had consumed 56,338 acres. The incident update reported four fatalities and one injury. The incident update also indicated that 27 structures were damaged and 204 structures were destroyed.

On October 9, 2020, the Utility submitted an electric incident report to the CPUC indicating that:

•wildfire camera and satellite data on September 27, 2020 show smoke, heat or signs of fire in the area of Zogg Mine Road and Jenny Bird Lane between approximately 2:43 p.m. and 2:46 p.m. Pacific Time;

•according to Utility records, on September 27, 2020, a SmartMeter and a line recloser serving the area of Zogg Mine Road and Jenny Bird Lane reported alarms and other activity between approximately 2:40 p.m. and 3:06 p.m. Pacific Time when the line recloser de-energized a portion of the Girvan 1101 12 kV circuit, a distribution line that serves that area;

•the data currently available to the Utility do not establish the causes of the activity on the Girvan 1101 circuit or the locations of these causes;

•on October 9, 2020, Cal Fire informed the Utility that they had taken possession of Utility equipment as part of Cal Fire’s ongoing investigation into the cause of the 2020 Zogg fire and allowed the Utility access to the area; and

•Cal Fire has not issued a determination as to the cause.

The cause of the 2020 Zogg fire remains under investigation by Cal Fire, and PG&E Corporation and the Utility are cooperating with its investigation. The Shasta County District Attorney’s Office is investigating the fire, and various other entities, which may include other law enforcement agencies, may also be investigating the fire. It is uncertain when any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2020 Zogg fire. This investigation is preliminary, and PG&E Corporation and the Utility do not have access to all of the evidence in the possession of Cal Fire or other third parties.

Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information contained in the electric incident report and other information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is reasonably possible that they will incur a loss in connection with the 2020 Zogg fire. However, due to the limited amount of time that has elapsed since the start of the 2020 Zogg fire, the preliminary stages of the investigations, and the uncertainty as to the extent and magnitude of potential losses, PG&E Corporation and the Utility cannot reasonably estimate the amount or range of such possible loss at this time.

While the cause of the 2020 Zogg fire remains under investigation and there are a number of unknown facts surrounding the cause of the 2020 Zogg fire, the Utility could be subject to significant liability in connection with this fire. If such liability were to exceed insurance coverage, it could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

As of October 28, 2020, PG&E Corporation and the Utility are aware of one complaint on behalf of approximately six plaintiffs that may be related to the 2020 Zogg fire and expect that they may receive further such complaints. The one complaint filed thus far has, as of October 28, 2020, not yet been served on PG&E Corporation or the Utility, and PG&E Corporation and the Utility have not yet had the opportunity to review it.

Loss Recoveries

PG&E Corporation and the Utility have 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 wildfires or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the inability to recover costs in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Insurance

Insurance Coverage

PG&E Corporation and the Utility have liability insurance coverage for wildfire events in an amount of $430 million (subject to an initial self-insured retention of $10 million per occurrence) for the period from August 1, 2019 through July 31, 2020, and approximately $1 billion in liability insurance coverage for non-wildfire events (subject to an initial self-insured retention of $10 million per occurrence), comprised of $520 million for the period from August 1, 2019 through July 31, 2020 and $480 million for the period from September 3, 2019 through September 2, 2020. PG&E Corporation’s and the Utility’s cost of obtaining this wildfire and non-wildfire insurance coverage in place for the period of August 1, 2019 through September 2, 2020 is approximately $212 million.

In July 2020, and through additional purchases in August 2020, the Utility renewed its liability insurance coverage for wildfire events in the amount of $867.5 million (subject to an initial self-insured retention of $60 million), comprised of $825 million for the period of August 1, 2020 to July 31, 2021 and $42.5 million in reinsurance for the period of July 1, 2020 through June 30, 2021. In addition, the Utility renewed its liability insurance coverage for non-wildfire events in the amount of $700 million (subject to an initial self-insured retention of $10 million) for the period from August 1, 2020 through July 31, 2021. PG&E Corporation’s and the Utility’s cost of obtaining this wildfire and non-wildfire coverage is approximately $859 million.

Various coverage limitations applicable to different insurance layers could result in material uninsured costs in the future depending on the amount and type of damages resulting from covered events.

The Utility’s 2020 GRC settlement agreement, currently pending before the Commission, includes a new two-way balancing account that, if approved, would allow the Utility to recover in rates its actual insurance premium costs for up to $1.4 billion in coverage. The Utility is unable to predict the timing and outcome of the 2020 GRC proceeding.

The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any calendar year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054. (See “Wildfire Fund under AB 1054” below.)

Insurance Receivable

PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through September 30, 2020, PG&E Corporation and the Utility recorded $1.38 billion for probable insurance recoveries in connection with the 2018 Camp fire, $843 million for probable insurance recoveries in connection with the 2017 Northern California wildfires, and $430 million for probable insurance recoveries in connection with the 2019 Kincade fire. These amounts reflect an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets:


Insurance Receivable (in millions)	2019 Kincade fire		2018 Camp fire		2017 Northern California wildfires		2015 Butte fire		Total
Balance at December 31, 2019	$	—	$	1,380	$	807	$	50	$	2,237
Accrued insurance recoveries	430		—		—		—		430
Reimbursements	—		(1,380)		(707)		—		(2,087)
Balance at September 30, 2020	$	430	$	—	$	100	$	50	$	580

In October 2020, the Utility received another $75 million and $50 million in insurance reimbursements related to the 2017 Northern California wildfires and the 2015 Butte fire, respectively.

Regulatory Recovery

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

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

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

On July 8, 2019, the CPUC issued a decision in the CHT proceeding. The decision adopts a methodology to determine the CHT based on (1) the maximum additional debt that a utility can take on and maintain a minimum investment grade credit rating; (2) excess cash available to the utility; (3) a potential regulatory adjustment of 20% of the CHT or 5% of the total disallowed wildfire liabilities; and (4) an adjustment to preserve for ratepayers any tax benefits associated with the CHT. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers as part of an application under Section 451.2(b).

Pursuant to SB 901 and the CPUC’s methodology adopted in the CHT OIR, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs that is designed to not impact amounts billed to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt and accelerate a $700 million payment due to the Fire Victim Trust.

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 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 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 was 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. Prior to resolution of the plaintiffs’ request to lift the stay, this matter was automatically stayed by PG&E Corporation’s and the Utility’s commencement of bankruptcy proceedings, as discussed below.

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. A case management conference is currently set for November 19, 2020.

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

On November 21, 2018, a fifth purported derivative lawsuit, entitled Williams v. Earley, Jr., et al., was filed in federal court in San Francisco, alleging claims identical to those alleged in the Oklahoma Firefighters Pension and Retirement System v. Chew, et al. lawsuit listed above against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. This lawsuit includes allegations related to the 2017 Northern California wildfires and the 2018 Camp fire. This action was stayed by stipulation of the parties and order of the court on December 21, 2018, subject to resolution of the pending securities class action. A case management conference is currently set for November 19, 2020.

On December 24, 2018, a sixth purported derivative lawsuit, entitled Bowlinger v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. On February 5, 2019, the plaintiff in Bowlinger 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. A case management conference is currently set for November 6, 2020.

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. A case management conference is currently set for January 6, 2021.

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. A case management conference is currently set for November 19, 2020.

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 were automatically stayed through the Effective Date pursuant to section 362(a) of the Bankruptcy Code. PG&E Corporation’s and the Utility’s rights with respect to the derivative claims asserted against former officers and directors of PG&E Corporation and the Utility were assigned to the Fire Victim Trust under the TCC RSA. The assignment became effective as of the Effective Date.

The above purported derivative lawsuits were brought against the named defendants on behalf of PG&E Corporation and/or the Utility. As a result of the assignment of these derivative claims to the Fire Victim Trust, any recovery based on the derivative claims would be paid to the Fire Victim Trust. Any such recovery is limited to the extent of any director and officer insurance policy proceeds paid by any insurance carrier to reimburse PG&E Corporation and/or the Utility for amounts paid pursuant to their indemnification obligations in connection with such causes of action.

Securities Class Action Litigation

Wildfire-Related Class Action

In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California, naming PG&E Corporation and certain of its current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively. The complaints alleged material misrepresentations and omissions related to, among other things, vegetation management and transmission line safety in various PG&E Corporation public disclosures. The complaints asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases and the litigation is now denominated In re PG&E Corporation Securities Litigation. The court also appointed the Public Employees Retirement Association of New Mexico (“PERA”) as lead plaintiff. The plaintiff filed a consolidated amended complaint on November 9, 2018. After the plaintiff requested leave to amend its 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 were automatically stayed as to PG&E Corporation and the Utility 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 third purported securities class action was filed in the United States District Court for the Northern District of California, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint names as defendants certain current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility is named as a defendant. The complaint alleges material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. The complaint asserts claims under Section 11 and Section 15 of the Securities Act, 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. On August 28, 2019, the Bankruptcy Court denied PG&E Corporation’s and the Utility’s request to extend the stay to the claims against the officer, director, and underwriter defendants. On October 4, 2019, the officer, director, and underwriter defendants filed motions to dismiss the third amended complaint, which motions are currently under submission with the District Court.

Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims

Claims against PG&E Corporation and the Utility relating to the three purported securities class actions (described above) that have been consolidated and denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-035509, will be resolved pursuant to the Plan. As described above, these claims consist of pre-petition claims under the Federal securities laws related to, among other things, allegedly misleading statements or omissions with respect to vegetation management and wildfire safety disclosures, and are classified into two categories under the Plan, each of which is subject to subordination under the Bankruptcy Code. The first category of claims consists of pre-petition claims arising from or related to the common stock of PG&E Corporation (such claims, with certain other similar claims against PG&E Corporation, the “HoldCo Rescission or Damage Claims”). The second category of pre-petition claims consists of claims arising from debt securities issued by PG&E Corporation and the Utility (such claims, with certain other similar claims against PG&E Corporation and the Utility, the “Subordinated Debt Claims,” and together with the HoldCo Rescission or Damage Claims, the “Subordinated Claims”).

While PG&E Corporation and the Utility believe they have defenses to the Subordinated Claims, as well as insurance coverage that may be available in respect of the Subordinated Claims, these defenses may not prevail and any such insurance coverage may not be adequate to cover the full amount of the allowed claims. In that case, PG&E Corporation and the Utility will be required, pursuant to the Plan, to satisfy such claims as follows:

•each holder of an allowed HoldCo Rescission or Damage Claim will receive a number of shares of common stock of PG&E Corporation equal to such holder’s HoldCo Rescission or Damage Claim Share (as such term is defined in the Plan); and

•each holder of an allowed Subordinated Debt Claim will receive payment in full in cash.

PG&E Corporation and the Utility have been engaged in settlement efforts with respect to the Subordinated Claims. If the Subordinated Claims are not settled (with any such resolution being subject to the approval of the Bankruptcy Court), PG&E Corporation and the Utility expect that the Subordinated Claims will be resolved by the Bankruptcy Court in the claims reconciliation process and treated as described above under the Plan. Under the Plan, after the Effective Date, PG&E Corporation and the Utility have the authority to compromise, settle, object to, or otherwise resolve proofs of claim, and the Bankruptcy Court retains jurisdiction to hear disputes arising in connection with disputed claims. With respect to the Subordinated Claims, the claims reconciliation process may include litigation of the merits of such claims, including the filing of motions, fact discovery, and expert discovery. The total number and amount of allowed Subordinated Claims, if any, was not determined at the Effective Date. To the extent any such claims are allowed, the total amount of such claims could be material, and therefore could result in (a) the issuance of a material number of shares of common stock of PG&E Corporation with respect to allowed HoldCo Rescission or Damage Claims, and/or (b) the payment of a material amount of cash with respect to allowed Subordinated Debt Claims. There can be no assurance that such claims will not have a material adverse impact on PG&E Corporation’s and the Utility’s business, financial condition, results of operations, and cash flows.

Further, if shares are issued in respect of allowed HoldCo Rescission or Damage Claims, it may be determined that under the Plan, the Fire Victim Trust should receive additional shares of common stock of PG&E Corporation (assuming, for this purpose, that shares issued in respect of the HoldCo Rescission or Damage Claims were issued on the Effective Date).

The named plaintiffs in the consolidated securities actions filed proofs of claim with the Bankruptcy Court on or before the bar date that reflect their securities litigation claims against PG&E Corporation and the Utility. On December 9, 2019, the lead plaintiff in the consolidated securities actions filed a motion seeking approval from the Bankruptcy Court to treat its proof of claim as a class proof of claim. On February 27, 2020, the Bankruptcy Court issued an order denying the motion, but extending the bar date for putative class members to file proofs of claim until April 16, 2020. On March 6, 2020, the lead plaintiff filed a notice of appeal regarding the denial of its motion. On May 15, 2020, the lead plaintiff filed the opening brief for its appeal. On June 15, 2020, PG&E filed its brief in response. On June 29, 2020, the lead plaintiff filed its reply. No hearing date has been set.

On July 2, 2020, PERA filed a notice of appeal of the Confirmation Order to the District Court, solely to the extent of seeking review of that part of the Confirmation Order approving the Insurance Deduction (as defined in the Plan) with respect to the formula for the determination of the HoldCo Rescission or Damage Claims Share. On September 3, 2020, PERA filed its principal brief in support of the appeal. On October 5, 2020, PG&E Corporation and the Utility filed their response brief. PERA filed its reply brief on October 19, 2020.

On September 1, 2020, PG&E Corporation and the Utility filed a motion (the “Securities Claims Procedures Motion”) with the Bankruptcy Court to approve procedures to allow for the resolution of the outstanding and unresolved Subordinated Claims, which motion, among other things, requests approval of certain information request procedures, standard and abbreviate mediation processes, and procedures with respect to the potential filing of omnibus claim objections with respect to the Subordinated Claims. PERA and a number of other parties have filed objections to the Securities Claims Procedures Motion.

On September 28, 2020, PERA filed a second motion requesting the Bankruptcy Court exercise its discretion pursuant to Bankruptcy Rule 7023 to allow PERA to file a class proof of claim on behalf of the holders of Subordinated Claims (the “Renewed 7023 Motion”). The Bankruptcy Court set a briefing schedule that, among other things, (i) adjourned the hearing on the Securities Claims Procedures Motion to November 17, 2020, and (ii) established a briefing scheduled with respect to the Renewed 7023 Motion with a hearing on the motion also scheduled for November 17, 2020. PG&E Corporation’s and the Utility’s deadline to object to the Renewed 7023 Motion is October 29, 2020.

De-energization Class Action

On October 25, 2019, a purported securities class action was filed in the United States District Court for the Northern District of California, entitled Vataj v. Johnson et al. The complaint named as defendants a current director and certain current and former officers of PG&E Corporation. Neither PG&E Corporation nor the Utility was named as a defendant. The complaint alleged materially false and misleading statements regarding PG&E Corporation’s wildfire prevention and safety protocols and policies, including regarding the Utility’s public safety power shutoffs, that allegedly resulted in losses and damages to holders of PG&E Corporation’s securities. The complaint 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, attorneys’ fees and other costs. On February 3, 2020, the District Court granted a stipulation appointing Iron Workers Local 580 Joint Funds, Ironworkers Locals 40,361 & 417 Union Security Funds and Robert Allustiarti co-lead plaintiffs and approving the selection of the plaintiffs’ counsel, and further ordered the parties to submit a proposed schedule by February 13, 2020. On February 20, 2020, the District Court issued a scheduling order that required the amended complaint to be filed by April 17, 2020.

On April 17, 2020, the plaintiffs filed an amended complaint asserting the same claims. The amended complaint added PG&E Corporation and a former officer of PG&E Corporation as defendants, and no longer asserts claims against the other two officers of PG&E Corporation previously named in the action.

On May 15, 2020 the officer defendants filed their motion to dismiss in Vataj. On June 19, 2020, the lead plaintiff filed its opposition to the motion to dismiss. On July 10, 2020 the officer defendants filed their reply. The motion is currently under submission with the District Court. As of October 28, 2020, PG&E Corporation had not yet been served with this complaint.

PG&E Corporation and the Utility currently believe it is probable that they will incur a loss in connection with this proceeding and accordingly recorded a charge during the three months ended September 30, 2020. PG&E Corporation and the Utility determined that the amount of the charge recorded in connection with such loss is not material and corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimable range of losses. This amount is subject to change based on additional information.

PG&E Corporation and the Utility are unable to reasonably estimate the upper end of the range given the early stages of the consolidated securities actions and the de-energization class action, including but not limited to, the fact that the defendants’ motions to dismiss have not yet been decided and no discovery has occurred.

Indemnification Obligations

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

District Attorneys’ Offices Investigations

Following the 2018 Camp fire, the Butte County District Attorney’s Office and the California Attorney General’s Office opened a criminal investigation of the 2018 Camp fire. PG&E Corporation and the Utility were informed by the Butte County District Attorney’s Office and the California Attorney General’s Office that a grand jury had been empaneled in Butte County.

On March 17, 2020, the Utility entered into the Plea Agreement and Settlement (the “Plea Agreement”) with the People of the State of California, by and through the Butte County District Attorney’s office (the “People” and the “Butte DA,” respectively) to resolve the criminal prosecution of the Utility in connection with the 2018 Camp fire. Subject to the terms and conditions of the Plea Agreement, the Utility agreed to plead guilty to 84 counts of involuntary manslaughter in violation of Penal Code section 192(b) and one count of unlawfully causing a fire in violation of Penal Code section 452, and to admit special allegations pursuant to Penal Code sections 452.1(a)(2), 452.1(a)(3) and 452.1(a)(4).

Per the Plea Agreement, the Utility was sentenced to pay the maximum total fine and penalty of approximately $3.5 million. The Utility also agreed to pay $500,000 to the Butte County District Attorney Environmental and Consumer Protection Fund to reimburse costs spent on the investigation of the 2018 Camp fire.

Simultaneous with entry into the Plea Agreement, the Utility has committed to spend up to $15 million over five years to provide water to Butte County residents impacted by damage to the Utility’s Miocene Canal caused by the 2018 Camp fire. In addition, the Utility has consented to the Butte DA consulting, sharing information with and receiving information from the Monitor overseeing the Utility’s probation related to the San Bruno explosion through the expiration of the Utility’s term of probation and in no event until later than January 31, 2022. This consent is subject to the approval of the federal court overseeing the Utility’s probation and the Monitor.

On June 16, 2020 through June 18, 2020, the Butte County Superior Court held proceedings at which the Utility pled guilty and was sentenced according to the terms of the Plea Agreement. On July 21, 2020, the Utility paid the $3.5 million fine and penalty to the Butte County Superior Court and $500,000 to the Butte County District Attorney Environmental and Consumer Protection Fund.

Cal Fire announced that it had determined that “the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.” Cal Fire also indicated that its investigative report has been forwarded to the Sonoma County District Attorney’s Office, which is currently conducting an investigation of the fire. For more information see “2019 Kincade Fire” above.

The Shasta County District Attorney’s Office is investigating the 2020 Zogg fire. See “2020 Zogg Fire” above for further information.

Additional investigations and other actions may arise out of the 2019 Kincade fire or the 2020 Zogg fire. The timing and outcome for resolution of any such investigations are uncertain.

SEC Investigation

On March 20, 2019, PG&E Corporation learned that the SEC’s San Francisco Regional Office was 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 $62 million for clean-up and repair of the Utility’s facilities (including $18 million in capital expenditures) through September 30, 2020, in connection with the 2019 Kincade fire. The Utility is authorized to track and seek recovery of clean-up and repair costs through CEMA. (CEMA requests are subject to CPUC approval.) The Utility capitalizes and records as regulatory assets costs that are probable of recovery. At September 30, 2020, the CEMA regulatory asset balance related to the 2019 Kincade fire was zero. Additionally, the capital expenditures for clean-up and repair are included in property, plant and equipment at September 30, 2020.

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

Wildfire Fund under AB 1054

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

Electric utility companies that draw from the Wildfire 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 $2.4 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 Wildfire Fund, resulting in a draw-down of the Wildfire Fund.

On August 23, 2019, the CPUC approved the Utility’s Initial Safety Certification, which under AB 1054 entitles the Utility to certain benefits, including eligibility for a cap on wildfire fund reimbursement and for a reformed prudent manager standard. The Utility satisfied the required elements for its Initial Safety Certificate, as follows: (i) the electrical corporation has an approved wildfire mitigation plan, (ii) the electrical corporation is in good standing, which can be satisfied by the electrical corporation having agreed to implement the findings of its most recent safety culture assessment, if applicable, (iii) the electrical corporation has established a safety committee of its board of directors composed of members with relevant safety experience, and (iv) the electrical corporation has established board-of-director-level reporting to the CPUC on safety issues. The Initial Safety Certification is valid for 12 months. Before the expiration of any current safety certification, the Utility must request a new safety certification for the following 12 months, which shall be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. The existing safety certification remains valid until a timely request for a new safety certification is acted upon. On July 29, 2020, the Utility submitted its application for a new safety certification.

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 for at least a 10 year period. 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 Wildfire Fund allocation metric is 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million). The Wildfire Fund will only be available for payment of eligible claims so long as there are sufficient funds remaining in the Wildfire Fund. Such funds could be depleted more quickly than expected, including as a result of claims made by California’s other participating electric utility companies.

AB 1054 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 WMPs 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). The Utility’s allocation is $3.21 billion. AB 1054 contemplates that such capital expenditures may be securitized through a customer charge.

On July 23, 2019, the Utility notified the CPUC of its intent to participate in the Wildfire Fund. On August 7, 2019, PG&E Corporation and the Utility submitted a motion with the Bankruptcy Court for the entry of an order authorizing PG&E Corporation and the Utility to participate in the Wildfire Fund and to make any initial and annual contributions to the Wildfire Fund upon emergence from Chapter 11. On August 26, 2019, the Bankruptcy Court entered an order granting such authorizations. In order to participate in the Wildfire Fund, the Utility also was required to meet the eligibility and other requirements set forth in AB 1054, and to pay its share of the initial contribution to the Wildfire Fund upon emergence from Chapter 11.

On the Effective Date, having satisfied the conditions for the Utility’s participation in the Wildfire Fund, PG&E Corporation and the Utility contributed, in accordance with AB 1054, an initial contribution of approximately $4.8 billion and first annual contribution of approximately $193 million to the Wildfire Fund to secure participation of the Utility therein. SDG&E and Edison made their initial contributions to the Wildfire Fund in September 2019.

As of the Effective Date, the Wildfire Fund is available to the Utility to pay for eligible claims arising on or after the effective date of AB 1054, July 12, 2019, subject to a limit of 40% of the amount of allowed claims arising between the effective date of AB 1054 and the Effective Date of the Plan.

For additional information on the Wildfire Fund, see Note 3 above.

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

The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below.

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.

Enforcement Matters

U.S. District Court Matters and Probation

In connection with the Utility’s probation proceeding, the United States District Court for the Northern District of California has the ability to impose additional probation conditions on the Utility. Additional conditions, if implemented, could be wide-ranging and would impact the Utility’s operations, number of employees, costs and financial performance. Depending on the terms of these additional requirements, costs in connections with such requirements could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

CPUC and FERC Matters

Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire

On June 27, 2019, the CPUC issued the 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.” On December 5, 2019, the assigned commissioner issued a second amended scoping memo and ruling that amended the scope of issues to be considered in this proceeding to include the 2018 Camp fire.

As previously disclosed, on December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s Office of the Safety Advocate, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with this proceeding and jointly moved for its approval.

Pursuant to the settlement agreement, the Utility agreed to (i) not seek rate recovery of wildfire-related expenses and capital expenditures in future applications in the amount of $1.625 billion, as specified below, and (ii) incur costs of $50 million in shareholder-funded system enhancement initiatives as described further in the settlement agreement. The settlement agreement stipulates that no violations have been identified in the Tubbs fire. As a result of this finding, the settlement agreement does not prevent the Utility from seeking recovery of costs associated with the Tubbs fire through rates. The amounts set forth in the table below include actual recorded costs and forecasted cost estimates as of the date of the settlement agreement for expenses and capital expenditures which the Utility has incurred or planned to incur to comply with its legal obligations to provide safe and reliable service. While actual costs incurred for certain cost categories are different than what was assumed in the settlement agreement, the Utility has recorded $1.621 billion of the disallowed costs through September 30, 2020 and plans to incur the remaining $4 million in the fourth quarter of 2020.


(in millions)
Description(1)	Expense		Capital		Total
Distribution Safety Inspections and Repairs Expense (FRMMA/WMPMA)(2)	$	236	$	—	$	236
Transmission Safety Inspections and Repairs Expense (TO)(3)	433		—		433
Vegetation Management Support Costs (FHPMA)	36		—		36
2017 Northern California Wildfires CEMA Expense and Capital (CEMA)	82		66		148
2018 Camp Fire CEMA Expense (CEMA)	435		—		435
2018 Camp Fire CEMA Capital for Restoration (CEMA)	—		253		253
2018 Camp Fire CEMA Capital for Temporary Facilities (CEMA)(4)	—		84		84
Total	$	1,222	$	403	$	1,625

(1) Unless indicated otherwise, all amounts included in the table reflect actual recorded costs for 2019.

(2) Includes $29 million forecasted for 2020.

(3) Transmission amounts are under the FERC’s regulatory authority.

(4) Includes $59 million forecasted for 2020.

PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.

The Utility expects that the system enhancement spending pursuant to the settlement agreement will occur through 2025.

On April 20, 2020, the assigned commissioner issued a Decision Different adopting, with changes, the proposed modifications set forth in the request for review. The Decision Different (i) increases the amount of disallowed wildfire expenditures by $198 million (as set forth in the POD); (ii) increases the amount of shareholder funding for System Enhancement Initiatives by $64 million (as set forth in the POD); (iii) imposes a $200 million fine but permanently suspends payment of the fine; and (iii) limits the tax savings that must be returned to ratepayers to those savings generated by disallowed operating expenditures. The Decision Different also denies all pending appeals of the POD and denies, in part, the Utility’s motion requesting other relief. On April 30, 2020, the Utility submitted its comments on the Decision Different to the CPUC, accepting the modifications. The CPUC approved the Decision Different on May 7, 2020.

The settlement agreement, as modified by the Decision Different, became effective upon: (i) approval by the CPUC in the Decision Different, (ii) following such approval by the CPUC, the June 20, 2020 approval of the Bankruptcy Court, and (iii) the July 1, 2020 effectiveness of the Plan.

As it relates to the additional $198 million in disallowed costs as adopted in the Decision Different, the Utility has recorded charges of $80 million as of September 30, 2020 and intend to record the remaining charges of $118 million in fourth quarter of 2020 and 2021.

On June 8, 2020, two parties filed separate Applications for Rehearing, the purpose of which was to challenge the CPUC’s approval of the settlement agreement, as modified. On June 23, 2020, the Utility and CUE filed a joint response opposing the Applications for Rehearing. The Utility is unable to predict the timing and outcome of the CPUC’s rulings on the Applications for Rehearing.

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. On October 15, 2020, FERC issued an order that affirmed in part and reversed in part the initial decision. The order reopens the record for the limited purpose of allowing the participants to this proceeding an opportunity to present written evidence concerning FERC’s revised ROE methodology adopted in FERC Opinion No. 569-A, issued on May 21, 2020, that refined the methodology it established in Opinion No. 569 for setting the ROE that electric utilities are authorized to earn on electric transmission investments. In addition, the order approves depreciation rates that yield an estimated composite depreciation rate of 2.94% compared to the Utility’s request of 3.25%. Further, the decision reduces forecasted capital, operations and maintenance, and cost of debt expense to actual costs incurred for the rate case period. Finally, the order upheld the initial decision’s rejection of the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. Application of the operating and maintenance labor rates would result in an allocation of 6.15% of common plant to FERC in comparison to 8.84% under the Utility’s direct assignment method.

On September 21, 2018, the Utility filed an all-party settlement with the 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. The FERC also ordered that the hearings will be held in abeyance pending settlement discussions among the parties. On March 31, 2020, the Utility filed a partial settlement of TO20 resolving certain issues related to the formula rate but leaving several issues including return on equity, capital structure, and depreciation rates for further settlement discussions or hearing. FERC approved the Partial Settlement on August 17, 2020. On October 15, 2020, the Utility filed a settlement with FERC resolving all of the remaining issues in the Formula Rate Proceedings, including the Utility’s ROE, capital structure, depreciation rates, as well as certain other aspects of the Utility’s formula rate. The term of the settlement continues until December 31, 2023 and the Utility will be required to file a replacement rate filing to be effective on January 1, 2024. The settlement also required the Utility to concurrently file a motion for interim rates requesting that the settlement rates go into effect on January 1, 2021, while approval of the settlement is pending at FERC. The settlement also provides that the Utility will make supplemental filings in two FERC dockets addressing the calculation of the AFUDC, effective May 1, 2019, to reflect the terms of the settlement. The two AFUDC dockets have not been consolidated with the Formula Rate Proceedings but include capital structure issues addressed by the settlement.

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

Other Matters

PG&E Corporation and the Utility are subject to various claims and lawsuits 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 $167 million and $116 million at September 30, 2020 and December 31, 2019, respectively. These amounts were included in LSTC at December 31, 2019 and were included in Other current liabilities at September 30, 2020. 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.

PSPS Class Action

On December 19, 2019, a complaint was filed in the United States Bankruptcy Court for the Northern District of California naming PG&E Corporation and the Utility. The plaintiff seeks certification of a class consisting of all California residents and business owners who had their power shut off by the Utility during the October 9, October 23, October 26, October 28, or November 20, 2019 power outages and any subsequent voluntary outages occurring during the course of litigation. The plaintiff alleges that the necessity for the October and November 2019 power shutoff events was caused by the Utility’s negligence in failing to properly maintain its electrical lines and surrounding vegetation. The complaint seeks up to $2.5 billion in special and general damages, punitive and exemplary damages and injunctive relief to require the Utility to properly maintain and inspect its power grid. PG&E Corporation and the Utility believe the allegations are without merit and intend to defend this lawsuit vigorously.

On January 21, 2020, PG&E Corporation and the Utility filed a motion to dismiss the complaint or in the alternative strike the class action allegations. The motion to dismiss and strike was heard by the Bankruptcy Court on March 10, 2020, and on April 3, 2020, the Bankruptcy Court entered an order dismissing the action without leave to amend, finding that the action was preempted under the California Public Utilities Code.

On March 30, 2020, the Bankruptcy Court issued an opinion granting the Utility's motion to dismiss this class action. The court held that plaintiff’s class action claims are preempted as a matter of law by section 1759 of the California Public Utilities Code and thus plaintiffs could not pursue civil damages. The court stated that “any claim for damages caused by PSPS events approved by the CPUC, even if based on pre-existing events that may or may not have contributed to the necessity of the PSPS events, would interfere with the CPUC’s policy-making decisions.”

On April 6, 2020, plaintiff filed a notice of appeal of the Bankruptcy Court decision dismissing the complaint. Plaintiff has elected to have the appeal heard by the District Court, rather than the Bankruptcy Appellate Panel. Plaintiff filed a designation of the record and statement of the issues on April 20, 2020, and the Utility had until May 4, 2020, 14 days thereafter, to file a designation of any additional items.

On June 8, 2020, plaintiff filed its opening brief. The Utility filed its opposition brief on July 6, 2020. Plaintiff’s reply brief was filed on August 4, 2020 with a request for oral argument. The court has not yet ruled on plaintiff’s request for oral argument.

The Utility is unable to determine the timing and outcome of this proceeding.

GT&S Capital Expenditures 2011-2014

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 a review of reasonableness to be conducted, or overseen, by the CPUC staff. The review was completed on June 1, 2020 and did not result in any additional disallowances. The report certified $512 million for future recovery. The difference between the certified amount and the $576 million previously disallowed is primarily a result of differences between capital expenditures forecasted in the 2015 GT&S rate case and recorded capital expenditures.

On July 31, 2020, the Utility filed an application seeking recovery of revenue requirements on the $512 million of capital expenditures retroactive to January 1, 2015. On October 16, 2020, the assigned commissioner issued a scoping memo establishing the scope and schedule for the proceeding. The scoping memo requires the Utility to provide supplemental testimony on January 20, 2021 addressing the reasonableness of the capital expenditures. The scoping memo calls for the issuance of a proposed decision in the fourth quarter of 2021.

The Utility is unable to determine the timing and outcome of this upcoming proceeding.

Environmental Remediation Contingencies

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


	Balance at
(in millions)	September 30, 2020		December 31, 2019
Topock natural gas compressor station	$	323	$	362
Hinkley natural gas compressor station	133		138
Former manufactured gas plant sites owned by the Utility or third parties (1)	670		568
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	99		101
Fossil fuel-fired generation facilities and sites (3)	100		106
Total environmental remediation liability	$	1,325	$	1,275

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

(2) Primarily driven by 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 September 30, 2020, 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, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded. At September 30, 2020, the Utility expected to recover $1,003 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 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 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 $221 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 report was received in January 2020 and is expected to be finalized in 2021. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $137 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 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 $492 million if the extent of contamination or necessary remediation at currently identified MGP sites 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 $64 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 $40 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.

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, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $43 million. If European Mutual Association for Nuclear Insurance losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $4 million. For more information about the Utility’s nuclear insurance coverage, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K.

Tax Matters

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the resolution of audits. As of September 30, 2020, it is reasonably possible that unrecognized tax benefits will decrease by approximately $30 million within the next 12 months.

As of the date of this report, PG&E Corporation did not believe that it had undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code.

In March 2020, Congress passed, and the President signed into law the Coronavirus Aid, Relief and Economic Security (“CARES”) Act. Under the CARES Act, PG&E Corporation and the Utility expect to be able to defer the payment of 2020 payroll taxes for the remainder of the year to 2021 and 2022.

During June 2020, the State of California enacted AB 85, which increases taxes on corporations over a three-year period beginning in 2020 by suspension of the net operating loss deduction and a limit of $5 million per year on business tax credits. PG&E Corporation and the Utility do not anticipate any material impacts to PG&E Corporation’s Condensed Consolidated Financial Statements due to this legislation.

See “Ownership Restrictions in PG&E Corporation’s Amended Articles” in Note 6 for information on the possible election to treat the Fire Victim Trust as a “grantor trust” for federal income tax purposes.

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, 2019, the Utility had undiscounted future expected obligations of approximately $38 billion. (See Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K.)

Oakland Headquarters Lease

On June 5, 2020, the Utility entered into an Agreement to Enter Into Lease and Purchase Option (the “Agreement”) with TMG Bay Area Investments II, LLC (“TMG”). The Agreement provides that, contingent on (i) entry of an order by the Bankruptcy Court authorizing the Utility to enter into the Agreement and the Lease Agreement (as defined below), subject to certain conditions, and (ii) acquisition of the Building (as defined below) by BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG, the Utility and Landlord will enter into an office lease agreement (the “Lease Agreement”) for approximately 910,000 rentable square feet of space within the building located at 300 Lakeside Drive, Oakland, California 94612 (the “Building”) to serve as the Utility’s principal administrative headquarters (the “Lease”). On June 9, 2020, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court authorizing them to enter into the Agreement and grant related relief. The Bankruptcy Court entered an order approving the motion on June 24, 2020.

The term of the Lease will begin on or about January 1, 2022. The Lease term will expire 34 years and 11 months after the commencement date, unless earlier terminated in accordance with the terms of the Lease. In addition to base rent, the Utility will be responsible for certain costs and charges specified in the Lease, including insurance costs, maintenance costs and taxes.

The Lease will require the Landlord to pursue approvals to subdivide the real estate it owns surrounding the Building to create a separate legal parcel that contains the Building (the “Property”) that can be sold to the Utility. The Lease will grant to the Utility an option to purchase the Property, following such subdivision, at a price of $892 million, subject to certain adjustments (the “Purchase Price”). The Purchase Price would not be paid until 2023.

Pursuant to the terms of the Agreement, concurrent with the Landlord’s acquisition of the building, on October 23, 2020, the Utility and the Landlord entered into the Lease, and the Utility issued to Landlord (i) an option payment letter of credit in the amount of $75 million on or before the Lease Date (as defined in the Agreement and the Lease Agreement), and (ii) and a lease security letter of credit in the amount of $75 million.

In connection with entry into the Agreement, the Utility intends to sell its current office space generally located at 77 Beale Street, 215 Market Street, 245 Market Street and 50 Main Street, San Francisco, California 94105, and associated properties owned by the Utility (“SFGO”). Any sale of the SFGO would be subject to approval by the CPUC. On September 30, 2020, the Utility filed an application with the CPUC seeking authorization to sell the SFGO.

At September 30, 2020, the Agreement had no impact on PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements.

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

OVERVIEW

The Utility is regulated primarily by the CPUC and the FERC. The CPUC has jurisdiction over the rates, terms, and conditions of service for the Utility’s electricity and natural gas distribution operations, electric generation, and natural gas transportation and storage. The FERC has jurisdiction over the rates and terms and conditions of service governing the Utility’s electric transmission operations and interstate natural gas transportation contracts. The NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. The Utility is 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 Form 10-Q. It also should be read in conjunction with the 2019 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 were jointly administered under the caption In re: PG&E Corporation and Pacific Gas and Electric Company, Case No. 19-30088 (DM). On the Effective Date, PG&E Corporation and the Utility emerged from Chapter 11. 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. The contents of this website are not incorporated into this document.

For more information about Chapter 11 emergence and related transactions, see the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.

Chapter 11 Emergence

PG&E Corporation and the Utility emerged from Chapter 11 on July 1, 2020. For more information regarding the Chapter 11 emergence and the related transactions, see the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.

Tax Matters

As a result of the Plan, which includes wildfire settlement payments made in the third quarter of 2020, PG&E Corporation expects to have a federal net operating loss carryforward of around $26.0 billion and state net operating loss carryforward of $23.0 billion at the end of 2020.

Under Section 382 of the Internal Revenue Code, if a corporation (or a consolidated group) undergoes an “ownership change,” net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally 5% shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). PG&E Corporation’s and the Utility’s Amended Articles limit Transfers (as defined in the Amended Articles) that increase a person’s ownership of PG&E Corporation’s equity securities to more than 4.75% prior to the Restriction Release Date without approval by the Board of Directors. As discussed below under “Update on Ownership Restrictions in PG&E Corporation’s Amended Articles,” the calculation of the percentage ownership may differ depending on whether the Fire Victim Trust is treated as a qualified settlement trust or grantor trust.

As of the date of this report, PG&E Corporation does not believe that it has undergone an ownership change, and consequently, its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code.

In 2019, $6.75 billion of the liability to be paid to the Fire Victim Trust in PG&E Corporation’s common stock was accrued by the Utility. Because the corresponding tax deduction generally occurs no earlier than payment, the Utility established a deferred tax asset for the accrual in 2019. On July 1, 2020, the Utility paid to the Fire Victim Trust 477 million shares of PG&E Corporation’s common stock. Because of the price of the stock on the date of transfer, the shares transferred to the Fire Victim Trust were valued at $4.53 billion, $2.22 billion less than the $6.75 billion that had been accrued as a liability in the Condensed Consolidated Financial Statements. Therefore, in the quarter ended June 30, 2020, the Utility recorded a charge of $619 million to adjust the measurement of the deferred tax asset to reflect the tax-effected difference between the accrual of $6.75 billion and the tax deduction of $4.53 billion for the transfer of PG&E Corporation’s shares to the Fire Victim Trust.

In addition, this deferred tax asset reflects PG&E Corporation’s conclusion as of September 30, 2020 that it is more likely than not that the Fire Victim Trust will be treated as a “qualified settlement fund” for U.S. federal income tax purposes, in which case the corresponding tax deduction will have occurred at the time the PG&E Corporation common stock was transferred to the Fire Victim Trust. As discussed further below under “Update on Ownership Restrictions in PG&E Corporation’s Amended Articles,” PG&E Corporation believes that it may be beneficial to elect to treat the Fire Victim Trust as a “grantor trust,” but only if PG&E Corporation receives favorable determinations from the IRS regarding certain aspects of such election. If PG&E Corporation makes a “grantor trust” election for the Fire Victim Trust, the Utility’s tax deduction will occur instead at the time the Fire Victim Trust pays the fire victims and will be based on the price at which the Fire Victim Trust sells the shares. In this case, the accounting treatment will require a re-evaluation under applicable accounting guidance of the remaining deferred tax asset and could result in a further impairment thereof or other material impact on the Condensed Consolidated Financial Statements. Additionally, the value of the deduction may be materially different than the value of the deduction if the Fire Victim Trust is treated as a “qualified settlement fund.”

Update on Ownership Restrictions in PG&E Corporation’s Amended Articles

The Plan contemplates that the Fire Victim Trust will be treated as a “qualified settlement fund” for U.S. federal income tax purposes, subject to PG&E Corporation’s ability to elect to treat the Fire Victim Trust as a “grantor trust” for U.S. federal income tax purposes instead. Based on the facts known to date, PG&E Corporation believes that it may be beneficial to elect to treat the Fire Victim Trust as a “grantor trust” for U.S. federal income tax purposes, subject to receipt of certain favorable determinations from the Internal Revenue Service regarding such election.

If PG&E Corporation were to make a “grantor trust” election with respect to the Fire Victim Trust, then any shares owned by the Fire Victim Trust would effectively be excluded from the total number of outstanding equity securities when calculating a person’s percentage ownership for purposes of the 4.75 percent ownership limitation in PG&E Corporation's charter. For example, although PG&E had 1,984,565,829 shares outstanding as of October 20, 2020 for corporate purposes, only 1,506,822,239 shares (the number of outstanding shares of common stock less the number of shares held by the Fire Victim Trust) would count as outstanding for purposes of the ownership restrictions in the Amended Articles. As of October 20, 2020, to the knowledge of PG&E Corporation, the Fire Victim Trust had not sold any shares of PG&E Corporation common stock.

For more information about the ownership restrictions in PG&E Corporation’s Amended Articles, see PG&E Corporation’s and the Utility’s joint quarterly report on Form 10-Q for the period ended June 30, 2020.

Summary of Changes in Net Income and Earnings per Share

PG&E Corporation’s net income was $83 million and net loss attributable to common shareholders was $1,518 million in the three and nine months ended September 30, 2020, respectively, compared to net losses of $1,619 million and $4,039 million in the same periods in 2019. PG&E Corporation recognized charges of $526 million and $2.0 billion associated with the 2018 Camp fire and 2017 Northern California wildfires, respectively, for the three months ended September 30, 2019, as compared to a charge of $25 million related to the 2019 Kincade fire in the three months ended September 30, 2020. PG&E Corporation recognized charges of $2.4 billion and $4.0 billion associated with the 2018 Camp fire and 2017 Northern California wildfires, respectively, for the nine months ended September 30, 2019, as compared to a charge of $195 million, net of probable insurance recoveries, related to the 2019 Kincade fire during the same period in 2020. Additionally, in the nine months ended September 30, 2020, PG&E Corporation recognized $1.1 billion of expense related to the Backstop Commitment premium and $452 million of expense related to the Additional Backstop Premium Shares, with no similar amounts for the same periods in 2019.

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 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. To the extent that future wildfires occur in the Utility’s service territory, the Utility may incur costs associated with the investigations of the causes and origins of such fires, even if it is subsequently determined that such fires were not caused by the Utility’s facilities. 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, and any such coverage may include limitations that could result in substantial uninsured losses depending on the amount and type of damages resulting from covered events. In July and August 2020, the Utility renewed its liability insurance coverage for wildfire events in the aggregate amount of $867.5 million (subject to an initial self-insured retention of $60 million), comprised of $825 million for the period of August 1, 2020 to July 31, 2021 and $42.5 million in reinsurance for the period of July 1, 2020 through June 30, 2021. Various coverage limitations applicable to different insurance layers could result in material uninsured costs in the future depending on the amount and type of damages resulting from covered events. The Utility will not be able to obtain any recovery from the Wildfire Fund for wildfire-related losses in any calendar year that do not exceed the greater of $1.0 billion in the aggregate and the amount of insurance coverage required under AB 1054. 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 conditions to the Utility’s ongoing participation in the Wildfire Fund set forth in AB 1054 and that the Wildfire Fund has sufficient remaining funds. (See “Insurance Coverage” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

However, the impact of AB 1054 on PG&E Corporation and the Utility is subject to numerous uncertainties, including 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. Finally, even if the Utility satisfies the ongoing eligibility and other requirements set forth in AB 1054, for eligible claims against the Utility arising from wildfires that occurred between July 12, 2019 and the Utility’s emergence from Chapter 11 on July 1, 2020, the availability of the Wildfire Fund to pay such claims would be capped at 40% of the amount of such claims. (See “Wildfire Fund under AB 1054” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

•The Uncertainties Regarding the Impact of Public Safety Power Shutoffs. The Utility’s wildfire risk mitigation initiatives involve substantial and ongoing expenditures and could involve other costs. The extent to which the Utility will be able to recover these expenditures and potential other costs through rates is uncertain. The PSPS program, one of the Utility’s wildfire risk mitigation initiatives outlined in the 2019 Wildfire Mitigation Plan, has been the subject of significant scrutiny and criticism by various stakeholders, including the California governor, the CPUC and the court overseeing the Utility’s probation. On November 12, 2019, the CPUC issued an order to show cause against the Utility related to implementation of the October 2019 PSPS events, and on November 13, 2019, the CPUC instituted an OII to examine California’s investor-owned utilities late 2019 PSPS events and to consider enforcement actions. In addition, the PSPS program has had an adverse impact on PG&E Corporation’s and the Utility’s reputation with customers, regulators and policymakers and future PSPS events may increase these negative perceptions. In addition to the 2019 PSPS events, the Utility initiated several PSPS events in September and October of 2020, and expects that additional PSPS events will be necessary in 2020 and future years. (See “Order to Show Cause Against the Utility Related to Implementation of the October 2019 PSPS Events,” “OII to Examine the Late 2019 Public Safety Power Shutoff Events.” and “OIR to Examine Electric Utility De-energization of Power Lines in Dangerous Conditions” in “Regulatory Matters” below.)

In addition, the proposals of SB 378 and AB 1941, which would impose penalties and other requirements on electric utility companies relating to PSPS events, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. (See “Legislative and Regulatory Initiatives” below.) In addition, on April 13, 2020, a group of local governments and associations filed a Joint Motion for Emergency Order Regarding De-Energization Protocols During the COVID-19 Pandemic, requesting that the CPUC issue an emergency order setting forth de-energization protocols for the Utility and other investor-owned utilities that will remain in place for as long as a State of Emergency or shelter-in-place order remains in effect due to the COVID-19 pandemic. On August 24, 2020, the ALJ in the “OIR to Examine Electric Utility De-energization of Power Lines in Dangerous Conditions” proceedings ruled that the CPUC’s May 28, 2020 Decision, which adopted additional guidelines for de-energization events, had largely addressed the issues raised in the Joint Motion, and held the motion in abeyance. If the motion were reinstated in the future, a CPUC decision could restrict or impose additional requirements on the Utility in implementing PSPS events. (See “OIR to Examine Electric Utility De-energization of Power Lines in Dangerous Conditions” in Regulatory Matters” below.)

•The Costs and Execution of Other Wildfire Mitigation Efforts. In response to the wildfire threat facing California, PG&E Corporation and the Utility have taken aggressive steps to mitigate the threat of catastrophic wildfires, the spread of wildfires should they occur and the impact of PSPS events. PG&E Corporation and the Utility incurred approximately $2.6 billion in connection with the 2019 WMP and expect to incur approximately $2.6 billion in 2020 in connection with their 2020-2022 WMP. Although the Utility may seek cost recovery for certain of these expenses and capital expenditures, the Utility has agreed in the Wildfires OII not to seek rate recovery of certain wildfire-related expenses and capital expenditures in future applications in the amount of $1.823 billion.

While PG&E Corporation and the Utility are committed to taking aggressive wildfire mitigation actions, if additional requirements are imposed that go beyond current expectations, such requirements could have a substantial impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. For example, the Court overseeing the Utility’s probation in connection with the Utility’s federal criminal proceeding has imposed numerous obligations on the Utility related to its business and operations. The success of the Utility’s wildfire mitigation efforts depends on many factors, including on whether the Utility is able to retain or contract for the workforce necessary to execute its wildfire mitigation actions. (See “2020 GRC” below and “Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp Fire” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

•The Timing and Outcome of Ratemaking Proceedings. The Utility’s financial results may be impacted by the timing and outcome of its 2020 GRC, FERC TO18, TO19, and TO20 rate cases, WMCE application, and its ability to timely recover costs not currently in rates, including costs already incurred and future costs tracked in its CEMA, WEMA, WMPMA, FRMMA, and CPPMA. 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. The Utility’s ability to seek cost recovery will also be limited as a result of the outcome of the Wildfires OII. (See Notes 4 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and “Regulatory Matters” below.)

•The Impact of the 2019 Kincade Fire. Claims related to the 2019 Kincade fire will not be discharged in connection with emerging from Chapter 11. On July 16, 2020, Cal Fire issued a press release stating that it had determined that “the Kincade fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E).” Accordingly, if PG&E Corporation or the Utility were determined to be liable for the 2019 Kincade fire, such liabilities could be significant and could exceed the amounts available under applicable insurance policies, which could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. As of September 30, 2020, PG&E Corporation and the Utility had recorded a loss of $625 million for the 2019 Kincade fire, which amount corresponds to the lower end of the range of reasonably estimable probable losses. If the liability for the 2019 Kincade fire were to exceed $1.0 billion, it is possible the Utility would be eligible to make a claim to the Wildfire Fund under AB 1054 for such excess amount, subject to a 40% cap on the amount of such claim. As of September 30, 2020, the Utility has also recorded an insurance receivable for $430 million. (See “2019 Kincade Fire” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 for more information.)

•The Impact of the 2020 Zogg Fire and Other 2020 Wildfires. On October 9, 2020 Cal Fire informed the Utility that it had taken possession of Utility equipment as part of Cal Fire’s ongoing investigation into the 2020 Zogg fire. The investigation is preliminary and Cal Fire has not issued a determination of cause, but if PG&E Corporation or the Utility were determined to be liable for the 2020 Zogg fire, such liabilities could be significant and could exceed the amounts available under applicable insurance policies, which could be expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. (For more information see Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.) Apart from the 2020 Zogg fire, there have been numerous wildfires in the Utility’s service territory during the 2020 wildfire season, attributable to various weather conditions (such as lightning, dry conditions, or high winds) and other causes. In addition, the cause of many 2020 wildfires has yet to be determined. If the Utility were alleged or determined to be a cause of one or more of these wildfires, this allegation or determination could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

•The Impact of the COVID-19 Pandemic. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows have been and could continue to be significantly affected by the outbreak of COVID-19. The principal areas of near-term impact include liquidity, financial results and business operations, stemming primarily from the ongoing economic hardship of the Utility’s customers, the moratorium on service disconnections for residential and small business customers and an observed reduction in non-residential electrical load. The Utility continues to monitor the overall impact of the COVID-19 pandemic; however, the Utility expects a significant impact on monthly cash collections as long as current circumstances persist. This impact to liquidity may be partially offset by reductions in discretionary spending or potential regulatory impacts. As of September 30, 2020, PG&E Corporation and the Utility had access to approximately $2.6 billion of total liquidity comprised of approximately $140 million of Utility cash, $262 million of PG&E Corporation cash and $2.2 billion of availability under the Utility and PG&E Corporation credit facilities. Other potential impacts of COVID-19 on PG&E Corporation and the Utility include operational disruptions, workforce disruptions, both in personnel availability (including a reduction in contract labor resources) and deployment, delays in production and shipping of materials used in the Utility’s operations may also adversely impact operations, a reduction in revenue due to the cost of capital adjustment mechanism, the potential for higher credit spreads and borrowing costs and incremental financing needs. For more information on the impact of COVID-19 on PG&E Corporation and the Utility, see “PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be significantly affected by the outbreak of the COVID-19 pandemic” in Item 1A Risk Factors in Part II.

PG&E Corporation and the Utility expect additional financial impacts in the future as a result of COVID-19. PG&E Corporation and the Utility continue to evaluate the overall impact of COVID-19 and their analysis is subject to change.

•The Outcome of Other Enforcement, Litigation, and Regulatory Matters, and Other Government Proposals. The Utility’s financial results may continue to be impacted by the outcome of other current and future enforcement, litigation, and regulatory matters, including those described above as well as the outcome of the Safety Culture OII, the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction, including the oversight of the Utility’s probation and the potential recommendations by the Monitor, and potential penalties in connection with the Utility’s safety and other self-reports. (See Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) In addition, the Utility’s business profile and financial results could be impacted by the outcome of recent calls for municipalization of part or all of the Utility’s businesses, offers by municipalities and other public entities to acquire the electric assets of the Utility within their respective jurisdictions and calls for state intervention, including the possibility of a state takeover of the Utility. PG&E Corporation and the Utility cannot predict the nature, occurrence, timing or extent of any such scenario, and there can be no assurance that any such scenario would not involve significant ownership or management changes to PG&E Corporation or the Utility, including by the state of California. Further, certain parties filed notices of appeal with respect to the Confirmation Order, including provisions related to the injunction contained in the Plan that channels certain pre-petition fire-related claims to trusts to be satisfied from the trusts’ assets. There can be no assurance that any such appeal will not be successful and, if successful, that any such appeal would not have a material adverse effect on PG&E Corporation and the Utility.

For more information about the risks that could materially 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 2019 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” above for a list of some of the factors that may cause actual results to differ materially. PG&E Corporation and the Utility are unable 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

The following discussion presents PG&E Corporation’s and the Utility’s operating results for the three and nine months ended September 30, 2020 and 2019. See “Key Factors Affecting Financial Results” above for further discussion about factors that could affect future 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) attributable to common shareholders for the three and nine months ended September 30, 2020 and 2019:


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
Consolidated Total	$	83	$	(1,619)	$	(1,518)	$	(4,039)
PG&E Corporation	(84)		(6)		(1,656)		(2)
Utility	$	167	$	(1,613)	$	138	$	(4,037)

PG&E Corporation’s net loss primarily consists of income taxes, interest expense on long-term debt, reorganization items, net, including approximately $1.5 billion in expense related to the Backstop Commitment premium and Additional Backstop Premium Shares in the second quarter of 2020, which is not deductible for tax purposes.

Utility

The table below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2020 and 2019. 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 energy procurement costs) and the corresponding revenues the Utility is authorized to collect to recover such costs do not impact earnings.

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


	Three Months Ended September 30, 2020						Three Months Ended September 30, 2019
	Revenues/Costs:						Revenues/Costs:
(in millions)	That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility
Electric operating revenues	$	2,392	$	1,418	$	3,810	$	2,232	$	1,322	$	3,554
Natural gas operating revenues	896		176		1,072		714		164		878
Total operating revenues	3,288		1,594		4,882		2,946		1,486		4,432
Cost of electricity	—		1,114		1,114		—		1,070		1,070
Cost of natural gas	—		90		90		—		68		68
Operating and maintenance	1,877		434		2,311		1,816		392		2,208
Wildfire-related claims, net of insurance recoveries	25		—		25		2,548		—		2,548
Wildfire fund expense	120		—		120		—		—		—
Depreciation, amortization, and decommissioning	845		—		845		840		—		840
Total operating expenses	2,867		1,638		4,505		5,204		1,530		6,734
Operating income (loss)	421		(44)		377		(2,258)		(44)		(2,302)
Interest income	5		—		5		18		—		18
Interest expense	(323)		—		(323)		(52)		—		(52)
Other income, net	57		44		101		13		44		57
Reorganization items, net	(82)		—		(82)		(69)		—		(69)
Income (loss) before income taxes	$	78	$	—	$	78	$	(2,348)	$	—	$	(2,348)
Income tax benefit (1)					(92)						(738)
Net income (loss)					170						(1,610)
Preferred stock dividend requirement (1)					3						3
Income (loss) Attributable to Common Stock					$	167					$	(1,613)

(1) These items impacted earnings for the three months ended September 30, 2020 and 2019.


	Nine Months Ended September 30, 2020						Nine Months Ended September 30, 2019
	Revenues/Costs:						Revenues/Costs:
(in millions)	That Impacted Earnings		That Did Not Impact Earnings		Total Utility		That Impacted Earnings		That Did Not Impact Earnings		Total Utility
Electric operating revenues	$	6,851	$	3,434	$	10,285	$	6,017	$	3,275	$	9,292
Natural gas operating revenues	2,592		844		3,436		2,300		794		3,094
Total operating revenues	9,443		4,278		13,721		8,317		4,069		12,386
Cost of electricity	—		2,418		2,418		—		2,506		2,506
Cost of natural gas	—		508		508		—		515		515
Operating and maintenance	4,937		1,484		6,421		5,071		1,181		6,252
Wildfire-related claims, net of insurance recoveries	195		—		195		6,448		—		6,448
Wildfire fund expense	293		—		293		—		—		—
Depreciation, amortization, and decommissioning	2,574		—		2,574		2,433		—		2,433
Total operating expenses	7,999		4,410		12,409		13,952		4,202		18,154
Operating income (loss)	1,444		(132)		1,312		(5,635)		(133)		(5,768)
Interest income	33		—		33		61		—		61
Interest expense	(764)		—		(764)		(213)		—		(213)
Other income, net	155		132		287		54		133		187
Reorganization items, net	(286)		—		(286)		(237)		—		(237)
Income (loss) before income taxes	$	582	$	—	$	582	$	(5,970)	$	—	$	(5,970)
Income tax provision (benefit) (1)					434						(1,943)
Net income (loss)					148						(4,027)
Preferred stock dividend requirement (1)					10						10
Income (loss) Attributable to Common Stock					$	138					$	(4,037)

(1) These items impacted earnings for the nine months ended September 30, 2020 and 2019.

Utility Revenues and Costs that Impacted Earnings

The following discussion presents the Utility’s operating results for the three and nine months ended September 30, 2020 and 2019, focusing on revenues and expenses that impacted earnings for these periods.

Operating Revenues

The Utility’s electric and natural gas operating revenues that impacted earnings increased by $342 million, or 12%, and $1,126 million, or 14%, in the three and nine months ended September 30, 2020, respectively, compared to the same periods in 2019, primarily due to additional revenues recorded pursuant to the TO20 rate case and cost recovery of capital expenditures related to the 2011-2014 GT&S rate case. In addition, the portion of authorized revenues related to interest expense on pre-petition debt was deferred as a regulatory liability and reduced revenues that impacted earnings during the three and nine months ended September 30, 2019 with no comparable impacts in the same periods in 2020.

Operating and Maintenance

The Utility’s operating and maintenance expenses that impacted earnings increased by $61 million or 3% in the three months ended September 30, 2020, compared to the same period in 2019, primarily due to $75 million in previously deferred CEMA costs recorded in conjunction with interim rate relief (see “2018 CEMA Application” below) in the three months ended September 30, 2020, with no comparable costs in the same period in 2019. In addition, bad debt expense increased in the three months ended September 30, 2020, as compared to the same period in 2019 as a result of the COVID-19 pandemic. The Utility also experienced increased labor and contract costs in the three months ended September 30, 2020, compared to the same period in 2019. These increases were partially offset by $237 million in disallowed costs for previously incurred capital expenditures in excess of adopted amounts in the 2019 GT&S rate case incurred in the three months ended September 30, 2019, with no corresponding charges during the same period in 2020.

The Utility’s operating and maintenance expenses that impacted earnings decreased by $134 million, or 3%, in the nine months ended September 30, 2020, compared to the same period in 2019, primarily due to a reduction in clean-up costs related to the 2018 Camp fire of $237 million (the Utility recorded $265 million of clean-up and repair costs relating to the 2018 Camp fire incurred in the nine months ended September 30, 2019, compared to $28 million in restoration and rebuild costs related to the 2018 Camp fire in the same period in 2020). Additionally, the Utility recorded $237 million in disallowed costs for previously incurred capital expenditures in excess of adopted amounts in the 2019 GT&S rate case in the nine months ended September 30, 2019, with no corresponding charges during the same period in 2020. These decreases were partially offset by $225 million in previously deferred CEMA costs recorded in conjunction with interim rate relief (see “2018 CEMA Application” below) in the nine months ended September 30, 2020, with no comparable costs in the same period in 2019. In addition, bad debt expense increased in the nine months ended September 30, 2020, as compared to the same period in 2019 as a result of the COVID-19 pandemic. Finally, the Utility incurred $35 million of clean-up and repair costs relating to the 2019 Kincade fire incurred in the nine months ended September 30, 2020, with no comparable charges in the same period in 2019.

Wildfire-related claims, net of insurance recoveries

Costs related to wildfires that impacted earnings decreased by $2.5 billion, or 99%, in the three months ended September 30, 2020, compared to the same period in 2019. The Utility recognized pre-tax charges of $526 million and $2.0 billion associated with the 2018 Camp fire and 2017 Northern California wildfires, respectively, for the three months ended September 30, 2019, compared to $25 million in pre-tax charges to the 2019 Kincade fire in the three months ended September 30, 2020.

Costs related to wildfires that impacted earnings decreased by $6.3 billion, or 97%, in the nine months ended September 30, 2020, compared to the same period in 2019. The Utility recognized pre-tax charges of $625 million related to the 2019 Kincade fire, partially offset by $430 million in insurance recoveries for the nine months ended September 30, 2020, with no corresponding charges during the same period in 2019. Additionally, the Utility recognized pre-tax charges of $2.4 billion and $4.0 billion associated with the 2018 Camp fire and 2017 Northern California wildfires, respectively, for the nine months ended September 30, 2019, with no corresponding charges during the same period in 2020.

(See “Item 1A. Risk Factors” in the 2019 Form 10-K, as updated in “Item 1A. Risk Factors” in this Form 10-Q, and Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.)

Wildfire fund expense

Wildfire fund expense that impacted earnings increased by $120 million, or 100%, and $293 million or 100%, in the three and nine months ended September 30, 2020, respectively, compared to the same periods in 2019. In 2020, the Utility became eligible to participate in the Wildfire Fund and as a result recorded amortization expense related to the Wildfire Fund coverage received from the effective date of AB 1054 through September 30, 2020.

(See Notes 3 and 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 $5 million, or 1%, and $141 million, or 6%, in the three and nine months ended September 30, 2020, respectively, compared to the same periods in 2019, primarily due to capital additions and an increase in depreciation expense associated with the 2019 GT&S rate case.

Interest Income

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

Interest Expense

Interest expense that impacted earnings increased by $271 million, or 521%, and $551 million, or 259%, in the three and nine months ended September 30, 2020, respectively, compared to the same periods in 2019, primarily due to the cessation of interest accruals on outstanding pre-petition debt in 2019 in connection with the Chapter 11 Cases. In the fourth quarter of 2019, the Utility concluded that interest was probable of being an allowed claim and resumed recording interest on pre-petition debt subject to compromise. Additionally, in the third quarter of 2020, the Utility started recording interest related to new debt issued in connection with emergence from Chapter 11.

Other Income, Net

Other income, net increased by $44 million, or 338%, and $101 million or 187%, in the three and nine months ended September 30, 2020, respectively, compared to the same periods in 2019, primarily due to lower pension expense resulting from higher than expected return on plan assets.

Reorganization items, net

Reorganization items, net increased by $13 million, or 19% in the three months ended September 30, 2020, compared to the same period in 2019, primarily due to an increase of $7 million of expenses directly associated with the Utility’s Chapter 11 filing and an decrease in interest income of $6 million.

Reorganization items, net increased by $49 million, or 21% in the nine months ended September 30, 2020, compared to the same period in 2019, primarily due to an increase of $115 million of expenses directly associated with the Utility’s Chapter 11 filing and a decrease in interest income of $28 million, offset by a decrease in DIP financing costs of $94 million.

(See “Item 1A. Risk Factors” in the 2019 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 Expense (Benefit)

Income tax benefit decreased by $646 million in the three months ended September 30, 2020, as compared to the same period in 2019, primarily due to a pre-tax loss in 2019 compared to pre-tax income in 2020.

Income tax expense increased by $2.4 billion, in the nine months ended September 30, 2020, as compared to the same period in 2019, primarily due to a write-off of a deferred tax asset associated with the decline in value of PG&E Corporation stock contributed into the Fire Victim’s Trust in 2020. Additionally, there was a pre-tax loss in 2019 compared to pre-tax income in 2020.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
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)	(17.8)	%	7.5	%	30.9	%	7.6	%
Effect of regulatory treatment of fixed asset differences (2)	(113.5)	%	2.4	%	(48.1)	%	3.8	%
Bankruptcy and emergence (3)	1.4	%	—		75.2	%	—	%
Other, net	(8.0)	%	0.5	%	(4.5)	%	0.2	%
Effective tax rate	(116.9)	%	31.4	%	74.5	%	32.6	%

(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. 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 2020 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.

(3) Includes an adjustment of the measurement of the deferred tax asset associated with the difference between the liability recorded related to the TCC RSA and the ultimate value of PG&E Corporation stock contributed to the Fire Victim Trust.

Utility Revenues and Costs that Did Not Impact Earnings

Fluctuations in revenues that did not impact earnings are primarily driven by 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. Cost of electricity also includes net sales (Utility owned generation and third parties) in the CAISO electricity markets. (See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) The Utility’s total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility’s own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of electricity.


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
Cost of purchased power, net	$	1,043	$	1,001	$	2,228	$	2,296
Fuel used in generation facilities	71		69		190		210
Total cost of electricity	$	1,114	$	1,070	$	2,418	$	2,506

Cost of Natural Gas

The Utility’s cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. (See Note 8 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) The Utility’s cost of natural gas is impacted by the market price of natural gas, changes in the cost of storage and transportation, and changes in customer demand.


	Three Months Ended September 30,				Nine Months Ended September 30,
(in millions)	2020		2019		2020		2019
Cost of natural gas sold	$	56	$	42	$	411	$	433
Transportation cost of natural gas sold	34		26		97		82
Total cost of natural gas	$	90	$	68	$	508	$	515

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

As a result of PG&E Corporation’s and the Utility’s emergence from Chapter 11 on July 1, 2020, substantial doubt has been alleviated regarding the Company’s ability to meet its obligations as they become due within one year after the date of the accompanying Condensed Consolidated Financial Statements.

As of and subsequent to the Effective Date, the Utility’s ability to fund operations, finance capital expenditures, make scheduled principal and interest payments, and make distributions to PG&E Corporation depends on the levels of its operating cash flows and access to the capital and credit markets. The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of capital. The Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% equity and 48% debt and preferred stock and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs. On May 28, 2020, the CPUC approved a final decision in the Chapter 11 Proceedings OII, which, among other things, grants the Utility a temporary, five-year waiver from compliance with its authorized capital structure for the financing in place upon the Utility’s exit from Chapter 11.

PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, and fund equity contributions to the Utility, depends on the level of cash on hand, cash distributions received from the Utility, and PG&E Corporation’s access to the capital and credit markets.

In 2019, as a result of the initiation of the Chapter 11 Cases, each of Moody’s, Fitch, and S&P withdrew its credit ratings for PG&E Corporation and the Utility. As a result of PG&E Corporation’s and the Utility’s credit ratings ceasing to be rated at investment grade, the Utility was required to post collateral under certain of its commodity purchase agreements and certain other obligations. On June 15, 2020, the agencies re-commenced rating the Utility and PG&E Corporation. The Utility and PG&E Corporation were assigned Ba2, BB, and BB- as their issuer credit ratings by Moody’s, Fitch, and S&P, respectively. Additionally, Moody’s assigned a B1 rating to PG&E Corporation’s Senior Secured debt, a Baa3 rating to the Utility’s Senior Secured debt, and a B1 rating to the Utility’s preferred stock. Fitch assigned a BB rating to PG&E Corporation’s Senior Secured debt, a BBB- rating to the Utility’s Senior Secured debt, and a BB rating to the Utility’s preferred stock. Lastly, S&P assigned a BB- and BBB- rating to PG&E Corporation’s and the Utility’s Senior Secured debt, respectively.

As a result of the outbreak of COVID-19, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could continue to be significantly affected. The Utility continues to evaluate the overall impact of the COVID-19 pandemic; however, the Utility expects a significant impact on monthly cash collections as long as current circumstances persist, including the moratorium on service disconnections for residential and small business customers and an observed reduction in non-residential electrical load. The Utility’s customer energy accounts receivable balances over 30 days outstanding as of September 30, 2020, were approximately $696 million, or $310 million higher as compared to the corresponding month in 2019. The Utility is unable to estimate the portion of the increase directly attributable to the COVID-19 pandemic. The Utility expects to continue experiencing an impact on monthly cash collections in 2020 and for as long as current COVID-19 circumstances persist. The reduction in cash collections from customers may be partially offset by reductions in discretionary spending or potential regulatory impacts.

The outbreak of COVID-19 and the resulting economic conditions and government orders have and will continue to have a significant adverse impact on the Utility’s customers and, as a result, these circumstances have and will continue to impact the Utility for an indeterminate period of time. Although the Utility is seeking regulatory relief to mitigate the impact of the consequences of the COVID-19 pandemic, there can be no assurance that any relief is forthcoming or that, if any relief measures are implemented, the timing that any such relief would impact the Utility. On April 16, 2020, the CPUC approved a resolution that authorizes utilities to establish memorandum accounts to track incremental costs associated with complying with the customer protections described within the resolution. On May 1, 2020, the Utility filed an advice letter with the CPUC, describing all reasonable and necessary actions to implement emergency customer protections through April 16, 2021, which was subsequently updated on June 2, 2020, and July 15, 2020, to modify and clarify the filing based on CPUC guidance. On July 27, 2020, the CPUC approved the Utility’s advice letter. (See “Emergency Authorization and Resolution Directing Utilities to Implement Emergency Customer COVID-19 Protections” below for more information.)

Cash and Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to cash and cash equivalents, the Utility holds restricted cash that primarily consists of cash held in escrow to be used to pay bankruptcy related professional fees.

Financial Resources

DIP Credit Agreement

In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement, which received final approval from the Bankruptcy Court on March 27, 2019.

On July 1, 2020, the DIP Facilities were repaid in full and all commitments thereunder were terminated in connection with emergence from Chapter 11.

Equity Financings

On July 23, 2020, PG&E Corporation sent a notice of termination to the managers of the Amended and Restated Equity Distribution Agreement, dated as of February 17, 2017, effectively terminating the agreement on that date. During the nine months ended September 30, 2020, there were no issuances under this agreement.

In connection with its emergence from Chapter 11, in July 2020, PG&E Corporation issued for gross proceeds of approximately $9.0 billion (i) 423.4 million shares of common stock in the Common Stock Offering, (ii) 342.1 million shares of common stock pursuant to the Investment Agreement, (iii) forward stock purchase contracts to the Backstop Parties pursuant to the Forward Stock Purchase Agreement and (iv) 14.5 million Equity Units in the Equity Unit Offering.

In August 2020, PG&E Corporation issued (i) 1.45 million Equity Units to the Equity Units Underwriters upon their exercise of their over-allotment option to purchase up to 1.45 million additional Equity Units and (ii) 42.3 million shares to the Backstop Parties pursuant to the Forward Stock Purchase Agreements.

The prepaid forward stock purchase contract portion of the Equity Units issued in July and August 2020 represents the right of the unitholders to receive, on the settlement date, between 125 million and 153 million shares, and between 12.5 million and 15.3 million shares, respectively, of PG&E Corporation common stock, based on the value of PG&E Corporation common stock. The common stock received was based on the value of PG&E Corporation common stock over a measurement period specified in the purchase contracts and subject to certain adjustments as provided therein. The settlement date of the purchase contracts is August 16, 2023, subject to acceleration or postponement as provided in the purchase contracts. Such gross proceeds were used to fund distributions under the Plan.

For the nine months ended September 30, 2020, PG&E Corporation made equity contributions to the Utility of $12.9 billion in cash and 477 million shares of PG&E Corporation common stock. Such shares were transferred to the Fire Victim Trust.

For more information, see Note 6 to the Notes to the Condensed Consolidated Financial Statements in Item 1.

Debt Financings

Utility

On June 19, 2020, the Utility completed the sale of (i) $500 million aggregate principal amount of Floating Rate First Mortgage Bonds due June 16, 2022, (ii) $2.5 billion aggregate principal amount of 1.75% First Mortgage Bonds due June 16, 2022, (iii) $1 billion aggregate principal amount of 2.10% First Mortgage Bonds due August 1, 2027, (iv) $2 billion aggregate principal amount of 2.50% First Mortgage Bonds due February 1, 2031, (v) $1 billion aggregate principal amount of 3.30% First Mortgage Bonds due August 1, 2040, and (vi) $1.925 billion aggregate principal amount of 3.50% First Mortgage Bonds due August 1, 2050 (collectively, the “Mortgage Bonds”). The proceeds of the Mortgage Bonds were deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and among the Escrow Agent and the Utility. On July 1, 2020, the net proceeds from the sale of the Mortgage Bonds were released from escrow and, together with the net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of the Utility and PG&E Corporation in accordance with the terms and conditions contained in the Plan.

On the Effective Date, pursuant to the Plan, the Utility issued approximately $11.9 billion of its first mortgage bonds (collectively, the “New Mortgage Bonds”) in satisfaction of certain of its pre-petition senior unsecured debt.

For more information, see “Long-Term Debt” in Note 5 to the Notes to the Condensed Consolidated Financial Statements in Item 1.

PG&E Corporation

On June 23, 2020, PG&E Corporation obtained a $2.75 billion secured term loan under a term loan credit agreement (“the “Term Loan Agreement”). The Term Loan matures on the date that is five years after June 23, 2020, unless extended by PG&E Corporation pursuant to the terms of the Term Loan Agreement. The proceeds of the Term Loan were deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and among the Collateral Agent, the Escrow Agent, the Administrative Agent and PG&E Corporation. On July 1, 2020, the net proceeds from the Term Loan were released from escrow and were used to fund, in part, the transactions contemplated under the Plan.

In accordance with the Term Loan Credit Agreement, PG&E Corporation is required to repay the principal amount outstanding on the Term Loan by $6.875 million on the last day of each quarter.

Additionally, on June 23, 2020, PG&E Corporation completed the sale of (i) $1.0 billion aggregate principal amount of 5.00% Senior Secured Notes due July 1, 2028 and (ii) $1.0 billion aggregate principal amount of 5.25% Senior Secured Notes due July 1, 2030 (collectively, the “Notes”). The proceeds of the Notes were deposited into an account at The Bank of New York Mellon Trust Company, N.A., as Escrow Agent, which proceeds were held by the Escrow Agent as collateral pursuant to an escrow agreement by and amount the Escrow Agent and PG&E Corporation. On July 1, 2020, the net proceeds from the sale of the Notes were released from escrow and, together with the net proceeds from certain other Plan financing transactions, were used to effectuate the reorganization of PG&E Corporation and the Utility in accordance with the terms and conditions contained in the Plan.

For more information, see “Long-Term Debt” in Note 5 to the Notes to the Condensed Consolidated Financial Statements in Item 1.

Credit Facilities

Utility

On July 1, 2020, the Utility entered into a $3.5 billion revolving credit agreement (the “Utility Revolving Credit Agreement”) with JPM, and Citibank, N.A. as co-administrative agents and Citibank, N.A., as designated agent. The Utility Revolving Credit Facility has tenor of three years, subject to two one-year extension options. The proceeds from the Utility Revolving Credit Facility were used in part to fund transactions contemplated under the Plan and are intended to finance working capital needs, capital expenditures and other general corporate purposes of the Utility and its subsidiaries.

In addition, on July 1, 2020, the Utility obtained a $3.0 billion secured term loan under a term loan credit agreement (the “Utility Term Loan Credit Agreement”) with JPM, as administrative agent, and the other lenders from time to time party thereto. The facilities under the Utility Term Loan Credit Agreement consist of a $1.5 billion 364-day term loan facility (the “Utility 364-Day Term Loan Facility”) and a $1.5 billion 18-month term loan facility (the “Utility 18-Month Term Loan Facility”). The maturity date for the Utility 364-Day Term Loan Facility is June 30, 2021 and the maturity date for the Utility 18-Month Term Loan Facility is January 1, 2022. The proceeds from the Utility Term Loan Credit Facility were used to fund transactions contemplated under the Plan.

At September 30, 2020, the Utility had fully drawn on its $3.0 billion term loan credit facilities and had $1.7 billion available under its $3.5 billion revolving credit facility.

For more information, see “Credit Facilities” in Note 5 to the Condensed Consolidated Financial Statements in Item 1.

PG&E Corporation

On July 1, 2020, PG&E Corporation entered into a $500 million revolving credit agreement (the “Corporation Revolving Credit Agreement”) with JPM, as administrative agent and collateral agent. The Corporation Revolving Credit Agreement has a maturity date three years after its Effective Date, subject to two one-year extensions at the option of PG&E Corporation. The proceeds from the Corporation Revolving Credit Facility will be used to finance working capital needs, capital expenditures and other general corporate purposes of PG&E Corporation and its subsidiaries.

At September 30, 2020, PG&E Corporation did not have any borrowings outstanding under its revolving credit facility.

For more information, see “Credit Facilities” in Note 5 to the Condensed Consolidated Financial Statements in Item 1.

Accounts Receivable Financing

Although PG&E AR Facility, LLC is a wholly owned subsidiary of the Utility whose financial results are consolidated for accounting purposes with the Utility, PG&E AR Facility, LLC is legally separate from the Utility. The assets of PG&E AR Facility, LLC (including the accounts receivables) are not available to creditors of the Utility or PG&E Corporation, and its accounts receivable are not legally assets of the Utility or PG&E Corporation. The Receivables Securitization Program will be accounted for as a secured financing. When amounts are received from the Lenders, the pledged receivables and the corresponding debt will be included in Accounts receivable and Short-term borrowings, respectively, on the Condensed Consolidated Balance Sheets.

Dividends

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.

On March 20, 2020, PG&E Corporation and the Utility filed a Case Resolution Contingency Process Motion with the Bankruptcy Court that includes a dividend restriction for PG&E Corporation. According to the dividend restriction, PG&E Corporation “will not pay common dividends until it has recognized $6.2 billion in non-GAAP core earnings following the Effective Date” of the Plan. The Bankruptcy Court entered the order approving the motion on April 9, 2020.

In addition, the Corporation Revolving Credit Agreement will require that PG&E Corporation (1) maintain a ratio of total consolidated debt to consolidated capitalization of no greater than 70% as of the end of each fiscal quarter and (2) if revolving loans are outstanding as of the end of a fiscal quarter, a ratio of adjusted cash to fixed charges, as of the end of such fiscal quarter, of at least 150% prior to the date that PG&E Corporation first declares a cash dividend on its common stock and at least 100% thereafter.

Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of the Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant. As of September 30, 2020, it is uncertain as to when PG&E Corporation and the Utility will commence the payment of dividends on their common stock and when the Utility will commence the payment of dividends on its preferred stock.

For more information on dividends, see “Dividends” in Note 6 to the Condensed Consolidated Financial Statements.

PG&E Corporation Cash Flows - Holding Company

The PG&E Corporation consolidated cash flows consist primarily of cash flows related to the Utility, which are discussed in the “Utility Cash Flows” section below.

There was no material change to PG&E Corporation’s standalone cash flows from operating and investing activities for the periods presented.

PG&E Corporation’s standalone cash flows from financing activities decreased by $205 million during the nine months ended September 30, 2020, as compared to the same period in 2019. This decrease is due to PG&E Corporation’s cash equity contribution to the Utility of approximately $13 billion and long-term debt repayments of $650 million, with no similar payments made in 2019. This decrease is partially offset by cash received from long-term debt issuances of $4.7 billion, with no similar issuances in 2019, and cash received from common stock and equity units issued of $8.9 billion, as compared to common stock issuances of $85 million in 2019.

Cash provided by or used in financing activities is driven by PG&E Corporation’s standalone financing needs, which depends on the level of cash on hand, cash distributions received from the Utility, access to the capital and credit markets, and the maturity date or prepayment of existing debt instruments.

Utility Cash Flows

The Utility’s cash flows were as follows:


	Nine Months Ended September 30,
(in millions)	2020		2019
Net cash provided by (used in) operating activities	$	(19,170)	$	4,078
Net cash used in investing activities	(5,524)		(4,250)
Net cash provided by financing activities	23,982		1,416
Net change in cash, cash equivalents and restricted cash	$	(712)	$	1,244

Operating Activities

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash. During the nine months ended September 30, 2020, net cash provided by operating activities decreased by $23.2 billion compared to the same period in 2019. This decrease was primarily due to the payment of $18.8 billion in satisfaction of pre-petition wildfire-related claims (including claims associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire), and initial and first annual contributions made to the Wildfire Fund of $5.0 billion, with no similar payments made in 2019.

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

•the timing and amount of costs in connection with the Kincade fire;

•the timing and amount of costs in connection with the 2020 Zogg fire;

•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 and “Regulatory Matters” below for more information);

•the severity, extent and duration of the global COVID-19 pandemic and its impact on the Utility’s service territory, the ability of the Utility to collect on its customer invoices, the ability of the Utility’s customers to pay their utility bills in full and in a timely manner, the ability of the Utility to offset these effects, including with spending reductions and the ability of the Utility to recover from customers any losses incurred in connection with COVID-19, as well as the impact of COVID-19 on the availability or cost of financing;

•the timing and amounts of annual contributions to the Wildfire Fund and if necessary, the availability of funds to pay eligible claims for liabilities arising from future wildfires;

•the timing and amount of substantially increasing costs in connection with the 2019 and 2020 Wildfire Mitigation Plans that are not currently being recovered in rates (see “Regulatory Matters” below for more information);

•the timing and amount of premium payments related to wildfire insurance (see “Insurance Coverage” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1 for more information);

•the timing of and amount of the gain to be returned to customers from the sale of the SFGO; and

•the timing and outcomes of the 2020 GRC, FERC TO18, TO19 and TO20 rate cases, 2018 and 2019 CEMA applications, WEMA application, WMCE application, future applications for cost recovery of amounts recorded to the FRMMA, CPPMA and WMPMA, future cost of capital proceedings and other ratemaking and regulatory proceedings.

Investing Activities

Net cash used in investing activities increased by $1.3 billion during the nine months ended September 30, 2020 as compared to the same period in 2019 partially due to the payment of pre-petition vendor payables for capital expenditures as a result of emerging from Chapter 11. 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.

Cash paid by the Utility for capital expenditures was approximately $6.3 billion in 2019. 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 $7.5 billion in capital expenditures in 2020 and between $7.6 billion and $8.2 billion in 2021. Additionally, future cash flows from investing activities will be impacted by the timing of and amount received from the sale of the SFGO.

Financing Activities

Net cash provided by financing activities increased by $22.6 billion during the nine months ended September 30, 2020 as compared to the same period in 2019. This increase was primarily due to PG&E Corporation making a cash equity contribution to the Utility of approximately $13 billion and due to the Utility receiving $8.8 billion in proceeds from the issuance of first mortgage bonds, with no similar activity in 2019. Additionally, the Utility had net borrowings of $940 million under its revolving credit facility during the nine months ended September 30, 2020, with no similar activity in 2019 due to the Utility entering into the revolving credit agreement on July 1, 2020.

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 or prepayment 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 and matters described in “Part II. Other Information, Item 1. Legal Proceedings” below. 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, liquidity, and cash flows. In addition, PG&E Corporation and the Utility are involved in other enforcement and litigation matters described in the 2019 Form 10-K and “Part II. Other Information, Item 1. Legal Proceedings.”

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.

Upon the court’s request, on March 2, 2020, the Utility provided to the court its target number of contract tree trimmers for 2020, information regarding the Utility’s 2019 inspections of Tower 009/081 on the Cresta-Rio Oso 230 kV Transmission Line (the “Cresta-Rio Oso Line”), information regarding the relationship between priority codes set forth in the Utility’s Electric Transmission Preventive Maintenance Manual and the safety factors specified in General Order 95 promulgated by the CPUC, as well as the application of each to the C-hooks of interest on the Cresta-Rio Oso Line. In addition, on April 2, 2020, the Utility submitted a report to the court regarding the Utility’s March 19, 2020 collection of equipment from the Cresta-Rio Oso Line. On April 10, 2020, the TCC in the Utility’s Chapter 11 Cases and estimation proceedings filed a declaration from a TCC expert concerning Cresta-Rio Oso 230kV Transmission Line evidence collection and removal on March 19, 2020.

On April 29, 2020, the court issued an order imposing new conditions of probation.

On May 13, 2020, the Utility filed motions with the court asking that it reconsider the April 29, 2020 order and issue a stay on implementing the new conditions until it has had a chance to rule on the Utility’s request for reconsideration.

On May 14, 2020, the court issued an order staying the April 29, 2020 order and ordering certain other procedural actions. On June 24, 2020, after a hearing on the Utility’s motion for reconsideration, the Utility filed a joint brief with the Monitor overseeing its probation and the Department of Justice, outlining which actions, if any, the court should take regarding the conditions of the Utility’s probation. On July 1, 2020, the court issued a notice inviting comments from “any interested party . . . on whether and the extent to which these joint proposed probation conditions should be accepted.” One interested party filed comments on July 16, 2020, stating that the proposed probation conditions submitted by the joint parties were inadequate and should be rejected by the court. The CPUC also filed comments indicating it did not oppose the conditions agreed to by the Utility, the Monitor, and the Department of Justice.

On June 17, 2020, the court issued an order requiring the Utility to respond to each statement in the Butte County District Attorney’s report filed in the criminal prosecution of the Utility in connection with the 2018 Camp Fire entitled “People’s Statement of Factual Basis in Support of the Pleas and Sentencing Statement” that the Utility denies is true and provide the reason for the denial. The Utility filed its response on July 1, 2020.

On July 21, 2020, the court issued an order requiring the Utility, the Monitor, and the Department of Justice to clarify certain aspects of the proposed additional conditions of probation set forth in the June 24, 2020 joint submission. The Utility filed its response on July 28, 2020.

On July 24, 2020, the Utility submitted a report to the court to update the court on the condition of the Utility’s Caribou-Palermo 115 kV Transmission Line (the “Caribou-Palermo Line”). The Utility indicated in its report that energized lines in the same vicinity as the Utility’s de-energized Caribou-Palermo Line may have the potential to induce voltage and current onto the Caribou-Palermo line, despite the Caribou-Palermo line’s de-energized state. The Utility further indicated in its report the steps it has taken to mitigate this risk and additional steps that it will be taking in the future. The Utility also has notified the Monitor, its probation officer, the CPUC and the Butte County District Attorney of the facts and mitigation efforts set forth in its report.

On August 7, 2020, the court entered an order withdrawing the conditions of probation proposed in its April 29, 2020 order and adopting the new conditions jointly proposed by the Utility, the Monitor, and the Department of Justice on June 24, 2020. Among other things, these conditions require the Utility to staff an in-house vegetation inspection manager and approximately 30 additional field inspectors to oversee vegetation management work. Further, the Utility is required to implement a program to assess the age and expected useful life of certain electrical components in high fire-threat areas, incorporate this information into its risk-based asset management programs, and provide monthly progress reports to the Monitor. The Utility must also hire additional inspectors to oversee inspections of its transmission assets and implement a 90-day replacement requirement for cold end hardware in high fire-threat areas with an observed material loss approaching 50 percent.

On October 12, 2020, the court entered an order requesting that the Utility explain its role in the ignition of the 2020 Zogg fire. Regarding the Utility’s equipment removed by Cal Fire as part of Cal Fire’s investigation into the 2020 Zogg fire, the court ordered the Utility to describe, among other things, the location of the equipment when it was in use; whether the equipment was transmission line equipment, distribution line equipment, or substation equipment; and the extent of trimmed and untrimmed vegetation in the area near where Cal Fire took possession of the equipment.

On October 21, 2020, the court entered an additional order related to the 2020 Zogg fire, requesting that the Utility: (1) supply all documents, emails, text messages, reports, voicemails and any other materials related to “the decision to leave energized the line or circuit in question that possibly led to the Zogg Fire”; (2) identify the officer or other employee who made the decision to leave such line energized; (3) identify all others with any role in the decision or recommendation to leave such line energized; (4) describe “the sequence of all events that possibly relate to PG&E’s involvement in the ignition of the Zogg Fire” in chronological order; and (5) provide photographs or videos of the relevant scene. The Utility filed its response to both orders on October 26, 2020, including a detailed, chronologically ordered sequence of events potentially related to the 2020 Zogg fire.

On October 16, 2020, the federal Monitor overseeing the Utility’s probation filed a letter with the court, responding to the court’s “request for an update on the Monitor team’s field inspections of [the Utility’s] vegetation management and infrastructure inspection operations since last year.” On October 20, 2020, the court entered an order noting that “[t]he Monitor has found more exceptions per mile this year than from September to December of last year” and that “as of August 31, 2020, [the Utility] failed to conduct any enhanced, ignition-based climbing inspections of the 967 applicable transmission structures selected for 2020 inspections in high-fire threat districts.” The court requested that the Utility “explain these shortcomings and any other points in the Monitor’s letter it wishes to address” by November 3, 2020.

On October 26, 2020, the court entered an additional order related to the 2020 Zogg fire, requesting that the Utility “state the extent to which the line in question had been cleared of vegetation within the last five years and the extent to which its records or its contractor records showed there was any vegetation that needed to be cut, but was not yet cut in the general area where equipment was seized by authorities.” The Utility included information responsive to the October 26, 2020 order in its response submitted that day and plans to provide a supplemental response with additional information responsive to the October 26, 2020 order at a future date.

For more information on the Utility’s probation, see the 2019 Form 10-K.

The Utility expects to receive additional orders from the court in the future.

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 materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Discussed below are significant regulatory developments that have occurred since filing the 2019 Form 10-K.

Rate Cases

2020 Cost of Capital Proceeding

On December 19, 2019, the CPUC approved a final decision in the 2020 Cost of Capital proceeding, maintaining the Utility’s return on common equity at the 2019 level of 10.25% for the three-year period beginning January 1, 2020, as compared to 12% requested by the Utility. The Utility’s annual cost of capital adjustment mechanism also remains unchanged. The cost of capital adjustment mechanism can trigger changes in the Utility’s authorized ROE and cost of debt, if the 12-month average Moody’s Baa bond rate for the period ending September 30, 2020 were to be 100 basis points higher or lower than 4.5 percent (the benchmark). The adjustment to i) ROE would be one-half the basis point change in the bond rate from the benchmark, and ii) authorized cost of debt would be updated. The decision maintains the common equity component of the Utility’s capital structure at 52%, as requested by the Utility, and reduces its preferred stock component from 1% to 0.5%, also as requested by the Utility. The decision also approves the cost of debt requested by the Utility.

On May 28, 2020, the CPUC issued a decision in the OII to Consider PG&E Corporation’s and the Utility’s Plan of Reorganization that directed the Utility to submit an Advice Letter to update its authorized cost of debt within 30 days of the Effective Date of the Plan. On July 22, 2020, the Utility submitted an Advice Letter requesting to update the authorized cost of long-term debt to implement the interest cost savings resulting from the Utility’s exit financing. On August 20, 2020, the CPUC approved the Utility’s request to update the authorized cost of long-term debt from 5.16%, as authorized in December 2019, to 4.17% effective July 1, 2020.

For additional information, see the 2019 Form 10-K.

2017 General Rate Case

As previously disclosed, on September 13, 2019 the Utility submitted an advice letter containing a revised computation of its revenue requirement due to the effects of the Tax Act, which indicated a $282 million net reduction to the 2018 revenue requirement and a $291 million net reduction to the 2019 revenue requirement. The revised gas revenue requirements increased by $21 million and $11 million for years 2018 and 2019, respectively, and the revised electric revenue requirements decreased by $304 million and $302 million for years 2018 and 2019, respectively. On October 17, 2019, the CPUC approved the Utility’s advice letter. The Utility incorporated the gas revenue requirement increases into rates through its Annual Gas True-up advice letter beginning on January 1, 2020 and amortized over 12 months. The Utility incorporated the electric revenue requirement reductions into rates through its Annual Electric True-up advice letter beginning on May 1, 2020. The revenue requirement reduction of $175 million related to electric generation is amortized over 12 months and the 2018 revenue requirement reduction of $215 million related to electric distribution is amortized over 10 months. The Utility will incorporate the remaining 2019 revenue requirement reduction of $216 million related to electric distribution with other anticipated changes, such as the change in revenue requirement resulting from the 2020 GRC phase one decision. The IRS is expected to provide additional guidance on the average rate assumption method. This IRS guidance may impact the Utility’s calculation of the related revenue requirement. It is uncertain when the IRS guidance may be issued.

For additional information, see the 2019 Form 10-K.

2020 General Rate Case

On October 23, 2020, the assigned ALJs issued a PD in the Utility’s 2020 GRC proceeding. In this proceeding, the CPUC will determine the annual amount of base revenues (or “revenue requirements”) that the Utility will be authorized to collect from customers for electric distribution, natural gas distribution, and electric generation operations from 2020 through 2022. In the 2020 GRC proceedings, the CPUC will also provide the Utility an opportunity to earn its authorized rate of return.

The PD proposes to adopt most of the provisions in the settlement agreement that the Utility, together with the Public Advocates Office of the California Public Utilities Commission, TURN, CUE, SED and certain other settling parties jointly submitted to the CPUC on December 20, 2019 (the “settlement agreement”). The PD also proposes several modifications, including reduction of the Community Wildfire Safety Program (the “CWSP”) capital forecasts for 2021 and 2022. The PD includes less favorable procedural requirements for recovery of undercollections tracked by certain regulatory accounts and for closure of up to 10 customer service branch offices.

Revenue Requirements and Attrition Year Revenues

The PD proposes that the Utility’s 2019 authorized revenue requirement of $8.5 billion be increased by $585 million, effective January 1, 2020, to $9.102 billion, as requested in the settlement agreement. The PD revises the revenue requirement for 2021 and 2022 by reducing the Utility’s capital expenditure forecast for wildfire mitigation stated in the settlement agreement for 2021 and 2022. The PD provides for an additional increase of $339 million in 2021 to the authorized 2020 revenue requirement, or a 3.7% increase, and an additional increase of $344 million in 2022, or a 3.6% increase, as shown in the table below.


(in millions) Year Revenue Requirement	Increase Proposed in the Settlement (1)		Increase Recommended in the PD		Difference: Increase (Decrease) from the Settlement
2020	$	585	$	585	$	—
2021	316		339		23
2022	$	364	$	344	$	(20)

(1) The settlement and PD amounts reflect the requirement to exclude certain capital expenditures for wildfire mitigation from the Utility’s rate base pursuant to Assembly Bill (AB) 1054 and reflect a $10 million increase in 2020 revenues over the $575 million included in the settlement agreement as a result of updating for 2018 recorded capital additions, as stipulated in the settlement agreement.

The PD proposes to adopt the revenue requirements for lines of business and cost categories proposed for 2020 in the settlement agreement. The following table shows the revenue requirements proposed in both the settlement agreement and the PD by line of business and cost category, as well as the differences between the 2019 authorized revenue requirements and the amounts in the settlement agreement adopted in the PD.


(in millions) Lines of Business:	Amounts Proposed in Settlement Agreement and in the PD		Increase / (Decrease) 2019 Amounts vs. Settlement Agreement and the PD
Electric distribution	$	4,800	$	436	10.0	%
Gas distribution	2,013		51		2.6	%
Electric generation	$	2,289	$	98	2.5	%
Total revenue requirements	$	9,102	$	585	6.9	%

Cost Category:
Operations and maintenance	$	2,073	$	128
Customer services	277		(61)
Administrative and general	1,203		250
Less: Revenue credits	(195)		(43)
Franchise fees, taxes other than income, and other adjustments	214		33
Depreciation (including costs of asset removal), return, and income taxes	5,530		278
Total revenue requirements	$	9,102	$	585

While the PD would adopt most of the settlement agreement, it proposes changes to the cost recovery process proposed in the settlement agreement for liability insurance, vegetation management and wildfire mitigation that are less favorable, by requiring that the Utility file applications for recovery of costs above 130% of the authorized amounts instead of addressing such costs in an advice letter. In addition, the PD proposes reductions to wildfire mitigation capital in the CWSP to $603 million for each of 2021 and 2022, as compared to $931 million in 2021 and $1.15 billion in 2022 proposed in the settlement agreement.

100

Rate Base and Capital Additions

The PD proposes the 2019 weighted-average rate base of $27.7 billion to be increased by $1.7 billion, effective January 1, 2020, to $29.5 billion, or a 6.2% increase. The PD revises weighted average rate base amounts for 2021 and 2022, providing for a rate base of $30.9 billion in 2021, a 5.1% increase, and $32.7 billion in 2022, or a $5.5% increase, as shown in the table below. The rate base amounts for 2020 through 2022 proposed in the PD include $1.95 billion in total of forecast capital spend that will not earn an equity return, pursuant to AB 1054, or $147 million for August to December 2019, and $601 million for each of 2020, 2021 and 2022. (The rate base amounts proposed in the settlement agreement included $147 million for August to December 2019, $601 million for 2020, $930 million for 2021 and $1.15 billion for 2022, for a total of $2.83 billion in forecast capital spend without an equity return.)


(in millions) Year Rate Base	Increase Proposed in the Settlement		Increase Recommended in the PD		Difference: Increase (Decrease) from the Settlement
2020	$	1,717	$	1,717	$	—
2021	1,603		1,493		(110)
2022	$	1,989	$	1,716	$	(273)

Over the 2020-2022 GRC period, the PD provides average annual capital investments of approximately $4.3 billion in electric distribution, natural gas distribution and electric generation infrastructure, as compared to $4.5 billion in the settlement agreement. (While the settlement agreement proposed overall revenue requirement increases for 2021 and 2022, it did not specify capital expenditures for those years.)

Consistent with the Utility’s GRC application, the settlement agreement did not propose funding for claims resulting from the 2017 Northern California wildfires or the 2018 Camp fire. Also, the Utility did not seek recovery of compensation of PG&E Corporation’s and the Utility’s officers.

The CPUC could vote on the PD no earlier than at its meeting scheduled for December 3, 2020. Settling parties’ notice to accept the PD or motion protesting the changes to the settlement are due 15 days after the date the Commission formally issues its final decision.

On June 30, 2020, the Utility filed the 2020 Risk Assessment Mitigation Phase Report.

In accordance with a January 16, 2020 CPUC decision in its OIR to Develop a Risk-Based Decision-Making Framework to Evaluate Safety and Reliability Improvements and Revise the GRC Plan the decision, the Utility is required to file with the CPUC on June 30, 2021 a single “general rate case” application requesting integrated GRC and GT&S related revenue requirements for test year 2023 and three attrition years.

For additional information, see the 2019 Form 10-K.

2015 Gas Transmission and Storage Rate Case

As previously disclosed, 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 forecast to be 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 audit report was released June 2, 2020 and did not result in any additional disallowances. The 2015 GT&S decision authorized the Utility to seek recovery of costs not otherwise disallowed through a separate application upon completion of the audit. On July 31, 2020, the Utility filed an application seeking recovery of $512 million (on a recorded basis). On October 16, 2020, the assigned commissioner issued a scoping memo establishing the scope and schedule for the proceeding. The scoping memo requires the Utility to provide supplemental testimony on January 20, 2021 addressing the reasonableness of the capital expenditures. The scoping memo calls for the issuance of a proposed decision in the fourth quarter of 2021.

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As previously disclosed, as a result of the Tax Act, on October 17, 2019, the CPUC approved the Utility’s advice letter including a revised computation of the effects of the Tax Act on the revenue requirements, resulting in a $61 million reduction to the 2018 revenue requirement. The Utility incorporated the revenue requirement reduction into rates through its Annual Gas True-up advice letter beginning January 1, 2020 and amortized over 12 months. The IRS is expected to provide additional guidance on the average rate assumption method. This IRS guidance may impact the Utility’s calculation of the related revenue requirement. It is uncertain when the IRS guidance may be issued.

For additional information, see the 2019 Form 10-K.

2019 Gas Transmission and Storage Rate Case

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

As previously disclosed, on January 16, 2020, the CPUC approved a final decision in its OIR to Develop a Risk-Based Decision-Making Framework to Evaluate Safety and Reliability Improvements and Revise the GRC Plan, as a result of which the Utility will be required to combine the GRC and GT&S rate cases starting with the 2023 GRC. In accordance with the decision, on June 30, 2021, the Utility is required to file with the CPUC a single “general rate case” application requesting integrated GRC and GT&S related revenue requirements for test year 2023 and three attrition years.

For additional information, see the 2019 Form 10-K.

Transmission Owner Rate Cases

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

As previously disclosed, 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. 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. Those rate case decisions were remanded to FERC for further proceedings consistent with the Court of Appeals’ opinion.

On July 18, 2019, FERC issued its order on remand reaffirming its prior grant of the Utility’s request for the 50-basis point ROE adder. On August 16, 2019, a number of parties filed for rehearing of that order.

On March 17, 2020, FERC issued its order denying the requests for rehearing. On May 11, 2020, the CPUC and a number of other parties filed a petition for review of FERC’s orders in the Ninth Circuit Court of Appeals. Briefing on the appeal will be completed in December 2020. The Utility is unable to predict the timing and outcome of this proceeding.

For additional information, see the 2019 Form 10-K.

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

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

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Also, as previously disclosed, on October 1, 2018, the ALJ issued an initial decision in the TO18 rate case proposing a ROE of 9.13% compared to the Utility’s request of 10.90%, and an estimated composite depreciation rate of 2.96% compared to the Utility’s request of 3.25%. 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. Finally, the ALJ rejected the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. Application of the operating and maintenance labor rates would result in an allocation of 6.15% of common plant to FERC in comparison to 8.84% under the Utility’s direct assignment method. The Utility and intervenors filed initial briefs on October 31, 2018, and reply briefs on November 20, 2018, in response to the ALJ’s initial decision.

On October 15, 2020, FERC issued an order that affirmed in part and reversed in part the initial decision. The order reopens the record for the limited purpose of allowing the participants to the proceeding an opportunity to present written evidence concerning FERC’s revised ROE methodology adopted in FERC Opinion No. 569-A, issued on May 21, 2020, which refined the methodology it established in Opinion No. 569 for setting the ROE that electric utilities are authorized to earn on electric transmission investments. Initial briefs are due 60 days from the date of this decision and responses are due 30 days later. In addition, the order approves depreciation rates that yield an estimated composite depreciation rate of 2.94% compared to the Utility’s request of 3.25%. Further, the order reduces forecasted capital, operations and maintenance, and cost of debt expense to actual costs incurred for the rate case period. Finally, the order rejected the Utility’s direct assignment of common plant to FERC and required the allocation of all common plant between CPUC and FERC jurisdiction be based on operating and maintenance labor ratios. Aside from the ultimate outcome of the common plant allocation and ROE methodology, which is subject to further briefing, FERC’s October 15, 2020 order is not expected to result in a material impact on the Utility’s financial condition, results of operations, liquidity, and cash flows. Some of the issues that will be decided in a final and unappealable TO18 decision, including the common plant allocation, will also be incorporated into the Utility’s current formula rate, described below under the TO20 rate case.

In addition to the additional return on equity briefing, the order is subject to requests for rehearing and potential appellate review of any rehearing order. The Utility is unable to predict the timing and outcome of this proceeding.

For additional information, see the 2019 Form 10-K.

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

As previously disclosed, on July 27, 2017, the Utility filed its TO19 rate case at the FERC requesting a 2018 retail electric transmission revenue requirement of $1.79 billion, a $74 million increase over the proposed 2017 revenue requirement of $1.72 billion. The forecasted network transmission rate base for 2018 was $6.9 billion. The Utility sought a 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.

Also, as previously disclosed, on September 21, 2018, the Utility filed an all-party settlement with the FERC in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined upon the issuance of a final, non-appealable TO18 decision. Additionally, if the Court of Appeals were to determine that the Utility was not entitled to the 50 basis point incentive adder for the Utility’s continued CAISO participation, then the Utility would be obligated to make a refund to customers of approximately $25 million. See Transmission Owner Rate Cases for 2015 and 2016 above for a discussion of the incentive adder. On December 20, 2018, the FERC issued an order approving the all-party settlement.

For additional information, see the 2019 Form 10-K.

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

As previously disclosed, 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.

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

The parties conducted several settlement conferences throughout 2019. On March 31, 2020, the Utility filed a partial settlement with FERC that resolves issues regarding the inputs, and methods used in the formula rate consistent with FERC precedent. In addition, the partial settlement establishes a stakeholder transmission asset review process that allows the stakeholders to review transmission capital projects that are not subject to review under the CAISO Transmission Planning Process which would be included in TO rates; allows the Utility to resolve the issue of compliance to reconcile the rate base with the CAISO register data base.

On May 9, 2019, the Utility filed a request with the FERC to modify the formula rate determination of the Utility’s capital structure to address certain non-cash charges related to wildfire liability. The filing was accepted by FERC, subject to hearing and refund, on July 8, 2019 and was consolidated with the TO20 rate case. In addition, on June 30, 2020, the Utility filed another request with the FERC to modify the formula rate determination of the Utility’s capital structure to address certain financing issuances related to the Utility’s emergence from Chapter 11 and requirements of AB 1054. The filing was accepted by FERC, subject to hearing and refund, on August 28, 2020 and was consolidated with the TO20 rate case (together, the “Formula Rate Proceedings”).

On March 31, 2020, the Utility filed a partial settlement with FERC that resolves issues regarding the inputs, and methods used in the formula rate consistent with FERC precedent. In addition, the partial settlement establishes a stakeholder transmission asset review process that allows the stakeholders to review transmission capital projects that are not subject to review under the CAISO Transmission Planning Process which would be included in TO rates; allows the Utility to resolve the issue of compliance to reconcile the rate base with the CAISO register data base; and requires the Utility to seek FERC authorization before recovering claims related to 2017 Northern California wildfires and 2018 Camp fire. The partial settlement was approved by FERC on August 17, 2020.

On October 15, 2020, the Utility filed a settlement with FERC resolving all of the remaining issues in the Formula Rate Proceedings, including the Utility’s ROE, capital structure, depreciation rates, as well as certain other aspects of the Utility’s formula rate. Specifically, the settlement, if approved by FERC, establishes an all-in ROE of 10.45%; a fixed capital structure of 49.75% common stock, 49.75% debt, and 0.5% preferred stock; and fixed depreciation rates for various categories of transmission facilities (represented by individual FERC accounts). The term of the settlement continues until December 31, 2023 and the Utility will be required to file a replacement rate filing to be effective on January 1, 2024. The settlement also requires the Utility to concurrently file a motion for interim rates requesting that the settlement rates go into effect on January 1, 2021 while approval of the settlement is pending at FERC. The settlement also provides that the Utility will make supplemental filings in two FERC dockets addressing the calculation of the Utility’s AFUDC to reflect the terms of the settlement. The two AFUDC dockets have not been consolidated with the Formula Rate Proceedings but include capital structure issues addressed by the settlement.

For additional information, see the 2019 Form 10-K.

Nuclear Decommissioning Cost Triennial Proceeding

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

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

Also, as previously disclosed, on January 10, 2020, the settlement agreement that the parties had reached in this proceeding was filed with the CPUC, along with a joint motion for adoption of the settlement agreement.

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Under the proposed settlement agreement, the Utility would collect annual revenue requirements of $112.5 million and $3.9 million for the funding of the Diablo Canyon non-qualified trust and Humboldt Bay tax qualified trust, respectively, commencing January 1, 2020. Additionally, under the proposed settlement agreement, the $398.4 million spent for Humboldt Bay Power Plant decommissioning project costs completed to date would be deemed reasonable.

The Utility is unable to determine the timing and outcome of this proceeding.

For additional information, see the 2019 Form 10-K.

Application for Wildfire Mitigation and Catastrophic Events Interim Rates

On February 7, 2020, the Utility filed an interim relief application seeking $899 million in interim rates related to certain electric distribution costs recorded in the following memorandum accounts: WMPMA, FRMMA, FHPMA, and CEMA. The costs pertain mainly to the years 2017-2019. The application addresses costs recorded in: (i) the WMPMA and FRMMA to comply with the 2019 WMP and other wildfire mitigation costs not otherwise recoverable through rates, (ii) the FHPMA to comply with various fire safety rulemakings through 2019, and (iii) the CEMA for responding to, and restoring customer service after, certain storms and fires occurring in 2017-2019.

The Utility submitted a request on March 23, 2020, to reduce the interim rate relief by $8.4 million to the proposed revenue requirement. This reduction, which reduces the requested rate relief to $891 million, relates to the capital cost reduction required by Assembly Bill 1054.

On October 22, 2020, the CPUC voted out its final decision that approved interim relief in the amount of $447 million. The Utility will recover these costs over a 17-month period beginning in January 2021.

For additional information, see the 2019 Form 10-K.

Wildfire Mitigation and Catastrophic Events Costs Recovery Application

On September 30, 2020, the Utility filed an application with the CPUC requesting cost recovery of recorded expenditures related to wildfire mitigation, certain catastrophic events, and a number of other activities (the “WMCE application”). The recorded expenditures exclude amounts disallowed as a result of the CPUC’s decision in the Order Instituting Investigation into the 2017 Northern California Wildfires and the 2018 Camp fire and consist of $1.18 billion in expense and $801 million in capital expenditures, which result in a revenue requirement of approximately $1.28 billion.

The costs addressed in the WMCE application cover activities mainly during the years 2017 to 2019 and are incremental to those previously authorized in the Utility’s 2017 GRC and other proceedings. The majority of costs addressed in this application reflect work necessary to mitigate wildfire risk and to respond to catastrophic events occurring during the years 2017 to 2019. The Utility recorded these costs to the FHPMA of $293 million, the FRMMA of $112 million, the WMPMA of $608 million, and the CEMA of $251 million. The CEMA costs reflected in the application include the Utility’s costs incurred responding to ten catastrophic events, including the 2017 Tubbs fire.

In its application, the Utility proposed the following ratemaking scenario: given the CPUC approval of $447 million in interim rate relief, the Utility proposes to recover the remaining $868 million revenue requirement over a one-year period (following the conclusion of interim rate relief recovery). Cost recovery requested in this application is subject to the CPUC’s reasonableness review.

The Utility has proposed a schedule that would call for a final decision by the CPUC in September 2021.

The Utility is unable to predict the timing and outcome of this application. 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 included in this application.

For more information regarding the FHPMA, the FRMMA, the WMPMA, and the CEMA memorandum accounts, see “Wildfire Mitigation Memorandum Accounts” and “Catastrophic Event Memorandum Accounts and Applications” below.

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Application for Recovery of Costs Recorded in the Wildfire Expense Memorandum Account

On February 7, 2020, the Utility filed an application seeking recovery of certain costs recorded in the WEMA. In the application, the Utility seeks recovery of $498.7 million for the cost of insurance premiums paid by the Utility between July 26, 2017 through December 31, 2019 that is incremental to the insurance costs already authorized in the 2017 GRC or sought to be authorized in rates in the 2020 GRC. These incremental costs are not associated with any specific wildfire event. The application does not seek recovery of wildfire claims or associated legal costs eligible for recording to WEMA. The Utility has proposed a schedule for the proceeding that requests a final decision by the end of 2020 and costs to be recovered in 2021.

On April 2, 2020, the CPUC held a prehearing conference in this matter. The CPUC has yet to issue a scoping memo that would establish the scope and schedule for the proceeding.

Catastrophic Event Memorandum Accounts and 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. The Utility’s CEMA applications are subject to CPUC review and approval. For more information see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

2019 CEMA Application

On September 13, 2019, the Utility submitted to the CPUC its 2019 CEMA application requesting cost recovery of $159.3 million in connection with 13 catastrophic events that included 12 wildfires and one storm for declared emergencies from mid-2017 through 2018. The 2019 CEMA application does not include costs related to the 2015 Butte fire, the 2017 Northern California wildfires, or the 2018 Camp fire.

On June 30, 2020, the Utility reported that it reached a settlement in principle with TURN and the PAO, and asked the ALJ to suspend the scheduled evidentiary hearings and give the parties time to finalize a settlement.

On August 31, 2020 the Utility filed a joint motion on behalf of the settling parties seeking approval and adoption of the settlement agreement. A final decision is expected by the end of 2020.

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

2018 CEMA Application

On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and storm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation.

On April 25, 2019, the CPUC approved the Utility’s request for interim rate relief, allowing for recovery of $373 million of costs (63% of the total costs incurred in 2016 and 2017), compared to $588 million requested by the Utility. The interim rate relief was implemented on October 1, 2019. Costs included in the interim rate relief are subject to audit and refund. On August 7, 2019, the Utility filed a Revised Application, Revised Testimony and Revised Workpapers, reflecting a new revenue requirement request of $669 million, pursuant to CPUC ruling allowing these changes.

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

On March 9, 2020, the CPUC issued a modified scoping memo and ruling, requiring the Utility to file by June 30, 2020 a revised application that would include actual 2019 tree mortality costs and an independent auditor to be hired for audit of all vegetation management costs and related interest calculations.

On May 4, 2020, the Utility filed a revised application, which included 2019 tree mortality costs, reflecting a new revenue requirement request of $757 million.

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The Utility is unable to predict the timing and outcome of this proceeding.

The Utility requested recovery of costs recorded in the 2018 CEMA in its Wildfire Mitigation and Catastrophic Events Interim Rates Application described above. (See “Wildfire Mitigation and Catastrophic Events Interim Rates Application.”)

For additional information, see the 2019 Form 10-K.

Wildfire Mitigation Memorandum Accounts

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 tracked such costs in the FHPMA through the end of 2019.

On December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s Office of the Safety Advocate, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with the OII into the 2017 Northern California Wildfires and the 2018 Camp Fire. Pursuant to the settlement agreement, the Utility agrees, among other things, to not seek recovery of $36 million of wildfire-related expenses recorded in the FHPMA. For more information on the settlement agreement, see Note 11 of the Notes to the Condensed Consolidated Financial Statements.

Other than the amounts subject to the settlement agreement, as modified by the Decision Different approved on May 7, 2020, in connection with the OII into the 2017 Northern California Wildfires and the 2018 Camp Fire, the Utility believes such costs are recoverable but rate recovery requires CPUC reasonableness review.

The Utility requested recovery of costs recorded in the FHPMA in its Wildfire Mitigation and Catastrophic Events Costs Recovery Application described above. (See “Wildfire Mitigation and Catastrophic Events Costs Recovery Application” above.)

The amount reflected in this memorandum account as of September 30, 2020 was $259 million, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

For additional information, see the 2019 Form 10-K.

Fire Risk Mitigation Memorandum Account

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

On December 17, 2019, the Utility, the SED of the CPUC, the CPUC’s Office of the Safety Advocate, and CUE jointly submitted to the CPUC a proposed settlement agreement in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire. Pursuant to the settlement agreement, the Utility agrees, among other things, not to seek recovery of $236 million of wildfire-related expenses recorded in the FRMMA and the WMPMA. For more information on the settlement agreement, see Note 11 of the Notes to the Condensed Consolidated Financial Statements.

The Utility requested recovery of costs recorded in the FRMMA in its Wildfire Mitigation and Catastrophic Events Costs Recovery Application, except for the amounts subject to the settlement agreement, as modified by the Decision Different approved on May 7, 2020, in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire. (See “Wildfire Mitigation and Catastrophic Events Costs Recovery Application” above.) 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 WMP recorded in the FRMMA.

The amount reflected in this memorandum account as of September 30, 2020 was $99 million, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

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For additional information, see the 2019 Form 10-K.

Wildfire Mitigation Plan Memorandum Account

As previously disclosed, on June 5, 2019, the Utility submitted an advice letter to establish the WMPMA (also called the Wildfire Plan Memorandum Account) effective May 30, 2019. The purpose of the WMPMA is to track costs incurred to implement the Utility’s Wildfire Mitigation Plans, as required by Public Utilities Code Sections 8386 et seq., as modified by SB 901 and subsequent bills including AB 1054, AB 111, SB 70, SB 167, SB 247, and SB 560. The WMPMA is required to be established upon approval of a utility’s wildfire mitigation plan to track costs incurred to implement the plan. The CPUC approved the memorandum account on August 5, 2019, so the Utility has recorded costs incurred in implementing the Wildfire Mitigation Plan, which was approved May 30, 2019, as of the WMPMA Effective Date, June 5, 2019.

The Utility requested recovery of costs recorded in the WMPMA in its Wildfire Mitigation and Catastrophic Events Costs Recovery Application, except for the amounts subject to the settlement agreement, as modified by the Decision Different approved on May 7, 2020, in connection with the OII into the 2017 Northern California wildfires and the 2018 Camp fire. (See “Wildfire Mitigation and Catastrophic Events Costs Recovery Application” above.) PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 Wildfire Mitigation Plan recorded in the WMPMA.

The amount reflected in this memorandum account as of September 30, 2020 was $1.08 billion, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

For additional information, see the 2019 Form 10-K.

Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections

In response to the COVID-19 pandemic, on April 16, 2020, the CPUC adopted a Resolution ordering utilities to implement a number of emergency customer protections for one year beginning on March 4, 2020 through April 16, 2021, including:

•waive deposit requirements for residential customers seeking to reestablish service for one;

•implement payment plan options for residential customers;

•suspend disconnection for nonpayment and associated fees, waive deposit and late fee requirements for residential and small business customers;

•support low-income residential customers by:

◦freezing all standard and high-usage reviews for the CARE program eligibility for 12 months and potentially longer, as warranted;

◦contacting all community outreach contractors, the community-based organizations that assist in enrolling hard-to-reach low-income customers into CARE, to help better inform customers of these eligibility changes;

◦partnering with the program administrator of the customer funded emergency assistance program for low-income customers and increasing the assistance limit amount for the next 12 months; and

◦indicate how the energy savings assistance program can be deployed to assist customers;

•suspend all CARE and Federal Emergency Relief Administration program removals to avoid unintentional loss of the discounted rate during the period for which the customer is protected under these customer protections;

•discontinue generating all recertification and verification requests that require customers to provide their current income information;

•offer repair processing and timing assistance and timely access to utility customers;

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•include these customer protections as part of their larger community outreach and public awareness plans;

•meet and confer with the Community Choice Aggregators as early as possible to discuss their roles and responsibilities for each emergency customer protection.

The Resolution also authorizes utilities to establish memorandum accounts to track incremental costs associated with complying with the Resolution.

COVID-19 Pandemic Protections Memorandum Account

On May 1, 2020, the Utility submitted an advice letter to establish the CPPMA. The purpose of the CPPMA is to track costs incurred to implement the CPUC’s Emergency Authorization and Order Directing Utilities to Implement Emergency Customer Protections to Support California Customers During the COVID-19 Pandemic. Costs included in the CPPMA will include incremental uncollectibles expense for residential and small business customers, incremental accounts receivable financing costs for residential and small business customers, and the costs of complying with various customer protections described in “Emergency Authorization and Order Directing Utilities to Implement Emergency Customer COVID-19 Protections,” above. The Utility intends to seek recovery of the CPPMA balance in a future application, recovery of which will require CPUC reasonableness review.

On June 2, 2020 and July 15, 2020, the Utility submitted updated advice letters to modify and clarify prior proposals based on CPUC guidance. On July 27, 2020, the CPUC approved the Utility’s advice letter.

The amount reflected in this memorandum account as of September 30, 2020 was $53 million, see Note 4 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

Other Regulatory Proceedings

Application to Sell General Office Complex

On September 30, 2020, the Utility filed an application with the CPUC to authorize it to sell its San Francisco General Office headquarters complex (the “SFGO”) located at 215 Market Street, 245 Market Street, 77 Beale Street, 50 Main Street, 25 Beale Street, and 45 Beale Street in downtown San Francisco, and relocate and consolidate this site and certain East Bay office locations into a single Bay Area corporate headquarters located at 300 Lakeside Drive in Oakland (the “Lakeside Building”), and for appropriate ratemaking treatment of those transactions.

According to this application, the Utility proposes the SFGO sale and headquarters transition proceed in several interrelated steps: the Utility will enter into the lease, with an option to purchase, the Lakeside Building; the Utility will initiate the sale process for, and ultimately sell, the SFGO, subject to CPUC approval; the Utility will enter into an agreement with the buyer of the SFGO to lease back space during the multi-year relocation period; and as space in the Lakeside Building becomes available following the expiration of existing tenants’ leases and completion of the redevelopment of the property to the Utility’s specifications, the Utility will relocate employees and operations from the SFGO and certain East Bay office locations to the Lakeside Building in phases over several years, beginning in 2022 (collectively, the “Transactions”).

In this application, the Utility requests that the CPUC: (i) authorize the Utility to sell the SFGO; (ii) approve the Utility’s proposal to distribute all of the gain on sale of the SFGO to customers on an annual basis over a period of five years, beginning in 2022; (iii) determine that the Transactions are reasonable, and authorize the Utility to recover (a) the costs of exercising the option to purchase the Lakeside Building and include the costs in rate base; (b) the costs of leasing necessary space in both the SFGO and in the Lakeside Building during the transition period (with the SFGO leased space decreasing as the Lakeside Building space increases); and (c) other transition and/or transaction-related costs, in accordance with the ratemaking treatment requested; and (iv) establish a balancing account to record lease payments, net savings or costs on operating expense and capital expense, gain on sale, moving costs and related costs for inclusion in electric and gas rates.

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

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Application for Post-Emergence Securitization Transaction

On April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs that is designed to be rate neutral to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt and accelerate a $700 million payment due to the Fire Victim Trust post-Effective Date. Specifically, the application requests administration of the Stress Test Methodology approved in the CHT OIR and a determination that $7.5 billion in 2017 catastrophic wildfire costs and expenses are Stress Test Costs and eligible for securitization. In this context, a securitization refers to a financing transaction where a special purpose financing vehicle issues new debt that is secured by the proceeds of a new recovery charge to Utility customers. The application also contemplates a customer credit designed to insulate customers from the charge on customer bills associated with the bonds. The Utility proposes to fund the customer credit through a trust that consists of shareholder assets including: (1) an initial contribution of $1.8 billion; (2) up to $7.59 billion of additional contributions funded by certain shareholder tax benefits; and (3) investment returns on the assets in the trust. The Utility anticipates that this will be sufficient to ensure that the customer credits equal the bond charges over the life of the bonds. The Utility also proposes to share with customers 25% of any surplus of shareholder assets in the customer credit trust at the end of the life of the trust.

Protests and response to the application were due June 4, 2020 and the Utility filed a reply on June 12, 2020. A prehearing conference was held on June 18, 2020. The Assigned Commissioner issued the scoping memorandum on July 28, 2020 and directed the Utility to file updated testimony, if any, based on its post-emergence financial status by August 7, 2020. The Utility served its updated testimony on August 7, 2020, in which it discussed , among other things, PG&E Corporation’s and Utility’s exit financings from Chapter 11 and related equity issuances, including to the Fire Victim Trust, in connection with consummating the Plan on July 1, 2020, issuance of revised credit ratings, updated financial forecasts for the Utility and their impacts on the securitization application, including on the Stress Test Costs and the Customer Credit Trust, as well as certain expected tax impacts.

Intervenor testimony was served on October 14, 2020, and the Utility’s rebuttal testimony is due on November 11, 2020. An evidentiary hearing is scheduled to commence on December 7, 2020. Opening briefs are due on January 7, 2021, and reply briefs are due on January 22, 2021.

2019 Wildfire Mitigation Plan

As previously disclosed, 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 determined, among other things, how to interpret and apply SB 901’s list of required plan elements, as well as what 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 WMP”) with the CPUC, and amended it subsequently on February 12 and February 14. On May 30, 2019, the CPUC approved the 2019 WMP. (The Utility also filed an amendment to the plan on April 25, 2019, but CPUC approval did not extend to that amendment.)

For additional information, see the 2019 Form 10-K.

2020-2022 Wildfire Mitigation Plan

As previously disclosed, on February 7, 2020, the Utility publicly posted its 2020 Wildfire Mitigation Plan (the “2020 WMP”) and utility survey. The Utility’s 2020 WMP describes the Utility’s wildfire safety programs, which are focused on three key areas: reducing the potential for fires to be started by electrical equipment, reducing the potential for fires to spread, and minimizing the frequency, scope and duration of Public Safety Power Shut-off events, as well as providing historical data requested by the guidelines.

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On March 18, 2020, the CPUC issued a decision in this proceeding, clarifying that the CPUC’s newly created Wildfire Safety Division will review 2020 wildfire mitigation plans, present resolutions for CPUC consideration on the 2020 Plans, and oversee independent evaluation and other compliance activity with regard to both 2019 and 2020 Plans.

On June 11, 2020, the CPUC voted to adopt two resolutions which conditionally approved PG&E’s 2020-2022 WMP. The resolutions indicate that while the Utility’s 2020-2022 WMP met the minimum requirements for its submission, the deficiencies found, classified as Conditions A, B, or C, will require significant oversight to ensure they appropriately prioritize and remedy the deficiencies. The Utility received 41 Conditions in total with the first set classified as Conditions A, which were completed on July 27, 2020. The second set, Conditions B were completed on September 9, 2020 and the third, Conditions C are due as part of the 2021 WMP update in February 2021.

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 WMP, and the 2020-2022 WMP recorded in the FRMMA and WMPMA, which the Utility expects will be substantial.

For additional information, see the 2019 Form 10-K.

OIR Regarding Microgrids

As previously disclosed, on September 19, 2019, the CPUC initiated a rulemaking proceeding to examine microgrid implementation issues and resiliency strategies pursuant to SB 1339. In the first track of that proceeding, the CPUC sought to deploy resiliency planning in areas that are prone to outage events and wildfires, with the stated goal of putting some microgrid and other resiliency strategies in place by Spring or Summer 2020, if not sooner. At the CPUC’s direction, the Utility submitted a proposal for immediate implementation of resiliency strategies on January 21, 2020. The Utility’s proposal contained three components for which it is sought scope and cost recovery authorization of up to approximately $379 million in both expense and capital. On April 1, 2020, the Utility filed a motion seeking to supplement its original proposal and to reduce the total cost recovery authorization it was seeking to approximately $257 million. The Utility described in its supplemental testimony that it was focusing in 2020 on the use of temporary, mobile generation solutions to power microgrids in 2020 and that the Utility had suspended its solicitation for permanent generation located at substations with online dates in 2020. On April 13, 2020, the ALJ presiding over the rulemaking issued a ruling denying on procedural grounds the Utility’s motion to supplement its proposal.

The CPUC adopted a decision in the first track of the proceeding on June 11, 2020, which approved with conditions each of the Utility’s three proposed components and requires the Utility to track costs in a new memorandum account. The decision requires the Utility to seek recovery of the recorded costs for the temporary, mobile generation and associated substation facility equipment in a future track of the proceeding. The decision requires the Utility to seek recovery of the costs of the community microgrid enablement program through reasonableness review in a future separate application or a general rate case.

The CPUC initiated the second track of the proceeding on July 3, 2020, which will focus on further implementation of SB 1339, as well as activity to shape the transition from diesel mobile generation to alternative, clean backup power generation. As part of the second track, the CPUC issued a staff proposal on September 4, 2020, describing an interim approach for providing temporary power at substations during the 2021 wildfire season, and a process for completing the transition to clean technologies and fuels in future years. The Utility expects the CPUC to issue a decision on temporary generation policy for the 2021 wildfire season and beyond by the end of 2020.

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

The Utility has approximately 450 megawatts of temporary generation reserved for use in 2020.

For additional information, see the 2019 Form 10-K.

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

As previously disclosed, on July 8, 2019, the CPUC issued a decision in the CHT proceeding, which adopts a methodology to determine the CHT based on (1) the maximum additional debt that a utility can take on and maintain a minimum investment grade credit rating; (2) excess cash available to the utility; (3) a potential regulatory adjustment of 20% of the CHT or 5% of the total disallowed wildfire liabilities; and (4) an adjustment to preserve for ratepayers any tax benefits associated with the CHT. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers as part of an application under Section 451.2(b).

Pursuant to SB 901 and the CPUC’s methodology adopted in the CHT OIR, on April 30, 2020, the Utility filed an application with the CPUC seeking authorization for a post-emergence transaction to securitize $7.5 billion of 2017 wildfire claims costs that is designed to be rate-neutral to customers, with the proceeds used to pay or reimburse the Utility for the payment of wildfire claims costs associated with the 2017 Northern California wildfires. As a result of the proposed transaction, the Utility would retire $6.0 billion of Utility debt and accelerate a $700 million payment due to the Fire Victim Trust post-Effective Date.

For additional information, see “Application for Post-Emergence Securitization Transaction” above and the 2019 Form 10-K.

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

As previously disclosed, on October 4, 2019, the CPUC issued an OII to consider the ratemaking and other implications “that will result from the confirmation of a plan of reorganization and other regulatory approvals necessary to resolve” the Chapter 11 Cases (the “Chapter 11 Proceedings OII”).

On May 28, 2020, the CPUC approved a final decision in this proceeding. As previously disclosed, the decision approved PG&E Corporation’s and the Utility’s Plan with certain conditions and modifications related to certain topics, including but not limited to, governance, operational structure, safety performance, executive competition, and financial condition. On September 17, 2020, the CPUC issued a proposed decision that would close the proceeding. On October 22, 2020, the CPUC approved the decision.

Regionalization Proposal

On June 30, 2020, the Utility filed its application for approval of its Regionalization Proposal with the CPUC. The Utility’s proposal would divide its service area into five new regions to further improve safety and reliability, core operations, and be more responsive to the needs of its customers. The Utility’s Regionalization Proposal describes the development of these regions, plans to hire new regional leadership, and a new regional organization structure that moves certain work to local regions for both scheduling and execution. The Utility’s application requests the CPUC to approve a memorandum account to record any incremental costs the Utility incurs in connection with the development and implementation of regionalization.

The Utility is unable to predict the timing and outcome of this application.

Enhanced Enforcement Process

In the Chapter 11 Proceedings OII final decision, the CPUC adopted an Enhanced Oversight and Enforcement Process (the “Process”) designed to provide a roadmap for how the CPUC will monitor the Utility’s performance on an ongoing basis. The Process contains six steps that are triggered by specific events and includes enhanced reporting requirements and additional monitoring and oversight. The Process also contains provisions for the Utility to cure and permanently exit the Process if it can satisfy specific criteria. If the Utility is placed into the Process, actions taken would occur in coordination with the CPUC’s existing formal and informal reporting requirements and procedures. The Process does not replace or limit the CPUC’s regulatory authority, including the authority to issue Orders to Show Cause and Orders Instituting Investigations and to impose fines and penalties. The Process requires the Utility to report the occurrence of a triggering event to the CPUC’s Executive Director no later than five business day after the date on which any member of senior management of the Utility becomes aware of the occurrence of a triggering event.

For more information about this OII, see PG&E Corporation’s and the Utility’s joint 2019 Form 10-K.

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Wildfire Fund Non-Bypassable Charge

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

On November 25, 2019, an individual intervenor filed an application for rehearing of the decision arguing that the decision constitutes a constitutional violation of procedural due process and an unjust and unreasonable rate increase. On March 2, 2020, the CPUC issued a decision denying the application for rehearing.

On July 16, 2020, the CPUC approved the Wildfire Fund NBC servicing orders between the California Department of Water Resources and the Large Electrical Corporations to impose the Wildfire Fund NBC. On September 10, 2020, the CPUC ordered the Utility to cease collection of the DWR Bond Charge related revenue requirement from electric customers in their respective territories. The final month in which a Bond Charge related revenue requirement will be imposed to collect revenue from electric customers of the Utilities will be September 2020.

On September 24, 2020, the CPUC ordered the Utility to collect the Wildfire Fund NBC from eligible customers from October 1, 2020 through December 31, 2020 in the amount of $0.00580 per kilowatt-hour.

On September 29, 2020, the Utility submitted an advice letter to submit tariffs incorporating final rates effective October 1, 2020. In addition to submitting tariff revisions that include final rates as outlined the letter included the tariff revisions needed to cease the imposition of the DWR Bond Charge and implement the Wildfire Fund Charge, submitted on September 25, 2020.

For additional information, see the 2019 Form 10-K.

Transportation Electrification

SB 350 (the Clean Energy and Pollution Reduction Act), requires the CPUC, in consultation with the CARB and the California Energy Resources Conservation and Development Commission, to direct electrical corporations to file applications for programs and investments to accelerate widespread transportation electrification. In September 2016, the CPUC directed the Utility and the other large IOUs to file transportation electrification 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.

As previously disclosed, 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.

On December 19, 2018, the CPUC initiated a new Rulemaking for vehicle electrification matters. 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. On February 3, 2020 the CPUC issued a draft Transportation Electrification Framework for review and comment. The CPUC has held workshops in 2020. Approval of the framework is expected by early 2021.

For additional information, see the 2019 Form 10-K.

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OIR to Establish Policies, Processes, and Rules to Ensure Safe and Reliable Gas Systems in California and Perform Long-Term Gas Planning

On January 16, 2020, the CPUC opened an OIR to address reliability and standards for gas public utilities, the regulatory changes necessary to improve the coordination between gas utilities and gas-fired electric generators, and impacts due to legislative mandates to address the greenhouse gas reduction emissions which will result in the replacement of gas-fuel technologies and forecast reduced demand for natural gas. This proceeding will examine whether recent industry related events will require the CPUC to change the rules, processes and regulations governing gas utilities, including but not limited to, gas reliability standards, long-term contracting, regulatory accounting, reporting and tariff changes for operational flow orders.

The Utility filed opening comments on the preliminary scope on February 26, 2020 and reply comments on March 12, 2020. The assigned ALJ and assigned commissioner held a prehearing conference on March 24, 2020. The Utility filed a post-prehearing conference Statement on April 1, 2020. On April 23, 2020, the assigned commissioner issued a ruling setting the final scope, schedule and categorization for phase 1 (Tracks 1A and 1B). On July 7, the CPUC held a workshop to address natural gas reliability standards (Track 1A) and on July 21, 2020 a second workshop was held to address market structure and regulations (Track 1B). On September 14, 2020, the assigned ALJ issued a Ruling modifying the procedural schedule to allow additional time for CPUC staff to issue a workshop report including recommendations. In accordance with the revised procedural schedule for Phase I, the CPUC staff is expected to issue its Report on October 2, 2020. Parties may then submit opening and reply comments in November 2020 on the Report.

For additional information, see the 2019 Form 10-K.

OIR to Consider Strategies and Guidance for Climate Change Adaptation

On April 26, 2018, the CPUC opened an OIR to consider strategies for integrating climate change adaptation matters into relevant CPUC proceedings.

On October 24, 2019, the CPUC adopted a final decision on a portion of phase one (Topic 1 and 2), defining climate change adaptation for California’s energy utilities as “adjustment in natural and human systems to a new or changing environment. Adaptation to climate change for energy utilities regulated by the CPUC refers to adjustment in utility systems using strategic and data-driven consideration of actual or expected climatic impacts and stimuli or their effects on utility planning, facilities maintenance and construction, and communications, to maintain safe, reliable, affordable and resilient operations.” In addition, this decision provides guidance on what data should be used by the investor-owned utilities to perform all climate impact, climate risk, and climate vulnerability analyses undertaken with respect to their infrastructure assets, operations, and customer impacts. Finally, this decision requires the energy utilities to adhere to the same climate scenarios and projections used in the most recent California Statewide Climate Change Assessment when analyzing climate impacts, climate risk, and climate vulnerability of utility systems, operations, and customers.

On October 22, 2019, the CPUC issued a staff proposal for a framework for climate-related decision-making and accountability. In the staff proposal, the CPUC instructed each of the large IOUs to research and develop a new form of risk assessment, a CVA. CVAs instruct utilities to “examine the risks posed by climate change to their core lines of business, including generation, transmission, distribution, and storage, irrespective of who owns the assets.” In addition, the staff proposal provides guidance regarding the data sources to be used in the CVA, outreach and coordination with the community, and incorporation of CVA findings into RAMP and GRC filings. The Utility provided opening and reply comments on February 18 and March 3, 2020, respectively.

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On August 27, 2020, the CPUC adopted a final decision on Topics 4 and 5, regarding adaptation outreach to disadvantaged communities and detailed requirements for each IOU’s CVA. The CPUC instructed IOUs to establish “climate change teams,” with cross-departmental responsibilities, which will report directly to a designated executive at the SVP level or above. Each IOU must disclose to the CPUC such changes in organizational structure, listing the individual names and department titles of all internal participants. Board members should oversee and prioritize climate adaptation planning, as informed by senior leadership. Each IOU is required to consider climate risks to assets, operations, and services over which IOUs have direct control. Additionally, the decision directs the IOUs seek to obtain and acknowledgement in new contracts with third party providers that the operator has considered long-term climate risk. Each IOUs’ completed CVA will coincide with its RAMP filing during its four-year GRC cycle, and IOUs must detail resulting climate adaptation measures in a new chapter in future GRC applications. Each IOU must file a Community Engagement Plan detailing community outreach on climate adaptation, covering every disadvantaged vulnerable community and leveraging existing IOU community outreach on other matters. The IOUs’ climate adaptation CEP proposals must be filed one year prior to their CVA, with the Utility’s first CEP due in June 2023, as PG&E’s first CVA under this decision will be due in June 2024. A new memorandum account, the Climate Adaptation Vulnerability Assessment Memorandum Account, was authorized, to cover CVA costs and incremental costs of outreach.

OIR to Examine Electric 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.

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.

On January 30, 2020, the CPUC proposed new guidelines. Parties submitted opening and reply comments on the guidelines on February 19, 2020 and February 26, 2020, respectively.

As discussed above, on April 13, 2020, a group of local governments and associations filed a Joint Motion for Emergency Order Regarding De-Energization Protocols During the COVID-19 Pandemic, requesting that the CPUC issue an emergency order setting forth de-energization protocols for the Utility and other investor-owned utilities that will remain in place for as long as a State of Emergency or shelter-in-place order remains in effect due to the COVID-19 pandemic. The requested requirements included providing back-up generation to essential services and allowing local governments to veto PSPS events for their areas. The Utility and other entities (including the other IOUs) filed responses on April 20, 2020, requesting that the CPUC deny the motion, and the moving parties and other entities filed responses on April 24, 2020. On August 24, 2020, the ALJ issued a decision holding the April 13, 2020 joint motion in abeyance, finding that the May 28, 2020 decision dealt with many of the issues raised. If the motion were reinstated in the future, a CPUC decision could restrict or impose additional requirements on the Utility in implementing PSPS events.

On May 28, 2020 the CPUC adopted PSPS Phase 2 Guidelines, which requires utilities to restore energy within 24 hours after the end of a PSPS event where possible; to consult with critical facilities on back-up power for PSPS events; and to support access and functional needs populations during PSPS events, including powering medical equipment at customer resource centers. The CPUC’s May 28, 2020 decision did not act on the joint motion.

On June 15, 2020, 14 parties (including telecommunications providers, CCAs, and 10 cities and counties) filed a joint motion requesting that the CPUC perform a reasonableness review of past IOU PSPS events to determine whether each was reasonable. In its August 24, 2020 decision, the CPUC denied the June 15, 2020 motion, finding that the CPUC already performed reasonableness reviews of IOU PSPS events.

For additional information, see the 2019 Form 10-K.

Order to Show Cause Against the Utility Related to Implementation of the October 2019 PSPS Events

On November 12, 2019, the assigned commissioner and ALJ in the OIR to Examine Electric Utility De-energization of Power Lines in Dangerous Conditions issued an order to show cause directing the Utility to show cause why it should not be sanctioned for violations of law or CPUC decisions related to the PSPS events of October 9-12, 2019, October 23-25, 2019, and October 26-November 1, 2019.

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The Utility filed its testimony with the CPUC on February 5, 2020. Parties filed testimony on February 28, 2020; concurrent rebuttal was filed on April 7, 2020. On April 16, 2020, proceedings in the order to show cause phase of this proceeding were suspended indefinitely pending the COVID-19-related restrictions. On July 7, 2020, in response to an email ruling from the ALJ, parties in the order to show cause submitted a joint response that discussed, among other things, the need for evidentiary hearings in the proceeding and a proposed schedule for the remainder of the proceedings. On July 9, 2020 and August 27, 2020, the ALJ held status conferences at which parties discussed those issues. On September 21, 2020, the assigned commissioner and the ALJ issued an order that required the Utility to provide responses to certain factual questions regarding the issues in the proceeding, concluded that with the provision of responsive answers to those questions evidentiary hearings would not be needed in the proceeding, and established a schedule for the remainder of the proceeding. The schedule provides for concurrent opening briefs to be filed on October 30, 2020; concurrent reply briefs on November 17, 2020; a presiding officer decision no later than 60 days following submission; and a final decision no sooner than 30 days after the presiding officer decision if no appeal or request for review is submitted.

The Utility is unable to predict the outcome of this proceeding.

For additional information, see the 2019 Form 10-K.

OII to Examine the Late 2019 Public Safety Power Shutoff Events

On November 13, 2019, the CPUC issued an OII to determine “whether California’s investor-owned utilities prioritized safety and complied with the CPUC’s regulations and requirements with respect to their Public Safety Power Shutoff (PSPS) events in late 2019.” The first phase of this proceeding will assess for each utility, among other things, (1) the effectiveness of the utility’s procedures to notify the public of the PSPS events, (2) the utility’s communication and coordination with first responders, local jurisdictions and state agencies, and (3) the utility’s management of its resources to ensure public safety. In later phases of this proceeding, the CPUC may consider taking action if it finds violations of statutes or its decisions or general orders have been committed and to enforce compliance, if necessary.

On June 8, 2020, the SED issued a Public Report on the Late 2019 Public Safety Power Shutoff Events. The Report indicated that it described the manner and extent to which each electric investor-owned utility implemented the CPUC’s PSPS Guidelines during their late 2019 PSPS events. The Report stated that it was intended to be advisory in nature, subject to modification, and not intended to serve as an adjudicatory-staff investigatory pre-enforcement report. On June 19, 2020, parties to the OII submitted prehearing statements that provided, among other things, views on the appropriate next steps in the proceeding. On June 22, 2020, the ALJ held a prehearing conference that discussed appropriate next steps in the proceeding. On August 3, 2020, the ALJ issued a ruling finding that a hearing was not necessary and setting the schedule for the proceeding, and on September 18, 2020, the ALJ granted a motion to extend time for intervenor and reply comments. IOU comments were submitted September 2, 2020, intervenor comments were submitted October 16, 2020, and reply comments are due November 16, 2020. The proposed decision is anticipated 90 days after submission of reply briefs, and the CPUC decision is anticipated no sooner than 30 days after issuance of the proposed decision.

Also on August 3, 2020, the assigned commissioner issued a ruling and scoping memo directing parties to file comments on SED’s report and the following two issues: (1) whether the Utility and other IOUs in October and November 2019 complied with the criteria set forth in applicable laws and regulations when pro-actively deenergizing and re-energizing their power lines, and (2) what corrective actions should the CPUC should require of the Utility and other IOUs for any failure in late 2019 to comply with the then-existing PSPS guidelines

For additional information, see the 2019 Form 10-K.

Power Charge Indifference Adjustment OIR

In 2017, the CPUC initiated the PCIA Rulemaking to make refinements to the PCIA, a cost recovery mechanism to ensure that customers that leave the Utility’s bundled service for a non-Utility provider, such as a DA or CCA provider, pay their fair share of the above market costs associated with long-term power purchase commitments and Utility-owned generation made on their behalf. The above market costs of the Utility’s generation portfolio are calculated using benchmarks for energy, resource adequacy (RA) and RPS attributes.

As previously disclosed, on October 11, 2018, the CPUC approved a phase one decision to modify the PCIA methodology. The Utility implemented a revised PCIA reflecting this decision in rates as of July 1, 2019.

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Also, as previously disclosed, on October 10, 2019, the CPUC approved a final decision that finalized the true-up for the new PCIA methodology.

On March 26, 2020, the CPUC approved a final decision on departing load forecasting and PCIA bill presentation issues, establishing that the IOUs shall show a PCIA line item in their tariffs and bill summary tables on all customer bills, which shall be implemented by the last business day of 2021.

On June 30, 2020, the CPUC issued a PD that would provide a non-Utility provider an option to prepay their entire PCIA obligation. On August 6, 2020 the CPUC issued a final decision adopting a framework for prepayment agreements for PCIA obligations.

The proceeding is now examining structures and rules governing how the Utility addresses excess resources in its portfolio due to load loss to CCA and DA, including standards for active management of the Utility’s portfolios. A PD is expected in the fourth quarter of 2020.

For additional information, see the 2019 Form 10-K.

Central Procurement of the Resource Adequacy Program

On June 17, 2020, the CPUC issued a decision on the Central Procurement of the RA Program. The decision adopted implementation details for the central procurement of multi-year local RA procurement, ordered the Utility and another IOU to serve as the central procurement entities for their respective distribution service areas, and adopted a hybrid central procurement framework for the multi-year local RA program beginning for the 2023 RA compliance year.

The decision requires the Utility, as the central procurement entity for its distribution service area, to conduct a competitive, all-source solicitation for local RA procurement, with any existing local resource that does not have a contract, any new local resource that can be brought online in time to meet solicitation requirements, or any load serving entity or third-party with an existing local RA contract eligible to bid into the solicitation.

The Cost Allocation Mechanism methodology is adopted as the cost recovery mechanism to cover procurement costs incurred in serving the central procurement function. The administrative costs incurred in serving the central procurement entity function shall also be recoverable under the Cost Allocation Mechanism.

LEGISLATIVE AND REGULATORY INITIATIVES

Senate Bill 350

On June 30, 2020, the California governor signed into law SB 350 (the Golden State Energy Act), a bill which authorizes the creation by the governor of a new entity “Golden State Energy,” a nonprofit public benefit corporation, for the purpose of acquiring the Utility’s assets and serving electric and gas in the Utility’s service territory only in the event that the CPUC determines that the Utility’s Certificate of Public Convenience and Necessity should be revoked pursuant to any process or procedures adopted by the CPUC in its decision approving PG&E Corporation’s and the Utility’s Plan of Reorganization.

Senate Bill 901

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

For additional information, see the 2019 Form 10-K.

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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.

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.

Each of California’s large investor owned utilities have elected to participate in the Wildfire Fund. On July 1, 2020, having satisfied the conditions for the Utility’s participation in the Wildfire Fund, the Utility deposited approximately $5 billion in the Wildfire Fund, which represents PG&E’s initial and first annual contributions.

For additional information, see the 2019 Form 10-K.

Senate Bill 378

In addition to other requirements, SB 378 would impose on an electric utility company a civil penalty of at least $250,000 per 50,000 affected customers for every hour that a PSPS event is in place, would require the CPUC to establish a procedure for customers, local governments and others to recover costs accrued during a PSPS event from the electric utility company, which cost recovery would be borne by shareholders, and would prohibit an electric utility company from billing customers for any nonfixed costs during a PSPS event.

Assembly Bill 1941

AB 1941 proposes to suspend RPS requirements, determine the savings to electric utility companies from the suspension and direct those savings towards system hardening to mitigate wildfire risks and PSPS impacts, and would prohibit salary increases or bonuses to executive officers during the suspension of RPS requirements.

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 greenhouse gas 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 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 Form 10-K.)

CONTRACTUAL COMMITMENTS

PG&E Corporation and the Utility enter into contractual commitments in connection with future obligations that relate to purchases of electricity and natural gas for customers, purchases of transportation capacity, purchases of renewable energy, and purchases of fuel and transportation to support the Utility’s generation activities. (See “Purchase Commitments” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1). Contractual commitments that relate to financing arrangements include long-term debt, preferred stock, and certain forms of regulatory financing. For more in-depth discussion about PG&E Corporation’s and the Utility’s contractual commitments, see “Liquidity and Financial Resources” above and MD&A “Contractual Commitments” in Item 7 of the 2019 Form 10-K.

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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 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2019 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 2019 Form 10-K. There were no significant developments to the Utility’s and PG&E Corporation’s risk management activities during the nine months ended September 30, 2020.

CRITICAL ACCOUNTING POLICIES

The preparation of the Condensed Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. PG&E Corporation and the Utility consider their accounting policies for regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal and regulatory matters, AROs, and pension and other post-retirement benefit 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 and assumptions. These accounting policies and their key characteristics are discussed in detail in the 2019 Form 10-K.

Contributions to the Wildfire Fund

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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.

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.)

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ITEM 4. CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of September 30, 2020, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms, and (ii) accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal control over financial reporting that occurred during the quarter ended September 30, 2020, that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In addition to the following proceedings, PG&E Corporation and the Utility are parties to various lawsuits and regulatory proceedings in the ordinary course of their business. For more information regarding PG&E Corporation’s and the Utility’s legal proceedings and contingencies, see Notes 2, 10, and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and Part I, MD&A: “Enforcement and Litigation Matters.”

U.S. District Court Matters and Probation

On April 29, 2020, the court issued an order imposing new conditions of probation.

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For more information on the Utility’s probation, see the 2019 Form 10-K.

The Utility expects to receive additional orders from the court in the future.

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 June 18, 2019, the CPUC issued a ruling requesting comments from parties on four proposals that it stated may improve the safety culture of PG&E Corporation and the Utility. The four proposals are: separating the Utility into gas and electric utilities (including, as one possibility, sale of the gas assets to a third party); establishing periodic review of the Utility’s certificate of convenience and necessity; modifying or eliminating PG&E Corporation’s holding company structure; and linking the Utility’s rate of return or return on equity to safety performance metrics. Opening comments on the ruling were filed on July 19, 2019 and reply comments were filed on August 2, 2019.

On September 4, 2020, the ALJ issued a ruling updating case status, which states that the proceeding will remain open as a vehicle to monitor the progress of the Utility in improving its safety culture, and to address any relevant issues that arise, with the CPUC’s consultant NorthStar Consulting Group, Inc. continuing in a monitoring role. The ruling states that additional issues may be raised in the proceedings by parties or the CPUC.

For more information, see the 2019 Form 10-K.

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 2019 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 2019 Form 10-K and in PG&E Corporation’s and the Utility’s joint quarterly reports for the periods ended March 31, 2020 and June 30, 2020 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 condition, results of operations, liquidity, and cash flows could be materially affected as a result of the 2019 Kincade fire, the 2020 Zogg fire or future wildfires.

On July 16, 2020, Cal Fire issued a press release addressing the cause of the 2019 Kincade fire. Cal Fire stated that it had “determined that the Kincade Fire was caused by electrical transmission lines owned and operated by Pacific Gas and Electric (PG&E) located northeast of Geyserville. Tinder dry vegetation and strong winds combined with low humidity and warm temperatures contributed to extreme rates of fire spread.” Cal Fire also indicated that its investigative report has been forwarded to the Sonoma County District Attorney’s Office, which is investigating the matter.

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On October 9, 2020, Cal Fire informed the Utility that it had taken possession of the Utility’s equipment as part of its ongoing investigation into the cause of the 2020 Zogg fire. Cal Fire has not issued a determination of cause. The Shasta County District Attorney’s Office is also investigating the fire.

Although there are a number of unknown facts surrounding Cal Fire’s causation determination of the 2019 Kincade fire and their investigation of the 2020 Zogg fire, the Utility could be subject to significant liability in excess of insurance coverage that would be expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. PG&E Corporation and the Utility have also received and are responding to data requests from the CPUC’s SED relating to the 2019 Kincade fire and the 2020 Zogg fire. PG&E Corporation and the Utility could be the subject of additional investigations, lawsuits, or enforcement actions in connection with the 2019 Kincade fire, the 2020 Zogg fire or future wildfires.

In addition, the 2019 Kincade fire, the 2020 Zogg fire or future wildfires could have adverse consequences on the Utility’s probation proceeding, the Utility’s proceedings with the CPUC and FERC (including the Safety Culture OII), and future regulatory proceedings, including future applications for the safety certification required by AB 1054. PG&E Corporation and the Utility may also suffer additional reputational harm and face an even more challenging operating, political, and regulatory environment. For more information about the 2019 Kincade fire and the 2020 Zogg fire, see Note 10 “Wildfire-Related Contingencies” in Part I, Item 1.

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be significantly affected by the outbreak of the COVID-19 pandemic.

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows have been (beginning in March 2020) and could continue to be significantly affected by the outbreak of COVID-19, but the extent of such impact is uncertain. In December 2019, a novel strain of coronavirus (COVID-19) was reported to have surfaced in Wuhan, China, resulting in significant disruptions to manufacturing, supply chain, markets, and travel world-wide. On January 30, 2020, the International Health Regulations Emergency Committee of the World Health Organization declared the COVID-19 outbreak a public health emergency of international concern and on March 12, 2020, announced the outbreak was a pandemic. On March 16, 2020, the California governor issued an Executive Order requiring the CPUC to direct electric utility companies to follow customer protection measures including a moratorium on service disconnections for residential and small business customers, retroactive to March 4, 2020. After a statewide shelter in place order instituted on March 19, 2020, on April 28, 2020, the California governor announced four different stages for easing the California shelter-in-place measures. California currently has a blueprint for reducing COVID-19 in the state with revised criteria for loosening and tightening restrictions on activities. It is uncertain when further modifications and restrictions will be implemented.

While the extent of the impact of the current COVID-19 outbreak on PG&E Corporation’s and the Utility’s business and financial results is uncertain, the consequences of a continued and prolonged outbreak and resulting government and regulatory orders could have a further negative impact on the Utility’s financial condition, results of operations, liquidity and cash flows.

The outbreak of COVID-19 and the resulting economic conditions, including but not limited to the shelter-in-place order and resulting decrease in economic and industrial activity in the Utility’s service territory have and will continue to have a significant adverse impact on the Utility’s customers; these circumstances have impacted and will continue to impact the Utility for a period of time that PG&E Corporation and the Utility are unable to predict. For example, the economic downturn has already resulted in a reduction in customer receipts and collection delays in the second and third quarters of 2020.

The Utility’s customer energy accounts receivable balances over 30 days outstanding as of September 30, 2020 were approximately $696 million, or $310 million higher as compared to the corresponding month in 2019. The Utility is unable to estimate the portion of the increase directly attributable to the COVID-19 pandemic. The Utility expects to continue experiencing an impact on monthly cash collections in 2020 and for as long as current COVID-19 circumstances persist.

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On April 16, 2020, the CPUC passed a resolution requiring COVID-19 related emergency customer protection measures starting from the March 4, 2020 Emergency Proclamation and consistent with the March 16, 2020 Executive Order. The Resolution allows associated costs to be tracked in a memorandum account, the COVID-19 Pandemic Protections Memorandum Account (CPPMA). The CPPMA allows tracking of residential and small business customers’ incremental uncollectible costs. In addition, the Utility’s proposed 2020 GRC settlement would continue the Utility’s existing mechanism to address uncollectibles, which allows the Utility to readjust its uncollectibles rate on an annual basis based on the most recent 10-year average of uncollectibles. In addition, the June 11, 2020 decision in the OIR to Consider New Approaches to Disconnections and Reconnections to Improve Energy Access and Contain Costs (Disconnections OIR) provides for a two-way balancing account for residential uncollectibles and memorandum account for OIR implementation costs. The Utility is unable to predict whether these measures will allow for future recovery of these amounts.

In addition, the Utility has experienced average reductions of approximately 3% in electric load and approximately 3% in core gas load on a weather-adjusted basis from mid-March to early October, resulting in an estimated $350 million reduction in billed revenues for the mid-March to early October period. PG&E Corporation and the Utility are currently unable to quantify the long-term potential impact of the changes in customer collections or changes in energy demand on earnings and cash flows due, in part, to uncertainties regarding the timing, duration and intensity of the COVID-19 outbreak and the resulting economic downturn. Although the CPUC authorized the establishment of memorandum and balancing accounts to track costs associated with customer protection measures, the timing of regulatory relief, if any, and ultimately cost recovery from such accounts or otherwise, are uncertain.

The COVID-19 pandemic and resulting economic downturn have resulted and will continue to result in workforce disruptions, both in personnel availability (including a reduction in contract labor resources) and deployment. In preparation for the return of a few teams to their offices, the Utility has issued a “Return to PG&E Playbook” that explains the safety-related steps the company is taking, as well as the steps that PG&E Corporation’s and the Utility’s employees should take. The guidance includes important reminders of policies on personal hygiene, travel, reporting exposure or illness, and other topics.

Although the Utility continues to prioritize customer and community safety, these disruptions necessitate changes to the Utility’s operating and capital expenditure plans, which could lead to project delays or service disruptions in certain programs. Delays in production and shipping of materials used in the Utility’s operations may also impact operations.

In addition, COVID-19 has the potential to cause delays and disruptions in various regulatory proceedings in which the Utility is involved. Following Department of Health guidance concerning restrictions on public gatherings, the CPUC has cancelled all public forums and has been conducting remote meetings for events it deems essential. A disruption in CPUC operations could impact the timing of PG&E Corporation’s and the Utility’s rate cases and other regulatory proceedings.

In addition, as discussed above, a group of local government entities and organizations filed a Joint Motion asking the CPUC to require utilities to comply with additional requirements when implementing PSPS events while local areas are sheltering-in-place due to COVID-19. The requested requirements included providing back-up generation to essential services and allowing local governments to veto PSPS events for their areas. The Utility and other entities (including the other IOUs) filed responses on April 20, 2020, requesting that the CPUC deny the motion, and the moving parties and other entities filed responses on April 24, 2020. On August 24, 2020, the ALJ issued a decision holding the April 13, 2020 joint motion in abeyance, finding that the May 28, 2020 decision dealt with many of the issues raised. If the motion were reinstated in the future, a CPUC decision could restrict or impose additional requirements on the Utility in implementing PSPS events.

PG&E Corporation and the Utility expect additional financial impacts in the future as a result of COVID-19. Potential longer-term impacts of COVID-19 on PG&E Corporation or the Utility include the potential for higher credit spreads and borrowing costs and incremental financing needs. PG&E Corporation’s and the Utility’s analysis of the potential impact of COVID-19 is preliminary and subject to change. PG&E Corporation and the Utility are unable to predict the timing, duration or intensity of the COVID-19 situation and its effects on the business and general economic conditions in the State of California and the United States of America.

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PG&E Corporation’s and the Utility’s substantial indebtedness following the Reorganization may adversely affect their financial health and operating flexibility.

PG&E Corporation and the Utility have a substantial amount of indebtedness as a result of the reorganization transactions in connection with implementation of the Plan, most of which is secured by liens on the assets of PG&E Corporation and the Utility. As of September 30, 2020, PG&E Corporation had approximately $4.75 billion of outstanding indebtedness (such indebtedness consisting of the 2028 Notes, the 2030 Notes and borrowings under the Term Loan), and the Utility had approximately $31.8 billion of outstanding indebtedness (such indebtedness including the Utility Reinstated Senior Notes, the Mortgage Bonds and the Utility Term Loan Credit Agreement). In addition, PG&E Corporation and the Utility had $500 million of additional borrowing capacity under the Corporation Revolving Credit Agreement, and the Utility had $1.71 billion of additional borrowing capacity under the Utility Revolving Credit Agreement. In addition, the Utility had outstanding preferred stock with an aggregate liquidation preference of $252 million.

Since PG&E Corporation and the Utility have a historically high level of debt, a substantial portion of cash flow from operations will be used to make payments on this debt. Furthermore, since a significant percentage of the Utility’s assets are used to secure its debt, this reduces the amount of collateral available for future secured debt or credit support and reduces its flexibility in operating these secured assets. This relatively high level of debt and related security could have other important consequences for PG&E Corporation and the Utility, including:

•limiting their ability or increasing the costs to refinance their indebtedness;

•limiting their ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of their business strategy or other purposes;

•limiting their ability to use operating cash flow in other areas of their business because they must dedicate a substantial portion of these funds to service debt;

•increasing their vulnerability to general adverse economic and industry conditions, including increases in interest rates, particularly given their substantial indebtedness that bears interest at variable rates, as well as to catastrophic events; and

•limiting their ability to capitalize on business opportunities.

Under the terms of the agreements and indentures governing their respective indebtedness, PG&E Corporation and the Utility are permitted to incur additional indebtedness, some of which could be secured (subject to compliance with certain tests) and which could further accentuate these risks. As a result of the high level of indebtedness, PG&E Corporation and the Utility may be unable to generate sufficient cash through operations to service such debt, and may need to refinance such indebtedness at or prior to maturity and be unable to obtain financing on suitable terms or at all, any of which could have a material adverse effect on PG&E Corporation’s and the Utility’s business, financial condition and results of operations.

Parties have appealed the Confirmation Order.

Following entry of the Confirmation Order confirming the Plan, certain parties filed notices of appeal with respect to the Confirmation Order. There can be no assurance that any such appeal will not be successful and, if successful, that any such appeal would not have a material adverse effect on PG&E Corporation and the Utility.

PG&E Corporation may be required to issue shares with respect to HoldCo Rescission or Damage Claims, which would result in dilution to holders of PG&E Corporation common stock.

On the Effective Date, PG&E Corporation issued to the Fire Victim Trust a number of shares of common stock equal to 22.19% of the outstanding common stock on such date. As further described in “Satisfaction of HoldCo Rescission or Damage Claims and Subordinated Debt Claims” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Item 1, PG&E Corporation may be required to issue shares of its common stock in respect of allowed HoldCo Rescission or Damage Claims. If such issuance is required, it may be determined that, under the Plan, the Fire Victim Trust should receive additional shares of PG&E Corporation common stock such that it would have owned 22.19% of the outstanding common stock of reorganized PG&E Corporation on the Effective Date, assuming that such issuance of shares in respect of the HoldCo Rescission or Damage Claims had occurred on the Effective Date. Any such issuances will result in dilution to anyone who holds shares of PG&E Corporation common stock prior to such issuance and may cause the trading price of PG&E Corporation shares to decline.

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Any substantial sale of stock by existing stockholders could depress the market value of PG&E Corporation’s common stock, thereby devaluing the market price and causing investors to risk losing all or part of their investment.

Certain existing stockholders, including the Fire Victim Trust, the investors party to the Investment Agreement and the Backstop Parties, hold a large number of the outstanding shares of PG&E Corporation. PG&E Corporation can make no prediction as to the effect, if any, that sales of shares, or the availability of shares for future sale, will have on the prevailing market price of shares of PG&E Corporation common stock. Sales of substantial amounts of shares common stock in the public market, or the perception that such sales could occur, could depress prevailing market prices for such shares. Such sales may also make it more difficult for PG&E Corporation to sell equity securities or equity-linked securities in the future at a time and price which it deems appropriate.

The ability of PG&E Corporation to use some or all of its net operating loss carryforwards and other tax attributes to offset future income may be limited.

As of December 31, 2019, PG&E Corporation had net operating loss carryforwards for PG&E Corporation’s consolidated group for U.S. federal and California income tax purposes of approximately $5.9 billion and $1.9 billion, respectively, and PG&E Corporation incurred and will incur in connection with the Plan significant net operating loss carryforwards and other tax attributes. The ability of PG&E Corporation to use some or all of these net operating loss carryforwards and certain other tax attributes may be subject to certain limitations. Under Section 382 of the Internal Revenue Code (which also applies for California state income tax purposes), if a corporation (or a consolidated group) undergoes an “ownership change,” such net operating loss carryforwards and other tax attributes may be subject to certain limitations. In general, an ownership change occurs if the aggregate stock ownership of certain shareholders (generally 5% shareholders, applying certain look-through and aggregation rules) increases by more than 50% over such shareholders’ lowest percentage ownership during the testing period (generally three years). Losses incurred in the same taxable year as an ownership change generally can be pro-rated between the pre- and post-change portions of the taxable year, even if a disproportionate amount of such losses were actually incurred on or prior to the date of the ownership change. Only the portion of such losses allocated to the pre-change portion of the year would be subject to the annual limitation.

As of the date of this report, PG&E Corporation does not believe that it has undergone an ownership change and its net operating loss carryforwards and other tax attributes are not limited by Section 382 of the Internal Revenue Code. However, whether PG&E Corporation underwent or will undergo an ownership change as a result of the transactions in PG&E Corporation’s equity that occurred pursuant to the Plan depends on several factors outside PG&E Corporation’s control and the application of certain laws that are uncertain in several respects. Accordingly, there can be no assurance that the IRS would not successfully assert that PG&E Corporation has undergone or will undergo an ownership change pursuant to the Plan. In addition, even if these transactions did not cause an ownership change, they may increase the likelihood that PG&E Corporation may undergo an ownership change in the future. If the IRS successfully asserts that PG&E Corporation did undergo, or PG&E Corporation otherwise does undergo, an ownership change, the limitation on its net operating loss carryforwards and other tax attributes under Section 382 of the Internal Revenue Code could be material to its operations.

In particular, limitations imposed on PG&E Corporation’s ability to utilize net operating loss carryforwards or other tax attributes could cause U.S. federal and California income taxes to be paid earlier than would be paid if such limitations were not in effect and could cause such net operating loss carryforwards or other tax attributes to expire unused, in each case reducing or eliminating the benefit of such net operating loss carryforwards and other tax attributes. Specifically, PG&E Corporation’s ability to utilize its net operating loss carryforwards is critical to a successful rate-neutral securitization transaction after the Effective Date, the proceeds of which are expected to be used to satisfy PG&E Corporation’s and the Utility’s obligations to the Fire Victim Trust, and to PG&E Corporation’s and the Utility’s commitment to make certain operating and capital expenditures. Failure to consummate a securitization transaction or obtain alternative sources of capital could have a material adverse effect on PG&E Corporation and the Utility and the value of PG&E Corporation common stock.

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The ability of PG&E Corporation to pay dividends on shares of PG&E Corporation common stock is subject to restrictions.

In response to concerns raised by California governor Gavin Newsom, PG&E Corporation and the Utility filed the Case Resolution Contingency Process Motion with the Bankruptcy Court setting forth certain commitments in connection with the confirmation process and implementation of the Plan, including, among other things, limitations on the ability of PG&E Corporation to pay dividends on shares of its common stock (the “Dividend Restriction”). The Dividend Restriction provides that PG&E Corporation may not pay dividends on shares of its common stock until it recognizes $6.2 billion in Non-GAAP Core Earnings following the Effective Date. “Non-GAAP Core Earnings” means GAAP earnings adjusted for certain non-core items. Additionally, the ruling of the court overseeing the Utility’s probation dated April 3, 2019 places further restrictions on the ability of PG&E Corporation and the Utility to issue dividends. Under the ruling, no dividends may be issued until the Utility is fully in compliance with all applicable laws concerning vegetation management and clearance requirements, as well as the vegetation management and enhanced vegetation management targets and metrics in the Utility’s wildfire mitigation plan.

Subject to the foregoing restrictions, any decision to declare and pay dividends in the future will be made at the discretion of the Board of Directors and will depend on, among other things, PG&E Corporation’s results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Board of Directors may deem relevant. Certain of the Utility’s debt instruments contain covenants that restrict the ability of the Utility to pay dividends to PG&E Corporation.

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

On the Effective Date, PG&E Corporation made an equity contribution of $12.9 billion in cash, along with the Fire Victim Trust Shares, to the Utility, which used the funds to satisfy and discharge certain liabilities of PG&E Corporation and the Utility under the Plan and transferred the Fire Victim Trust Shares to the Fire Victim Trust. PG&E Corporation’s cash equity contribution was funded by proceeds from the financing transactions. This equity issuance to the Utility by PG&E Corporation was exempt from registration pursuant to Section 4(a)(2) of the Securities Act.

On June 7, 2020, PG&E Corporation entered into an Investment Agreement as described in Note 6 of the Notes to the Condensed Consolidated Financial Statements in Item 1. Pursuant to the terms of the Investment Agreement, on the Effective Date, PG&E Corporation issued 342.1 million shares of common stock to the Investors. This issuance and sale were exempt from registration pursuant to Section 4(a)(2) of the Securities Act. The Investors represented to PG&E Corporation that they were “accredited investors” as defined in Rule 501 under the Securities Act and that the common stock was being acquired for investment purposes and not with a view to, or for sale in connection with, any distribution thereof, and acknowledged that the common stock acquired in connection with the Investment Agreement, or any transaction statement evidencing ownership of such common stock, would bear a restrictive legend until such shares were registered on a shelf registration statement pursuant to the Investment Agreement.

On June 19, 2020, PG&E Corporation entered into the Forward Stock Purchase Agreements with the Backstop Parties as described in Note 2 and Note 6 of the Notes to the Condensed Consolidated Financial Statements in Item 1. The Forward Stock Purchase Agreement required PG&E Corporation to issue a number of shares of common stock equal to the unredeemed portion of such Backstop Party’s Greenshoe Backstop Purchase Amount divided by the Settlement Price (such shares of common stock, each Backstop Party’s “Greenshoe Backstop Shares”) to the Backstop Parties subject to the terms and conditions thereof. On August 3, 2020, PG&E Corporation redeemed $120.5 million of the Forward Stock Purchase Agreements as a result of the exercise by the underwriters of their option to purchase Equity Units pursuant to the Equity Units Underwriting Agreement. On August 3 2020, PG&E Corporation delivered 42.3 million shares of PG&E Corporation common stock to the Backstop Parties to settle the portion of the Forward Stock Purchase Agreements that had not been redeemed. This issuance and sale was exempt from registration pursuant to Section 4(a)(2) of the Securities Act. The Backstop Parties represented to PG&E Corporation that they are “accredited investors” and that the Greenshoe Backstop Shares are being acquired for investment purposes and not with a view to, or for sale in connection with, any distribution thereof, and the Greenshoe Backstop Shares acquired in connection with the Forward Stock Purchase Agreements, or any transaction statement evidencing ownership of such shares, held an appropriate restrictive legend until such shares were registered on a shelf registration statement pursuant to the Forward Stock Purchase Agreements.

Also, pursuant to the Forward Stock Purchase Agreement, PG&E Corporation agreed to issue the Additional Backstop Premium shares as described in Note 2 of the Notes to the Condensed Consolidated Financial Statements in Item 1. Pursuant to the terms of the Forward Stock Purchase Agreements and the Backstop Commitment Letters, on the Effective Date, PG&E Corporation issued to the Backstop Parties 169.0 million shares of common stock. This issuance and sale were exempt from registration under the Securities Act pursuant to Section 1145 of the Bankruptcy Code, as approved by the Bankruptcy Court in the Confirmation Order dated June 20, 2020.

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On the Effective Date, pursuant to the Plan, the Utility entered into an assignment agreement with the Fire Victim Trust, pursuant to which the Utility agreed to transfer to the Fire Victim Trust on the Effective Date 477.0 million shares (such shares, the “Fire Victim Trust Shares”) of common stock of PG&E Corporation, no par value. The transfer of shares of common stock to the Fire Victim Trust was exempt from registration under the Securities Act pursuant to Section 1145 of the Bankruptcy Code, as approved by the Bankruptcy Court in the Confirmation Order dated June 20, 2020.

On August 3, 2020, PG&E Corporation made an equity contribution of 748,415 shares to the Utility which delivered such additional shares of common stock to the Fire Victim Trust pursuant to an anti-dilution provision in the assignment agreement with the Fire Victim Trust. This equity issuance to the Utility by PG&E Corporation was exempt from registration pursuant to Section 4(a)(2) of the Securities Act. The transfer of shares of common stock to the Fire Victim Trust was exempt from registration under the Securities Act pursuant to Section 1145 of the Bankruptcy Code, as approved by the Bankruptcy Court in the Confirmation Order dated June 20, 2020.

Issuer Purchases of Equity Securities

During the quarter ended September 30, 2020, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. PG&E Corporation does not have any preferred stock outstanding. During the quarter ended September 30, 2020, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

ITEM 5. OTHER INFORMATION

PG&E Corporation and the Utility currently expect to hold their 2021 joint annual meeting of shareholders (the “2021 Annual Meeting”) in the second quarter of 2021. Due to PG&E Corporation’s and the Utility’s Chapter 11 bankruptcy proceedings in 2020, the 2021 Annual Meeting will be PG&E Corporation’s and the Utility’s first annual meeting of shareholders since their 2019 joint annual meeting of shareholders held on June 21, 2019.

ITEM 6. EXHIBITS

EXHIBIT INDEX


2.1						Confirmation Order, dated June 20, 2020 (incorporated by reference to PG&E Corporation’s Form 8-K dated June 20, 2020 (File No. 1-12609), Exhibit 2.1)

3.1						Amended and Restated Articles of Incorporation of PG&E Corporation , effective as of May 29, 2002, as amended by the Amendment dated June 22, 2020 (incorporated by reference to PG&E Corporation’s Form 8 K dated June 20, 2020 (File No. 1-12609), Exhibit 3.1)

3.2						Certificate of Determination for PG&E Corporation Series A Preferred Stock , filed December 22, 2000 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)

3.3						Bylaws of PG&E Corporation , Amended and Restated as of June 22, 2020 (incorporated by reference to PG&E Corporation’s Form 8-K dated June 20, 2020 (File No. 1-12609), Exhibit 3.3)

3.4						Amended and Restated Articles of Incorporation of Pacific Gas and Electric Company , effective as of June 22, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 20, 2020 (File No. 1-2348), Exhibit 3.2)

3.5						Bylaws of Pacific Gas and Electric Company, Amended and Restated as of June 22, 2020 (incorporated by reference in Form 8-K dated June 20, 2020 (File No. 1-2348), Exhibit 3.4)

4.1						Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 4.1)

4.2						First Supplemental Indenture, dated as of June 19, 2020, relating to the Mortgage Bonds between Pacific Gas and Electric Company and the Trustee (including the form of Mortgage Bonds of each series) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 4.2)

4.3						Indenture, dated as of June 23, 2020, between PG&E Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-12609), Exhibit 4.1)

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4.4						First Supplemental Indenture, dated as of June 23, 2020, relating to the Notes among PG&E Corporation, the Trustee and JP Morgan Chase Bank N.A., as collateral agent (including the form of Notes for each series) (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-2609), Exhibit 4.2)

4.5						Escrow Deposit and Disbursement Agreement, dated as of June 23, 2020, by and among PG&E Corporation, The Bank of New York Mellon Trust Company, N.A., as escrow agent, and the Trustee (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-2609), Exhibit 4.3)

4.6						Calculation Agency Agreement, dated as June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A, as calculation agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 4.3)

4.7						Escrow Deposit and Disbursement Agreement, dated as of June 19, 2020, by and among Pacific Gas and Electric Company, The Bank of New York Mellon Trust Company, N.A., as escrow agent, and the Trustee (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 4.4)

4.8						Third Supplemental Indenture, dated as of July 1, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (including forms of the New Short-Term Bonds and the New Long-Term Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.1)

4.9						Fourth Supplemental Indenture, dated as of July 1, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (including forms of the Funded Debt Exchange Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.2)

4.10						Thirtieth Supplemental Indenture, dated as of July 1, 2020, to the Amended and Restated Indenture, dated as of April 22, 2005, between Pacific Gas and Electric Company and BOKF, N.A., as trustee (including forms of certain series of Reinstated Senior Notes) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.3)

4.11						First Supplemental Indenture, dated as of July 1, 2020, to the Indenture, dated as of November 29, 2017, between Pacific Gas and Electric Company and BOKF, N.A., as trustee (including forms of certain series of Reinstated Senior Notes) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.4)

4.12						Second Supplemental Indenture, dated as of July 1, 2020, to the Indenture, dated as of August 6, 2018, between Pacific Gas and Electric Company and BOKF, N.A., as trustee (including forms of certain series of Reinstated Senior Notes) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 2, 2020 (File No. 1-2348), Exhibit 4.5)

4.13						Second Supplemental Indenture, dated as of July 1, 2020, to the Indenture of Mortgage, dated as of June 19 , 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (including forms of the Senior Notes Collateral Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.6)

4.14						Fifth Supplemental Indenture, dated as of July 1, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (including forms of the Credit Agreement Collateral Bonds) (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 4.7)

4.15						Sixth Supplemental Indenture, dated as of August 1, 2020, to the Indenture of Mortgage, dated as of June 19, 2020, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee

4.16						Pledge Agreement, dated as of October 5, 2020, by and between Pacific Gas and Electric Company and MUFG (incorporated by reference to PG&E Corporation’s Form 8-K dated October 5, 2020 (File No. 1-12609), Exhibit 4.1)

10.1						Settlement Agreement , dated April 21, 2020 , by and among the TCC, PG&E Corporation, Pacific Gas and Electric Company, FEMA, the SBA, the Department of Agriculture, the Department of the Interior, the United States Department of Housing and Urban Development and the General Services Administration (incorporated by reference to PG&E Corporation’s Form 10-Q dated May 1, 2020 (File No. 1-12609), Exhibit 10.7)

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10.2		Settlement Agreement , dated April 21, 2020 , by and among the TCC, PG&E Corporation, Pacific Gas and Electric Company, Cal DDS, Cal DTSC, Cal Fire, Cal OES, Cal Parks, CSU, Caltrans and Cal Vet (incorporated by reference to PG&E Corporation’s Form 10-Q dated May 1, 2020 (File No. 1 12609), Exhibit 10.8)

10.3		Utility RCF Commitment Letter, dated May 26, 2020, by and among Pacific Gas and Electric Company, J.P. Morgan Chase Bank, N.A., and Citibank, N.A., as co-administrative agents, and the commitment party thereto (incorporated by reference to Pacific Gas and Electric Company’s Form 8 K dated May 26, 2020 (File No. 1-2348), Exhibit 10.1)

10.4		Utility Term Loan Commitment Letter, dated May 26, 2020, by and among Pacific Gas and Electric Company, J.P. Morgan Chase Bank, N.A., as administrative agent, and the commitment party thereto (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 26, 2020 (File No. 1-2348), Exhibit 10.2)

10.5		Corporation RCF Commitment Letter, dated May 26, 2020, by and among PG&E Corporation, J.P. Morgan Chase Bank, N.A., as administrative agent and collateral agent, and the commitment parties party thereto. (incorporated by reference to PG&E Corporation’s Form 8-K dated May 26, 2020 (File No. 1-12609), Exhibit 10.3)

10.6	*	Form of Consent Form (incorporated by reference to PG&E Corporation’s Form 8-K dated June 7, 2020 (File No. 1-12609), Exhibit 10.1)

10.7		Schedule Relating to Form of Consent Form (incorporated by reference to PG&E Corporation’s Form 8-K dated June 9, 2020 (File No. 1-12609), Exhibit 10.1)

10.8		Exhibit A to Consent Form– Form of Amended and Restated Chapter 11 Plan Backstop Commitment Letter (incorporated by reference to PG&E Corporation’s Form 8-K dated June 7, 2020 (File No. 1 12609), Exhibit 10.2)

10.9		Exhibit B to Consent Form – Redeemable Forward Stock Purchase Contract Term Sheet (incorporated by reference to PG&E Corporation’s Form 8-K dated June 7, 2020 (File No. 1-12609), Exhibit 10.2)

10.10		Investment Agreement among PG&E Corporation and the Investors listed in Schedule A thereto (incorporated by reference to PG&E Corporation’s Form 8-K dated June 7, 2020 (File No. 1-12609), Exhibit 10.4)

10.11	**	Agreement to Enter Into Lease and Purchase Option, dated June 5, 2020 , between Pacific Gas and Electric Company and TMG Bay Area Investments II, LLC (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 5, 2020 (File No. 1-2348), Exhibit 10.1)

10.12	**	Office Lease, dated as of October 23, 2020, by and between Pacific Gas and Electric Company and BA2 300 Lakeside LLC

10.13		Underwriting Agreement , dated June 16, 2020, by and among Pacific Gas and Electric Company, J.P. Morgan Securities LLC, Barclays Capital Inc., BofA Securities, Inc., Citigroup Global Markets and Goldman Sachs & Co. LLC (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 19, 2020 (File No. 1-2348), Exhibit 1.1)

10.14		Underwriting Agreement , dated June 18, 2020, by and among PG&E Corporation, J.P. Morgan Securities LLC, Barclays Capital Inc., BofA Securities, Inc., Citigroup Global Markets and Goldman Sachs & Co. LLC (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-2609), Exhibit 1.1)

10.15		Term Loan Agreement, dated June 23, 2020 , by and among Company, J.P. Morgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-12609), Exhibit 10.1)

10.16	***	Form of Forward Stock Purchase Agreement (incorporated by reference to PG&E Corporation’s Form 8-K dated June 19, 2020 (File No. 1-12609), Exhibit 10.1)

10.17		Underwriting Agreement , dated June 25, 2020, by and among PG&E Corporation, Goldman Sachs & Co., LLC and J.P. Morgan Securities, LLC, as representatives of the several underwriters named in Schedule I thereto, in respect of the Common Stock Offering (incorporated by reference to PG&E Corporation’s Form 8-K dated June 25, 2020 (File No. 1-12609), Exhibit 10.1)

10.18		Underwriting Agreement , dated June 25, 2020, by and among PG&E Corporation, Goldman Sachs & Co., LLC and J.P. Morgan Securities, LLC, as representatives of the several underwriters named in Schedule I thereto, in respect of the Equity Units Offering (incorporated by reference to PG&E Corporation’s Form 8-K dated June 25, 2020 (File No. 1-12609), Exhibit 10.2)

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10.19		Pledge Agreement, dated as of July 1, 2020, by and among PG&E Corporation, J.P. Morgan Chase Bank, N.A., as collateral agent, revolving administrative agent and term administrative agent, The Bank of New York Mellon Trust Company, N.A., and the secured representatives party thereto from time to time (incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020 (File No. 1-12609), Exhibit 4.8 )

10.20		Purchase Contract and Unit Agreement, dated July 1, 2020, between PG&E Corporation and The Bank of New York Mellon Trust Company, N.A., as purchase contract agent and attorney-in-fact for the holders from time to time as provided therein (incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020 (File No. 1-12609), Exhibit 4.9)

10.21		Custodial Agreement, dated July 1, 2020, between The Bank of New York Mellon Trust Company, N.A., as purchase contract agent and The Bank of New York Mellon Trust Company, N.A., as custodian (incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020 (File No. 1-12609), Exhibit 4.12)

10.22		Tax Benefits Payment Agreement, dated July 1, 2020, between PG&E Corporation and the Fire Victim Trust (incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020 (File No. 1-12609), Exhibit 10.1)

10.23		Registration Rights Agreement, dated July 1, 2020, between the Fire Victim Trust and PG&E Corporation (incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020 (File No. 1-12609), Exhibit 10.2)

10.24		Credit Agreement, dated as of July 1, 2020, by and among PG&E Corporation, the several lenders from time to time party thereto, J.P. Morgan Chase Bank, N.A., as administrative agent, and J.P. Morgan Chase Bank, N.A., as collateral agent (incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 10.3)

10.25		Term Loan Credit Agreement, dated as of July 1, 2020, by and among Pacific Gas and Electric Company, the several lenders from time to time party thereto and J.P. Morgan Chase Bank, N.A., as administrative agent (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 30, 2020 (File No. 1-2348), Exhibit 10.4)

10.26		Credit Agreement, dated as of July 1, 2020, by and among Pacific Gas and Electric Company, the several lenders from time to time party thereto, J.P. Morgan Chase Bank, N.A. and Citibank, N.A., as co-administrative agents, and Citibank, N.A., as designated agent (incorporated by reference to PG&E Corporation’s Form 8-K dated June 30, 2020 (File No. 1-12609), Exhibit 10.5)

10.27		Purchase and Sale Agreement , dated as of October 5, 2020, by and between PG&E AR Facility, LLC, as buyer, and Pacific Gas and Electric Company in its capacity as initial Servicer and in its capacity as Originator (incorporated by reference to PG&E Corporation’s Form 8-K dated October 5, 2020 (File No. 1-12609), Exhibit 10.1)

10.28		Receivables Financing Agreement, dated as of October 5, 2020, by and among PG&E AR Facility, LLC, as borrower, Pacific Gas and Electric Company, in its individual capacity and as initial Servicer, the Persons from time to time party thereto as Lenders and Group Agents and MUFG Bank, Ltd., as Administrative Agent on behalf of the Credit Parties (incorporated by reference to PG&E Corporation’s Form 8-K dated October 5, 2020 (File No. 1-12609), Exhibit 10.2)

10.29		Collection Account Intercreditor Agreement, dated as of October 5, 2020, by and among Pacific Gas and Electric Company, MUFG and each trustee, indenture trustee, lender administrative agent, collateral agent, purchaser or other party described in Exhibit A therein (incorporated by reference to PG&E Corporation’s Form 8-K dated October 5, 2020 (File No. 1-12609), Exhibit 10.3)

10.30		Amendment to the 2014 Long-Term Incentive Plan, effective as of July 1, 2020 (incorporated by reference to PG&E Corporation’s Form 8-K dated July 1, 2020 (File No. 1-12609), Exhibit 10.1)

10.31	*****	Restricted Stock Unit Award Agreement between PG&E Corporation and William L. Smith, dated August 3, 2020

10.32	*****	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and John Simon, dated August 14, 2020

10.33	*****	Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Jason Wells, dated August 14, 2020

10.34	*****	Performance Share Award Agreement between PG&E Corporation and James Welsch, dated March 2, 2020

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10.35	*****	Performance Share Award Agreement between PG&E Corporation and Michael Lewis, dated March 2, 2020

10.36	*****	Performance Share Award Agreement between PG&E Corporation and William L. Smith, dated August 3, 2020

10.37	*****	Performance Share Award Agreement PG&E Corporation and David Thomason, dated March 2, 2020

10.38	*****	Separation Agreement between Andy Vesey and Pacific Gas and Electric Company dated, September 21, 2020

10.39	*****	Separation Agreement between Pacific Gas and Electric Company and Janet Loduca, dated July 17, 2020 (last amended effective July 23, 2020)

10.40	*****	PG&E Corporation 2014 Long-Term Incentive Plan (as adopted effective May 12, 2014 and as last amended effective July 1, 2020)

10.41	*****	Form of Performance Share Award Agreement under the PG&E Corporation 2014 Long-Term Incentive Plan

10.42	*****	PG&E Corporation 2012 Officer Severance Policy, as amended effective as of September 24, 2020

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 Officer 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

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101.SC		XBRL Taxonomy Extension Schema Document

101.CA		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB		XBRL Taxonomy Extension Labels Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

101.DE		XBRL Taxonomy Extension Definition Linkbase Document

104		Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document

*The Form of Consent Form is substantially identical in all material respects to each Consent Form that is otherwise required to be filed as an exhibit, except as to the Backstop Party, the amount of such Backstop Party’s Backstop Commitment Amount (as defined in the Backstop Commitment Letter) and the amount of such Backstop Party’s Forward Contract Purchase Commitment (as defined in the Consent Form). In accordance with instruction no. 2 to Item 601 of Regulation S-K, the registrant has filed the form of such Consent Form, with a schedule dated as of June 9, 2020 identifying the Consent Forms omitted and setting forth the material details in which each Consent Form differs from the form that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any agreement so omitted.

**In accordance with Item 601(a)(5) of Regulation S-K, certain schedules (or similar attachments) to this exhibit have been omitted from this filing. Such omitted schedules (or similar attachments) include information relating to the Property. The registrants will provide a copy of any omitted schedule to the Securities and Exchange Commission or its staff upon request. In accordance with Item 601(b)(10)(iv) of Regulation S-K, certain provisions or terms of the Lease Agreement attached as an exhibit to the Agreement have been redacted. Such redacted information includes proprietary information about the Property. The registrants will provide an unredacted copy of the exhibit on a supplemental basis to the Securities and Exchange Commission or its staff upon request.

***The Form of Forward Stock Purchase Agreement is substantially identical in all material respects to each Forward Stock Purchase Agreement that is otherwise required to be filed as an exhibit, except as to the Purchaser (as defined in the Forward Stock Purchase Agreement), the amount of such Purchaser’s Greenshoe Backstop Purchase Amount and the amount of such Purchaser’s Additional Backstop Premium Shares. In accordance with instruction no. 2 to Item 601 of Regulation S-K, the registrant has filed the form of such Forward Stock Purchase Agreement, with a schedule identifying the Forward Stock

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Purchase Agreements omitted and setting forth the material details in which each Forward Stock Purchase Agreement differs from the form that was filed. The registrant acknowledges that the Securities and Exchange Commission may at any time in its discretion require filing of copies of any agreement so omitted.

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

*****Management contract or compensatory agreement.

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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/ CHRISTOPHER A. FOSTER
Christopher A. Foster Interim 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: October 29, 2020

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